As filed with the Securities and Exchange Commission on August 14, 2006

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

x REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

¨ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended             

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

¨ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report                     

For the transition period from              to             

Commission file number             

TRANSATLANTIC PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

Alberta, Canada

(Jurisdiction of incorporation or organization)

Suite 1840, 444 – 5^th Ave., SW, Calgary, Alberta T2P 2T8

(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act. None

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

Title of Class:

Common Stock Without Par Value

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

Indicate the number of outstanding shares of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report – 37,659,189 as of December 31, 2005.

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

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    ¨  Yes    ¨  No

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 Company 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨    Accelerated Filer  ¨    Non-accelerated Filer  x

Indicate by check mark which financial statement item the registrant has elected to follow.    Item 17  x    Item 18  ¨

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

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    ¨  Yes    ¨  No

TABLE OF CONTENTS

Part I.
Item 1.	Identity of Directors, Senior Management and Advisers	1
Item 2.	Offer Statistics and Expected Timetable	1
Item 3.	Key Information	1
Item 4.	Information on the Company	9
Item 4A.	Unresolved Staff Comments	25
Item 5.	Operating and Financial Review and Prospects	25
Item 6.	Directors, Senior Management and Employees	33
Item 7.	Major Shareholders and Related Party Transactions	38
Item 8.	Financial Information	39
Item 9.	The Offer and Listing	39
Item 10.	Additional Information	41
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 12.	Description of Securities Other than Equity Securities	52
Part II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	53
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	53
Item 15.	Controls and Procedures	53
Item 16.	[Reserved]	53
Item 16(A).	Audit Committee Financial Expert	53
Item 16(B).	Code of Ethics	53
Item 16(C).	Principal Accountant Fees and Services	53
Item 16(D).	Exemption from the Listing Standards for Audit Committees	53
Item 16(E).	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	53
Part III.
Item 17.	Financial Statements	53
Item 18.	Financial Statements	55
Item 19.	Exhibits	55

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PART I.

Item 1. Identity of Directors, Senior Management and Advisors

A.	Directors and Senior Management
	Name	Business Address	Functions
	Michael D. Winn	Suite 1840, 444 – 5th Ave., SW Calgary, Alberta T2P 2T8	Director
	Brian B. Bayley	Suite 1840, 444 – 5th Ave., SW Calgary, Alberta T2P 2T8	Director
	Alan C. Moon	Suite 1840, 444 – 5th Ave., SW Calgary, Alberta T2P 2T8	Director
	Scott C. Larsen	5910 N. Central Expressway, Suite 1755 Dallas, Texas 75206	President, Chief Executive Officer and Director
	Christopher H. Lloyd	5910 N. Central Expressway, Suite 1755 Dallas, Texas 75206	Chief Financial Officer
B.	Advisers
	Name	Business Address	Position
	Macleod Dixon LLP	3700 Cantera Tower 400 Third Avenue SW Calgary, Alberta T2P 4H2	Canadian legal counsel
	Jenkens & Gilchrist	1445 Ross Ave., Suite 3700 Dallas, Texas 75202	United States legal counsel
C.	Auditors
	Name	Business Address	Professional Body Membership
	KPMG LLP	Suite 2500, Bow Valley Square II 205 – 5th Ave., SW Calgary, Alberta T2P 4B9	Institute of Chartered Accountants of Alberta and the Canadian Institute of Chartered Accountants

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

A. Selected Financial Data

The selected consolidated financial data presented in the table below for the five fiscal years ended December 31, 2005 is derived from our consolidated financial statements and is denominated in U.S. dollars. Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in Canada. This data includes our accounts and our wholly-owned subsidiaries’ accounts. The following selected financial data is qualified by reference to, and should be read in conjunction with, our consolidated financial statements and related notes. We follow the full cost method of accounting for oil and gas operations.

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The selected financial data for the years ended December 31, 2005, 2004 and 2003 was derived from our financial statements, which have been audited by KPMG LLP, Chartered Accountants, as indicated in their audit report which is included elsewhere in this registration statement. The selected financial data for the years ended December 31, 2002 and 2001 was derived from our audited financial statements, which are not included in this registration statement. The selected financial data for the quarters ended March 31, 2006 and 2005 was derived from our interim financial statements, which are unaudited.

We have not declared any dividends since incorporation and do not anticipate that we will do so in the foreseeable future. Our present policy is to retain future earnings for use in our operations and the expansion of our business.

Selected Financial Data Presented According to Canadian GAAP

(In thousands of U.S. dollars, except per share data)

	Quarter Ended March 31, (unaudited)			Year Ended December 31,
	2006		2005	2005		2004		2003		2002	2001
Revenue	556		282	1,409		5,108		8,494		36,531	26,791
Net income (loss)	1,128		105	(3,773	)	(5,193	)	(584	)	5,957	(5,860	)
Net income (loss) per share basic and diluted	(0.03	)	0.00	(0.11	)	(0.17	)	(0.02	)	0.25	(0.30	)
Cash dividends per share	—		—	—		—		—		—	—
Weighted average shares (000’s)	37,663		32,146	33,023		30,908		23,831		23,803	18,430
Ending shares outstanding (000’s)	37,672		32,072	37,659		31,852		23,831		23,830	23,725
Total assets	17,207		15,907	18,927		16,048		12,391		14,504	7,301
Long term liabilities	570		159	556		155		132		—	—
Shareholders’ equity	14,822		14,864	15,936		14,713		11,672		12,099	6,126
Capital expenditures (net)	381		372	4,839		1,551		1,245		107	1,338

Selected Financial Data Presented According to U.S. GAAP

(In thousands of U.S. dollars, except per share data)

	Year Ended December 31,
	2005		2004		2003
Revenue	1,409		5,108		8,494
Net income (loss)	(3,722	)	(5,289	)	(726	)
Net income (loss) per share basic and diluted	(0.11	)	(0.17	)	(0.03	)
Cash dividends per share	—		—		—
Weighted average shares (000’s)	33,023		30,908		23,831
Ending shares outstanding (000’s)	37,659		31,852		23,831
Total assets	18,868		15,791		—
Long term liabilities	556		155		—
Shareholders	15,749		14,475		—
Capital expenditures (net)	4,839		1,551		—

B. Capitalization and Indebtedness

The following table sets forth our capitalization and indebtedness as at June 15, 2006 and is qualified by reference to, and should be read in conjunction with, our consolidated financial statements and related notes.

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Capitalization and Indebtedness

(In thousands of U.S. dollars)

(unaudited)

	June 15, 2006
Indebtedness
Accounts payable and accrued liabilities	1,158
Settlement provision	961
Asset retirement obligations	582
Total Indebtedness	2,701
Shareholders’ equity
Share capital	20,644
Warrants	760
Contributed surplus	4,488
Deficit	(11,878)
Net shareholders’ equity	14,014

C. Reasons for the Offer and Use of Proceeds

Not Applicable

D. Risk Factors

This section describes some of the risks and uncertainties faced by us. The factors below should be considered in connection with any forward looking statements in this registration statement. The risk factors described below are considered to be the significant or material ones, but they are not the only risks faced by us.

Competition. The oil and gas industry is highly competitive. We experience competition in all aspects of our business, including searching for, developing and acquiring reserves, obtaining pipeline and processing capacity, leases, licenses and concessions, and obtaining the equipment and labor needed to conduct operations and market crude oil and natural gas. Our competitors include multinational energy companies, other independent crude oil and natural gas concerns and individual producers and operators. Many competitors have financial and other resources substantially greater than those available to us and, accordingly, may be better positioned to acquire and exploit prospects, hire personnel and market production. In addition, many of our larger competitors may be better able to respond to factors such as changes in worldwide crude oil and natural gas prices, levels of production, the cost and availability of alternative fuels or the application of government regulations. We expect a high degree of competition to continue.

Government Regulation and Environmental Matters. We are subject to various

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federal and state laws and regulations, including environmental laws and regulations in each jurisdiction in which we operate. We believe that we are in substantial compliance with such laws and regulations; however, such laws and regulations may change in the future in a manner that will increase the burden and cost of compliance. In addition, we could incur significant liability for damages, clean up costs and penalties in the event of certain discharges into the environment. Certain laws and governmental regulations may impose liability on us for personal injuries, clean-up costs, environmental damages and property damages, as well as administrative, civil and criminal penalties. Although we believe that cost of compliance with environmental regulations will not have a material adverse effect on our operations or earnings, risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities, including criminal penalties, will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages for injuries to property or persons resulting from our operations could result in substantial costs and liabilities. Some of the regulations that apply to us in the United States, where we have field operations, include the Resource Conservation and Recovery Act and comparable state statutes, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Occupational Safety and Health Act and comparable state statutes, the Oil Pollution Act 1990, the Water Pollution Control Act of 1972, the Safe Drinking Water Act and the Toxic Substances Control Act. We are unable to estimate the costs to be incurred for compliance with environmental laws over the next twelve months, however, management believes all such costs will be those ordinarily and customarily incurred in the development and production of oil and gas and that no unusual costs will be encountered.

Exploration and Production Regulations. Our operations in the United States are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used or obtained in connection with operations. Our operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units and the density of wells that may be drilled and the unitization or pooling of oil and gas properties. In addition, certain state conservation laws may establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and gas which can be produced from wells in which we hold interest and may limit the number of wells or the locations at which wells can be drilled. The extent of any impact on our operations of such restrictions cannot be predicted.

International Operations. We are actively pursuing oil and gas opportunities in several foreign countries. International crude oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes, sometimes frequent or material, in governmental energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, foreign exchange restrictions, currency fluctuations, royalty and tax increases, limits on allowable levels of production and other risks arising out of foreign governmental sovereignty over the areas in which our operations will be conducted, as well as risks of loss due to civil

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strife, terrorism, acts of war and insurrection. These risks may be higher in developing countries in which we may conduct such activities. Our international operations may also be adversely affected by laws and policies of Canada or the United States affecting foreign trade, taxation and investment. Consequently, our international exploration, development and production activities may be substantially affected by factors beyond our control, any of which could materially adversely affect our financial position or results of operations. Furthermore, in the event of a dispute arising from international operations, we may be subject to the exclusive jurisdiction of courts outside the United States or Canada or may not be successful in subjecting persons to the jurisdictions of the courts in the United States or Canada, which could adversely affect the outcome of such dispute.

Dependence on Key Personnel. We depend to a large extent on the services of Scott C. Larsen, our President and Chief Executive Officer, Dr. David Campbell, our International Exploration Manager and Dr. Weldon Beauchamp, our Consulting Geophysicist/Geologist. The loss of the services of any of these individuals could have a potential adverse effect on our operations. We have entered into an employment agreement with Mr. Larsen and a long-term consulting agreement with Dr. Campbell, and we maintain key man insurance on Mr. Larsen. We are negotiating a long-term consulting arrangement with Dr. Beauchamp.

Ability to Attract Competent Personnel. Recent commodity price increases have driven a substantial increase in oil and gas exploration activities worldwide, with a concurrent rise in demand for competent oil and gas professionals. We are a small company and must compete with larger, better capitalized companies for competent personnel.

Concentration of Producing Properties. Our crude oil and natural gas production is presently concentrated in two properties in the United States: the Bayou Couba property and the South Gillock property. We will be vulnerable to a disproportionate impact of delays or interruptions of production until we develop a more diversified production base. Once we have more producing properties, a disruption in one property will have less of an impact on our overall production. In addition, we are not the operator of the Bayou Couba property. As such, our plans, commitments and obligations are dependent on the operator’s plans and on how well the operator executes such plans.

Insurance and Uninsured Risk. Our business is subject to a number of risks and hazards, including the risk of fire, explosions, equipment failure, abnormally pressured formations, environmental hazards, industrial accidents, changes in the regulatory environment, labor disputes, the occurrence of any of which could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our insurance will not cover all the potential risks associated with an oil and gas company’s operations. We may also be unable to maintain insurance to cover these risks at economically feasible premiums. Insurance coverage may not be available or may not be adequate to cover any resulting liability. There are risks against which we cannot insure or against which we may elect not to insure. We, and the operators of our properties, maintain insurance in accordance with customary industry practices and in amounts that we believe to be reasonable. The occurrence of a significant event that is not fully insured could have a material adverse effect on our results of operation and our financial condition.

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Commodity Price Fluctuations. Our revenues and profitability are substantially dependent upon prevailing prices for crude oil, natural gas and natural gas liquids. For much of the past decade, the markets for crude oil and natural gas have been extremely volatile. These markets are expected to continue to be volatile in the foreseeable future. In general, future prices of crude oil, natural gas and natural gas liquids are dependent upon numerous external factors such as various economic, political and regulatory developments and competition from other sources of energy. The unsettled nature of the energy market and the unpredictability of worldwide political developments, including, for example, the Iraq war and the actions of the Organization of Petroleum Exporting Countries members, make it particularly difficult to estimate future prices of crude oil, natural gas and natural gas liquids.

Exploration Risks. Our results of operations are heavily dependent on how successful we are in the exploration for crude oil and natural gas. Exploration activities involve substantially more risk than development or exploitation activities. Exploratory drilling is a speculative activity. The use of three-dimensional seismic data and other advanced technologies may increase the probability of success of exploratory wells, and reduce the average finding costs through the elimination of prospects that might otherwise be drilled solely on the basis of two-dimensional seismic data and other traditional methods. Even when fully utilized and properly interpreted, three-dimensional seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not conclusively allow the interpreter to know if hydrocarbons will in fact be present, or present in economic quantities, in such structures. Failure of our exploration activities would have a material adverse effect on our results of operations and financial condition.

Operating Risks. The oil and gas industry involves a variety of operating risks, including the risk of fire, explosion, blowout, pipe failure, casing collapse, stuck tools, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, pipeline ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to us due to injury and loss of life, loss of or damage to well bores and/or drilling or production equipment, costs of overcoming downhole problems, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Gathering systems and processing facilities are subject to many of the same hazards and any significant problems related to those facilities could adversely affect our ability to market our production. Moreover, offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.

Shortage of Supplies and Equipment. Our ability to conduct operations in a timely and cost effective manner is subject to the availability of crude oil and natural gas field supplies, rigs, equipment and service crews. There presently exists a general tightening of supplies, equipment and personnel available to conduct operations in a timely manner. We anticipate this shortage of certain types of supplies and equipment will result in delays in our operations as well as in higher operating and capital costs.

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Drilling and Workover Plans Subject to Change. This registration statement includes descriptions of our future drilling and workover plans with respect to our prospects. A prospect is a property on which our geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of review. Whether or not we ultimately drill a prospect may depend on the following factors: receipt of additional seismic data or reprocessing of existing data; material changes in crude oil or natural gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; availability and cost of capital; changes in the estimates of costs to drill or complete wells; our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; decisions of our joint working interest owners and operators; and restrictions imposed by governmental agencies. Additionally, due to the significant amount of work done by prior operators on many of the existing wellbores in our older prospects, such as the South Gillock property, we may be subject to unanticipated delays and expenses during the course of any planned workover programs. We will continue to gather data about our prospects, and it is possible that additional information may cause us to alter our drilling and workover schedule or determine that a prospect should not be pursued at all.

Capital Requirements. We will be required to make substantial capital expenditures to develop reserves and to discover new crude oil and natural gas reserves. If our cash and cashflow from operating activities is insufficient to fund such additional expenditures, we may be required to sell equity, issue debt, sell properties or offer interests in the properties to be earned by another party or parties carrying out further exploration or development thereof. There can be no assurance that capital will be available to us from any source or that, if available, it will be at prices or on terms acceptable to us. Should sufficient capital not be available, the development and exploration of our properties could be delayed and, accordingly, the implementation of our business strategy would be adversely affected. If we are unable to meet our share of costs incurred under agreements to which we are a party, our interest in the properties subject to such agreements may be reduced.

Replacement of Reserves. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future success depends upon our ability to find, develop and/or acquire crude oil and natural gas reserves at prices that permit profitable operations. Except to the extent that we conduct successful development, exploitation or exploration activities or acquire properties containing proved reserves, our proved reserves will decline.

Estimates of Reserves and Related Data. Numerous uncertainties are inherent in estimating quantities of proved and other reserves of oil and gas and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data presented in this registration statement represents only estimates based on available geological, geophysical, production and engineering data, the extent, quality and reliability of which vary. Oil and gas reserve engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact manner, and estimates of other engineers might differ materially from those shown.

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Additional Capital Contributions and the Exercise of Existing Stock Options and Share Purchase Warrants Could Result in Dilution to Existing Shareholders. We do not know if we will be able to generate material revenue from oil and gas operations. Historically, the primary source of funds available to us has been through the sale of our equity securities. Any future additional equity financing could cause dilution to current stockholders. As of June 30, 2006 we had 3,257,250 share purchase warrants outstanding at an average exercise price of $1.04 per share. We have granted to some or all of our key employees, directors and consultants options to purchase common shares as non-cash incentives. As of June 30, 2006 we had 2,685,000 share purchase options outstanding at an average exercise price of $0.76 per share. If all of the share purchase warrants and share purchase options were exercised, the number of common shares issued and outstanding would increase from 37,936,939 (as of June 30, 2006) to 43,879,189. This represents an increase of 15.6% in the number of shares issued and outstanding and would result in significant dilution to current shareholders.

Limited and Volatile Trading Volume. Although our shares trade on the Toronto Stock Exchange, the volume of trading has been limited and volatile in the past and is likely to continue to be so in the future, making it difficult for investors to readily sell their shares in the open market. Without a liquid market for the our shares, investors may be unable to sell their shares at favorable times and prices and may be required to hold their shares in declining markets or to sell them at unfavorable prices. Our shares do not trade on an established market in the United States and we cannot make any assurances that our shares will ever trade in such a market, or if they do so trade, that a United States market for our shares will be sustained.

Volatility of Share Price. The market price of many resource companies, particularly resource exploration companies like us, have experienced wide fluctuations in price, resulting in substantial losses to investors who have sold their shares at a low price point. These fluctuations are based only in part on the level of progress of exploration, and can reflect general economic and market trends, world events or investor sentiment, and may sometimes bear no apparent relation to any objective factors or criteria. From January 1, 2006 through June 30, 2006, our price per share has fluctuated between a low of $0.82 and a high of $1.35. Significant fluctuation in our share price is likely to continue, and could potentially increase, in the future.

Dividend Policy. No dividends on our common shares have been paid to date. We currently plan to retain all future earnings and other cash resources, if any, for the future operation and development of our business. Payment of future dividends, if any, will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial condition, and current and anticipated cash needs.

Future Sales of Common Shares by Existing Shareholders. Sales of a large number of our common shares in the public markets, or the potential for such sales, could decrease the trading price of the common shares and could impair our ability to raise capital through future sales of common shares.

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Difficulty for U.S. Investors to Effect Service of Process. We are incorporated under the laws of the Province of Alberta, Canada. Consequently, it will be difficult for United States investors to effect service of process in the United States upon our directors or officers, or to realize in the United States upon judgments of United States’ courts predicated upon civil liabilities under the Exchange Act. Half of our directors are residents of Canada, and a significant portion of our assets are located outside of the United States. A judgment of a United States court predicated solely upon such civil liabilities would probably be enforceable in Canada by a Canadian court if the United States court in which the judgment was obtained had jurisdiction, as determined by the Canadian court, in the matter. There is substantial doubt whether an original action could be brought successfully in Canada against any of such persons or us predicated solely upon such civil liabilities.

Conflicts of Interest. There may be potential conflicts of interest for certain of our officers and directors who are or may become engaged from time to time in the crude oil and natural gas business on their own behalf or on behalf of other companies with which they may serve in the capacity as directors or officers. Certain of our independent directors are officers and/or directors of other publicly traded crude oil and natural gas exploration and production companies.

Title to Properties. Title to oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. Although the Company has no basis to believe that such will occur, there can be no assurance that our title to oil and gas properties may not be challenged through legal proceedings.

Item 4. Information on the Company

A. History and Development of the Company

Incorporation, Amalgamation and Name Change. Our predecessor corporation, Profco Resources Ltd. (“Profco”), was incorporated under the laws of British Columbia on October 1, 1985 and continued under the Business Corporations Act (Alberta) on June 10, 1997. We filed articles of amalgamation on January 1, 1999 under the Business Corporations Act (Alberta) in order to amalgamate with GHP Exploration Corporation, a corporation continued under the laws of Alberta from the Territory of Yukon. By articles of amendment effective December 2, 1998, Profco changed its name to TransAtlantic Petroleum Corp.

Contact Information. Our head office is located at Suite 1840, 444 — 5th Ave. SW., Calgary, Alberta, T2P 2T8. Our registered office is located at 3700, 400-3rd Ave. SW, Calgary, Alberta T2P 4H2. The telephone number at our head office is (403) 262-8556. Certain of our activities are conducted out of the office of our wholly owned subsidiary, TransAtlantic Petroleum (USA) Corp., located at Suite 1755, 5910 N. Central Expressway, Dallas, Texas, 75206. Our internet address is www.tapcor.com. Our contact person is Scott C. Larsen, President and Chief Executive Officer.

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Development of Our Business. We are in the business of exploring, developing and producing crude oil and natural gas properties. Until 2003, we concentrated our efforts on properties located onshore and offshore Africa. In 1993, we acquired a 30% interest in Oil Mining License 109 (“OML 109”), a 215,000 acre concession located offshore Nigeria. We successfully drilled a discovery well in 1994 and an appraisal well in 1995 in the Ejulebe field on OML 109, and contracted with a service provider to develop the field. Production began in September 1998, and the Ejulebe field has produced approximately 11 million bbls. of crude oil as of December 2005 (an estimated greater than 50% recovery of oil in place).

Following our participation in OML 109, we drilled several unsuccessful exploration wells offshore Benin and onshore Tunisia. We then attempted to exploit two onshore Egyptian oil and gas exploration blocks. In 2001, we sold our Egyptian properties, reduced our staff and consolidated all of our day-to-day operations. We focused on monetizing our interest in OML 109.

In June 2005, we sold the wholly-owned subsidiary in which we held our 30% interest in OML 109 to a third party. As a result of the transaction, in addition to cash consideration totaling $780,000 ($540,000 paid at closing and the balance after two new wells are drilled), we are entitled to net profits of up to a maximum of $16 million based on the success of future exploration and development on OML 109 by the new service contractor. As part of the transaction, $2.5 million from an abandonment fund was released to us and a portion of this amount ($1.76 million) was deposited into an escrow fund to address any potential liabilities and claims resulting from our operations in Nigeria over the past 10 years. The balance from the abandonment fund (approximately $730,000) was returned to us. The escrow fund now contains slightly less than $1 million. The new service contractor is committed to drilling two new wells on OML 109.

In 2005, we began to execute on a new strategy designed to (1) pursue prospects for crude oil and natural gas exploration and development in foreign countries which are under-explored and offer attractive fiscal terms, and (2) establish a base of low-risk production onshore United States.

Pursuing International Exploration and Development. In April 2005, we entered into an exclusive option with a Turkish company, Polmak Sondaj Sanayii A.S, to acquire a 50% interest in five exploration licenses that cover approximately 500,000 acres in southeastern Turkey. We reprocessed two-dimensional seismic data over these five prospects and analyzed other available data to evaluate their potential. Based on our evaluation of the prospect, we declined to exercise the option and abandoned the prospect.

In June 2005, we were awarded a reconnaissance license covering 3.4 million acres over the Guercif and Beni Znassen areas, onshore Morocco. The reconnaissance license provided exclusive rights for one year. We have now extended the reconnaissance license until December 2006. We have the right to convert portions of the reconnaissance license into exploration

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permit. We have reprocessed existing seismic data over the area, flown an aeromagnetic survey and conducted other studies to help define prospective areas. Stratic Energy Corporation participates with us in the reconnaissance license as a 40% partner.

In September 2005, we were awarded licenses covering six blocks in the U.K North Sea 23rd Seaward Licensing Round. The acreage is in an under-explored area of the North Sea, between the larger producing areas of the Southern Gas Basin and Central North Sea. The blocks were awarded to us under the “Promote License” initiative. We have a two-year period within which to conduct technical studies and acquire and reprocess seismic data on the licensed area. We can perpetuate the license by committing, prior to the end of the second year, to drill an exploratory well before the fourth anniversary of license.

In February 2006, we were awarded three production licenses in Romania: Izvoru Field, Vanatori Field and Marsa Field. The three licenses were among 24 licenses offered by the Romanian government in the 7th Licensing Round. The licenses were awarded to us based upon our commitment to certain work programs on each of the respective fields over the next 3 years. We will be the operator and 100% working interest owner of the fields. We expect final government approval of our work program by the end of 2006.

In May 2006, we were awarded the Tselfat permit covering 225,000 acres in northern Morocco. The Tselfat permit provides several opportunities including redevelopment of the existing fields, extensions of known productive horizons, and exploration of higher impact targets at depth. During the exploration phase of the permit, we will operate and bear 100% of the costs to earn a 75% ownership interest. We will carry the national oil company of Morocco, National des Hydrocarbures et des Mines (“ONHYM”), for 25% of the costs during the exploration phase, and then we and ONHYM will each pay our share of costs in the development phase.

In June 2006, we were awarded three blocks in southeastern Turkey. Two of the blocks applied for are adjacent to the producing Molla/Yasince oil fields. Detailed fieldwork and geochemical analyses will be required to confirm prospectivity on the third block, with the possibility of later seismic acquisition to define a drilling location, as there is no seismic data available on this block.

Establishing Production Onshore United States. In March 2003, we acquired a 10% interest in the Bayou Couba property, a salt dome located in Louisiana, and financed the drilling of four successful wells on the property. Since that time we have continued to participate in a number of wells in the Bayou Couba property.

In 2003, we began to acquire acreage positions in various prospects located in Oklahoma. We have taken leases on two prospects in Dewey County and McClain County, Oklahoma. We retain a 50% interest in both prospects and expect to drill one well in 2006.

In April 2005, we acquired the South Gillock property covering over 6,000 acres in Galveston County, Texas. The field has produced over 65 million barrels of oil to date. We believe there are remaining natural gas reserves in the gas cap of the

11

South Gillock property to be exploited. In July 2005, we began a workover program to rehabilitate production from existing wells; this program proved moderately unsuccessful. We expect to drill one well on the South Gillock property in 2006.

In January 2006, we acquired the Jarvis Dome property located in Anderson County, Texas. We believe there are crude oil and natural gas reserves in production zones bypassed by earlier drilling. We are currently completing a sidetrack of an existing well drilled into the Pecan Gap formation and expect to drill another well on the Jarvis Dome property in 2006.

Principal Capital Expenditures and Divestitures. The following table sets forth our principal capital expenditures and divestitures during Fiscal 2003, 2004 and 2005:

Principal Capital Expenditures and Divestitures

(In thousands of U.S. dollars)

Expenditure Type	2005		2004			2003
Property acquisition		3,892		—			—
Drilling (leasing, exploration and development)		947		1,694			1,409
Facilities and equipment		—		12			—
Divestiture of property and equipment		—		(155	)		(164	)
Total Capital Expenditures and Divestitures	$	4,839	$	1,551		$	1,245

B. Business Overview

Nature of Our Operations. Our principal business is acquiring, exploring and developing crude oil and natural gas properties. In the United States, we are currently acquiring, exploring or developing crude oil and natural gas properties located in Texas, Louisiana and Oklahoma. Internationally, we are acquiring, exploring or developing crude oil and natural gas properties in Morocco, Romania, Turkey and the North Sea. Additionally, we hold a net profits interest in a Nigerian offshore crude oil property. We intend to continue to pursue the acquisition of crude oil and natural gas properties and pursue strategic opportunities to buy or sell assets or otherwise contract with other companies in our industry.

Our success will depend on whether we are able to locate and successfully negotiate for crude oil and natural gas opportunities in countries which meet our criteria and then successfully develop and produce crude oil and natural gas in those countries. Our success will also depend on how well our prospects in the United States perform. All of our production is currently from properties located in the United States.

We plan to grow our operations by seeking opportunities in the 10 to 100 million Boe range in foreign countries where, because of attractive fiscal terms, that size discovery can have a significant impact on our financial condition and results of operations. In the United States, we

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will continue to acquire properties where we can exploit lower-risk missed pay, increased density and behind casing reserves by using modern technologies: three dimensional seismic data, cased hole logging, under balanced drilling, horizontal drilling and fracture stimulation.

Principal Markets. As at December 31, 2005, we operate in one reportable segment, the exploration for and the development and production of crude oil and natural gas. Identifiable assets, revenues and net loss in each of its geographic areas are as follows:

2005 (Thousands of U.S. Dollars)	Identifiable assets (liabilities)			Revenues		Loss
United States	$	11,094		$	1,398	$	2,922
Morocco		644			9		67
Corporate assets		7,189			945		784
	$	18,927		$	2,352	$	3,773
2004
United States	$	3,880		$	797	$	2,288
Canada		(134	)		389		2,367
Nigeria		198			4,364		538
Corporate assets		12,106			—		—
	$	16,048		$	5,549	$	5,193
2003
United States	$	4,203		$	1,037	$	787
Canada		1,044			247		(123	)
Nigeria		52			7,744		(81	)
Corporate assets		7,092			—		—
	$	12,391		$	9,028	$	584

Seasonality. Seasonality has no material effect on our financial condition or results of operations. However, our crude oil and natural gas exploration and development activities may be timed to meet seasonal conditions.

Marketing Channels. Crude oil production from South Gillock and Bayou Couba properties is sold under market sensitive or spot price contracts. Natural gas production is sold to purchasers under varying percentage-of-proceeds and percentage-of-index contracts or by direct marketing to end users or aggregators. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price paid to the purchaser for sales of residue gas and natural gas liquids recovered after gathering and processing the natural gas. The residue gas and natural gas liquids sold by these purchasers are sold primarily based on spot market prices. The revenue from the sale of natural gas liquids is included in natural gas sales.

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Material Effects of Governmental Regulations. Government regulations have a material effect on us to the extent that they require us to conduct field operations and hydrocarbon extraction activities according to prescribed environmentally-safe, sensitive regulations. Also, government regulations may restrict the commencement or re-commencement of field activities in certain properties in which we hold an interest for the purpose of exploration. Examples of types of governmental laws and regulations that may have a material effect on our business include:

• requirements to acquire permits before commencing drilling operations;

• requirements to restrict the substances that can be released into the environment in connection with drilling and production activities;

• limitations on, or prohibitions to, drilling in protected areas such as wildlife preserves; and

• requirements to mitigate and remediate the effects caused by drilling and production operations.

C. Organizational Structure

We conduct the majority of our business through subsidiaries incorporated outside of Canada. The following table presents the name, the percentage of voting securities owned and the jurisdiction of incorporation of our principal subsidiaries:

Subsidiary	Percent Owned	Jurisdiction of Incorporation
TransAtlantic Petroleum (USA) Corp.	100	Colorado
TransAtlantic Worldwide Ltd.	100	Bahamas

We own, directly or indirectly, 100% of four other subsidiary corporations, which on a consolidated basis constitute less than 10% of our assets and operating revenues.

D. Property, Plant and Equipment

Morocco. In May 2006, we were awarded the Tselfat exploration permit (the “Tselfat Permit”) covering 225,000 acres in northern Morocco. Tselfat Permit has two existing fields, Haricha and Tselfat, and one partial field, Bou Draa. The Haricha Field was discovered in the early 1950’s on a large surface anticline with hydrocarbon seeps. The field was developed with 30 wells drilled to a depth of less than 2,000 meters and produced approximately 3.5 million barrels of oil and 9.5 bcf of gas from porous Jurassic age sandstones. The field is a complex structural trap formed by a thrust fault that has not been fully exploited. Based on available two-dimensional seismic data, potential exists for a deeper sub-thrust play below the known productive horizon. The Tselfat field was discovered in 1918 by wells drilled on a surface anticline with hydrocarbon seeps. More than 90 shallow wells were drilled and produced less than 0.50 million barrels of oil recorded production from Jurassic carbonate reservoirs. The Bou Draa field was discovered in 1934 by wells drilled on hydrocarbon seeps. Over 140 shallow wells were drilled in a six square kilometer area and produced less than 1 million barrels recorded production of light oil from fractured carbonates and sandstones. Approximately 15%

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of these wells are located on our portion of the Bou Draa field. It is believed that hydrocarbon reserves can be recovered using horizontal drilling techniques, artificial stimulation and reservoir pressure maintenance. Potential exists in subthrust reservoirs in Jurassic age sandstones. We will commence a review of all the existing well data on the Tselfat Permit, reprocess much of the 2D seismic and initiate a field program. In addition, the Company will shoot a 3D survey over the Bou Draa and Haricha fields that will be followed by an exploratory well to test the previously untested Jurassic formations in the sub-thrust.

In June 2005, we were awarded a one-year reconnaissance license covering approximately 3.4 million acres in northeastern Morocco (the “Guercif-Beni Znassen License”). We operate and hold a 60% interest in the Guecif-Beni Znassen License, and Stratic Energy Corporation, with headquarters in Calgary, is a 40% partner in the project. The Guercif-Beni Znassen License provides us with exclusive rights over the area and is renewable for a second year or portion thereof. The Guercif-Beni Znassen License areas contain large structures and all the elements for oil and gas reserves: source rock, reservoir rock and traps. The initial year’s work program involves the reprocessing of 4,300 kilometers of two-dimensional seismic data and an aeromagnetic/aerogravity survey over the block. The work commitment is estimated to cost $1 million. We extended the reconnaissance license through December 2006.

Licensing Regime. The licensing process in Morocco for oil and gas concessions occurs in three stages: Reconnaissance License, Exploration Permit and then Exploitation Concession. Under a Reconnaissance License, the government grants exploration rights over an area for a one year term to conduct seismic and other exploratory activities (but not drilling). The size of the area may be very large and generally is unexplored or under-explored. The Reconnaissance License may be extended for up to one additional year. Interests under a Reconnaissance License are not transferable. The recipient of a Reconnaissance License commits to a work program and posts a bank guarantee in the amount of the estimated cost for the program. At the end of the term of the Reconnaissance License, the license holder must designate one or more areas for conversion to an Exploration Permit or relinquish all rights.

An Exploration Permit, which is codified in a Petroleum Agreement, is for a term of up to eight years and covers an area not to exceed 2,000 square kilometers. Under an Exploration Permit, exploration and appraisal studies and operations are undertaken in order to establish the existence of oil and gas in commercially exploitable quantities. This generally entails the drilling of exploration wells to establish the presence of oil and/or gas and such additional appraisal wells as may be necessary to determine the limits and the productive capacity of a hydrocarbon deposit to determine whether or not to go forward to develop and produce the prospect. The eight-year term under an Exploration Permit is divided into three separate time frames of two to three years each. A distinct work program is negotiated for each separate term, and the licensee then must post a bank guarantee to cover the cost of the agreed upon minimum work program for that term. The area of the exploration permit is reduced with each extension (area released is subject to negotiation). The ownership interests under an Exploration Permit are 75% to us and 25% to ONHYM, the Moroccan government agency that oversees the petroleum activities in Morocco. Interests under an Exploration Permit are transferable. However, 100% of the costs of all activities under an Exploration Permit are borne by us. We cannot hold rights, directly or indirectly, to more than 10,000 square kilometers under exploration permits.

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An Exploitation Concession is applied for upon the discovery of a commercially exploitable field. The area of the Exploration Concession corresponds to the area of the producing field. However, any number of Exploitation Concessions may be carved out of an Exploration Permit. The maximum duration of the Exploitation Concession is 25 years. Once an Exploitation Concession becomes effective, then the costs incurred for the development of the field are to be funded by the parties in proportion to their respective ownership interests (in this case, 75% by us and 25% by ONHYM). The oil company serves as operator. The oil company and ONHYM enter into an Association Contract to govern operations on the Exploration Concession. Interests under an Exploitation Concession are transferable.

Romania. In February 2006, we were awarded three production licenses onshore by the Romanian government in the 7^th Licensing Round. The three oil and gas fields, Izvoru Field, Vanatori Field and Marsa Field, each cover about 1,200 acres. They were discovered by the former national oil company, Petrom, and are all located within 60 miles of Bucharest, Romania. The licenses were awarded to us based upon our commitment to certain work programs on each of the respective fields over the next three years. We will be the operator and 100% working interest owner of the fields. All three fields previously produced oil, gas or both but were not fully developed. Discovered in 1968, the Izvoru Field produced 1.35 million barrels of oil from 26 wells. Completion difficulties and sand production resulted in limited flow rates and recoveries and led to premature field abandonment in 1998. Izvoru is a stratigraphic play and produces from Sarmatian (Tertiary age) shallow marine sandstones. Additionally, there is deeper potential in Cretaceous Albian age limestones which are productive in adjacent fields and were penetrated by four wells in the Izvoru field but not developed. The initial work program will be to re-start production. We plan to re-enter up to nine wells and shoot a 25 square kilometer three-dimensional seismic survey and drill a new well thereafter. The other two fields, Vanatori and Marsa, were both discovered in the 1970’s. Five wells were drilled in the Vanatori Field, two of which produced a total of 1.3 Bcf over six years from the Sarmatian formation. There is also deeper Cretaceous potential in the field. The Vanatori Field was prematurely abandoned due to sand production and water invasion. We plan to shoot a two-dimensional seismic survey and, provided this confirms the prospect, drill a new well. In the Marsa Field, five wells were drilled of which three were productive. Between 1974 and 1983, these wells produced a cumulative 0.3 Bcf from the Meotian (Tertiary age) reservoir. We will shoot a two-dimensional seismic survey over the field and, provided this confirms the prospect, drill a new well. Romania has a developed infrastructure for oil and gas and all production is sold at or near world market prices. There is ready availability of drilling rigs and a technically competent workforce.

Licensing Regime. The National Agency for Mineral Resources (“NAMR”) was set up in 1993 to administer the petroleum industry and represent the state in dealings with oil companies. When licenses are to be made available, NAMR publishes a list of available blocks for concession in the Official Gazette. Foreign and Romanian companies must register their interest by a specified date and must submit applications by an application deadline. Applicants are required to prove their financial capacity, technical expertise and other requirements as stipulated in the tender call. The licensing rounds are competitive and the winning bid is based

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on a scoring system. NAMR negotiates the terms of agreements granting the licenses with the winning licensee and the license agreement is then submitted to the government for its approval. The date of government approval is the effective date of the license. Blocks which fail to attract a prescribed level of bids are re-offered in a subsequent licensing round. NAMR may issue a prospecting permit or a petroleum concession. A prospecting permit is for the conduct of geological mapping, magnetometry, gravimetry, seismology, geochemistry, remote sensing and drilling of wildcat wells in order to determine the general geological conditions favouring petroleum accumulations. A petroleum concession provides exclusive rights to conduct petroleum exploration and production under a petroleum agreement.

UK North Sea. In September 2005, we were awarded two 23^rd Round Promote Licenses, P.1325 and P.1326, covering a total of six offshore blocks (covering 1200 sq. km) in the Auk Basin 150 kilometers east of the Scottish mainland. These blocks are in shallow water and contain a sub-salt Permian gas prospect at moderate depth with significant reserve potential. The prospect is defined by well and seismic control. The official award of these licenses to us occurred in December 2005. Over the next two years, we will purchase and reprocess available seismic data and conduct other geological and geophysical studies to evaluate the licenses. We plan to invite participation in the prospect by other companies and will likely farmout working interests in the prospect. Any company farming into the licenses would need to demonstrate its qualifications as an operator to the Department of Trade and Industry (the “DTI”) by showing it has sufficient technical, environmental and financial capacity to execute an offshore work program. Once a commitment to drill a well on the license has been made, the term of the license can be extended into years 3 and 4.

Licensing Regime. In 2003 in order to counteract the decrease in exploration expenditures, the DTI undertook substantial reforms of its licensing system and introduced the concept of the “Promote License.” Promote Licenses are specifically designed to attract smaller exploration companies to the UK North Sea. Smaller companies are seen as offering more innovative exploration ideas relevant to a maturing basin. The general concept of the Promote License is that the licensee will be given two years after award to attract the technical, environmental and financial capacity to complete a firm agreed work program. This means that sometime in the third or fourth year of the license, a well must be drilled. The rental costs for a Promote License are one tenth that of a traditional license for the first two years. Accordingly, a license will expire after two years if the licensee has not made a firm commitment to the DTI to complete a work program that includes the drilling of a well. At the same time, the licensee must also satisfy the DTI of its technical, environmental and financial capacity to carry out the work program. In effect, under a Promote License, the DTI defers its normal financial, technical and environmental requirements for the initial two years of the license.

Turkey. In June 2006, we were awarded three blocks in southeastern Turkey. Two of the blocks applied for are adjacent to the producing Molla/Yasince oil fields. Our focus is on a deeper under-explored Palaeozoic play in the area. Palaeozoic reservoirs are present at various depths over most of the region. The presence of suitably timed structural traps and sealing lithologies are the main controls on this play. The third block is closer to the Iraq border near the town of Cizre. Surface oil seeps indicate the existence of an active petroleum system in this area. We are focused on deeper sub-thrust plays in this area similar to those found in the major

17

Iraqi and Iranian Zagros fields further south. The presence of a suitably timed structural trap and sealing lithologies are the main controls on this play. Detailed fieldwork and geochemical analyses will be required to confirm prospectivity with the possibility of later seismic acquisition to define a drilling location as there is no seismic data available on this block.

Licensing Regime. The licensing process in Turkey for oil and gas concessions occurs in three stages: Permit, License and Lease. Under a Permit, the government grants the non-exclusive right to conduct a geological investigation over an area. The size of the area and the term of the Permit are subject to the discretion of the General Directorate of Petroleum Affairs (“GDPA”), the agency responsible for the regulation of oil and gas activities under the Ministry of Energy and Natural Resources. A License grants exclusive rights over an area for the exploration for petroleum. A License has a term of four years and requires drilling activities in the third year, but this obligation may be deferred into a future year by posting a guaranty. The License may be extended for up to two two-year extensions. No single company may own more than eight licenses within a district. The national oil company, TPAO, has the first right to acquire licenses in preference to private companies. Rentals are due annually based on the hectares under license. Once a discovery is made, the license holder applies to convert the area, not to exceed 25,000 hectares, to a Lease. Under a Lease, the lessee may produce oil and gas. The term of a lease is 20 years. Annual rentals are due based on the hectares under lease.

Nigeria. We originally acquired our interest in the OML 109 offshore Nigerian concession in 1992. OML 109 is an oil mining license located approximately 15 kilometers offshore in water depths between 15 and 60 metres. We drilled the discovery well and the first appraisal well in the Ejulebe Field on OML 109 in 1994 and 1995. We then entered into a risk service contract with a third party, who drilled development wells, installed a production platform and pipeline and put the Ejulebe field into production in 1998. The Ejulebe field has produced about 11 million barrels, or about 50%, of the estimated 22 million barrels in place through 2005.

In June 2005, we sold our 30% interest in OML 109. As part of the transaction, we will receive deferred payments of up to a maximum of $16 million based on the success of the future exploration and development on the concession. We agreed to pay a bonus equivalent to 3.87% of the deferred payments, if and when received, up to a maximum of $600,000, to Scott C. Larsen, our President, for his efforts in completing this transaction.

As part of this complex multi-party transaction, a new service contractor replaced our former service contractor on OML 109 and committed to drill at least two new wells in adjacent fault blocks near the currently producing Ejulebe Field. An affiliate of the new service contractor purchased the existing Ejulebe production platform and facilities and relieved us of all

18

abandonment liabilities. If the drilling is successful, it is anticipated these new wells will be put into immediate production through the existing Ejulebe facilities. Drilling has commenced and is in progress.

Nigerian Tax Claims. In conjunction with the sale of our Nigerian assets, we deposited $1.76 million into an escrow fund to address any Nigerian tax liabilities and claims relating to our operations in Nigeria for the years 1998 to 2005. At the time of the sale, the previously recorded reserve of $855,000 was increased to $1.76 million (the amount deposited into escrow), and the charge for the increase to the reserve was included in earnings. In the third quarter 2005, agreement was reached and tax returns filed with respect to years 1998 through 2001, and $226,000 was withdrawn from the escrow account to pay all remaining Nigerian tax liabilities for that period. In the first quarter 2006, Nigerian tax returns for years 2002, 2003 and 2004 were filed and an additional $550,000 was withdrawn from the escrow to pay the estimated tax due for those years. As of June 2006, there remains slightly less than $1 million in the escrow account. The tax returns for years 2002 through 2004 still must undergo review by the Nigerian Federal Inland Revenue Service, and we remain responsible for taxes up to the sale date in June 2005. We believe the escrow fund provides adequate provision for the liabilities related to our Nigerian activities.

South Gillock. In April 2005, we acquired the South Gillock and State Kohfeldt Units covering over 6,000 acres in Galveston County, Texas. The field began producing in the 1940’s, and the two units combined have produced over 65 million barrels of oil from the Big Gas Sand of the Frio formation. We believe there are remaining gas reserves in the gas cap of the South Gillock Unit, and its acquisition was premised on this concept. Since this acquisition, we have engaged in a workover program entering existing wells. This has increased production from 60 Boe/d at the time of the acquisition to about 119 Boe/d in June 2006. There are 61 wells on the units, of which three are producing and the remainder are temporarily abandoned. Subject to the timing of rig availability, in 2006 we will drill one new well to test the Big Gas Sand as well as deeper Frio formations below the Big Gas Sand. We are operator and own 100% of the working interest with a net revenue interest of 77%. The initial acquisition of the South Gillock and State Kohfeldt Units covered only the unitized Big Gas Sand formation. In November 2005, we completed a transaction for the shallow and deep leasehold rights from BP America Production Company. We have a two-year option on deep rights covering 2,731 acres over the northern portion of the South Gillock Unit and a 3 year term assignment over the same 2,731 acres for the shallow rights.

Bayou Couba. We acquired a 10% working interest in the Bayou Couba prospect in March 2003. We paid $200,000 for the interests in two leases covering 3,049 acres and advanced ANEC $1.8 million for ANEC’s initial drilling program as a $2 million production payment, which was repaid in October 2003. We also have the right to acquire a 10% interest in any property ANEC acquires in the 23.5 square mile area covered by a 3D seismic survey, including any property interests acquired through ANEC’s agreement with ExxonMobil Corp. The term of our agreement with ANEC is co-extensive with the Development Agreement that ANEC has with ExxonMobil Corp., which currently expires in November 2007. In March 2006, we announced plans to sell our 10% interest in the Bayou Couba prospect in Louisiana and the ANEC convertible debentures we hold to ANEC for $3.8 million, subject to ANEC securing financing; however, the transaction failed to close.

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Jarvis Dome. In January 2006, we acquired the Jarvis Dome prospect located in Anderson County, Texas, which included two wells and leases covering 170 acres. A leasing program is underway to acquire an additional 1,000 acres. We own 100% of the working interest in the prospect subject to a 20% back-in after payout in favor of the seller. The initial work program on Jarvis Dome has involved working over one of the existing wells and sidetracking the other existing well. We also plan to drill either one new vertical well on the prospect to test the Woodbine formation or one horizontal well to test the Pecan Gap formation. Completion of the sidetrack is still pending, and the workover was completed in July 2006, and the Woodbine test is anticipated to occur later this year.

Other. We have positions in two prospects in Dewey and McClain Counties, Oklahoma. In both prospects, we have a 50% partner in our leasehold position. A well on the McClain County prospect will test the Springer formation and is scheduled to be drilled in the third quarter 2006. We will have a twenty percent working interst in this well. Also in 2005, we participated for a 20% interest in two wells on a prospect in Panola County, Texas, but both wells were non-commercial.

Property and Equipment

(In thousands of U.S. dollars)

2005	Cost		Accumulated depreciation and depletion		Net book value
Crude oil and natural gas properties
United States	$	11,308	$	5,521	$	5,787
Furniture, fixtures and other assets		238		212		26
Balance, December 31, 2005	$	11,546	$	5,733	$	5,813
2004
Crude oil and natural gas properties
United States	$	4,890	$	4,199	$	691
Nigeria		14,436		14,436		—
Furniture, fixtures and other assets		381		368		14
Balance, December 31, 2004	$	19,707	$	19,003	$	704

Property acquisitions:

In April 2005, we completed the purchase of the South Gillock property located in Texas. We paid $3.0 million cash and issued 500,000 shares and 500,000 warrants exercisable at $1.00 per share on or before April 15, 2007 for the property. The fair value of the warrants was determined using a Black-Scholes pricing model. A purchase equation is provided below:

Consideration:
Cash	$	3,000,000
Common shares		350,000
Warrants		125,434
Acquisition costs		66,630
	$	3,542,064
Assets acquired:
Property and equipment	$	3,892,064
Asset retirement obligations		(350,000	)
	$	3,542,064

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Sale of subsidiary:

Effective June 2005, we sold our Bahamian subsidiary which owned 30% interest in certain properties offshore Nigeria. In consideration, we received $540,000 prior to disposal costs of $220,000 (including legal, consulting and other deal-related costs), a future contingent cash payment (after two new wells have been drilled) of $240,000, and contingent compensation of up to a maximum of $16 million. A bonus equivalent to 3.87% will be paid to Scott C. Larsen, our President, if and when this contingent compensation is received by us. No amount of contingent consideration has been recognized in our financial statements. We paid Mr. Larsen a bonus of $100,000 upon finalization of this transaction (included in general and administrative expense). Of the $2.5 million reserved at December 31, 2004 as an abandonment fund, $1.76 million was placed in escrow to address any Nigerian tax claims relating to our prior operations in Nigeria, with the balance of approximately $730,000 being released from the abandonment fund.

Estimated Reserves of Crude Oil and Natural Gas. As a Canadian issuer, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (NI 51-101) implemented by the members of the Canadian Securities Administrators in all of our reserves related disclosures. Under NI 51-101, proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. Reported proved reserves should target, under a specific set of economic conditions, at least a 90% probability that the quantities of oil and natural gas actually recovered will equal or exceed the estimated proved reserves.

In the United States, registrants, including foreign private issuers like us, are required to disclose proved reserves using the standards contained in Rule 4-10(a) of the United States Securities and Exchange Commission’s (“SEC”) Regulation S-X. Proved reserves estimated and reported below pursuant to NI 51-101 also meet the definition of estimated proved reserves required to be disclosed under Rule 4-10(a) of Regulation S-X.

The crude oil and natural gas industry commonly applies a conversion factor to production and estimated proved reserve volumes of natural gas in order to determine an “all commodity equivalency” referred to as barrels of oil equivalent (“boe”). The conversion factor we have applied in this registration statement is the current convention used by many oil and gas companies, where six thousand cubic feet (“mcf”) of natural gas is equal to one barrel (“bbl”) of

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oil. The boe conversion ratio we use is based on an energy equivalency conversion method primarily applicable at the burner tip. It may not represent a value equivalency at the wellhead and may be misleading, particularly if used in isolation.

The reserve data set out in the summary table below is based on Netherland, Sewell & Associates, Inc.’s independent engineering evaluation of the estimated proved crude oil and natural gas reserves pertaining to our properties as of December 31, 2005.

OIL AND GAS RESERVES

BASED ON CONSTANT PRICES AND COSTS⁽⁹⁾

	Light and Medium Oil		Natural Gas
	Gross(1) (MBBL)	Net(1) (MBBL)	Gross(1) (MMCF)	Net(1) (MMCF)
Proved Developed Producing(2)(6)
United States	39.3	31.1	1094.7	847.9
Total	39.3	31.1	1094.7	847.9
Proved Developed Non-Producing(2)(7)
United States	23.6	17.0	139.6	107.9
Total	23.6	17.0	139.6	107.9
Proved Undeveloped(2)(8)
United States	—	—	505.3	391.3
Total	—	—	505.3	391.3
Total Proved(2)
United States	62.9	48.0	1739.7	1347.1
Total	62.9	48.0	1739.7	1347.1

NET PRESENT VALUES OF FUTURE NET REVENUE

BASED ON CONSTANT PRICES AND COSTS⁽⁹⁾

	Before Deducting Income Taxes Discounted At		After Deducting Income Taxes Discounted At
	0% (M$)	10% (M$)	0% (M$)	10% (M$)
Proved Developed Producing(2)(6)
United States	6450.4	5259.0	6450.4	5259.0
Total	6450.4	5259.0	6450.4	5259.0
Proved Developed Non-Producing(2)(7)
United States	1209.2	1052.3	1209.2	1052.3
Total	1209.2	1052.3	1209.2	1052.3
Proved Undeveloped(2)(8)
United States	2142.7	1601.5	2142.7	1601.5
Total	2142.7	1601.5	2142.7	1601.5
Total Proved(2)
United States	9802.3	7912.8	9802.3	7912.8
Total	9802.3	7912.8	9802.3	7912.8

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TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

BASED ON CONSTANT PRICES AND COSTS⁽⁹⁾

	Revenue (M$)	Royalties (M$)	Operating Costs (M$)	Development Costs (M$)	Abandonmt and Reclamation Costs (M$)10	Future Net Revenue Before Income Taxes (M$)	Income Taxes (M$)	Future Net Revenue After Income Taxes (M$)
Total Proved(2)
United States	18186.0	4144.6	3697.0	542.1	—	9802.3	0	9802.3
Total	18186.0	4144.6	3697.0	542.1	—	9802.3	0	9802.3

RECONCILIATION OF COMPANY NET

RESERVES BY PRINCIPAL PRODUCT TYPE

BASED ON CONSTANT PRICES AND COSTS ⁽⁹⁾

The following table sets forth a reconciliation of the changes in our light and medium crude oil, and associated and non-associated gas (combined) reserves as at December 31, 2004 against such reserves as at December 31, 2005 based on the price and cost assumptions set forth in note 9:

	Light and Medium Oil						Associated and Non-Associated Gas
	Net Proved (bbl)		Net Probable (bbl)		Net Proved Plus Probable (bbl)		Net Proved (mcf)		Net Probable (mcf)		Net Proved Plus Probable (mcf)
United States
At December 31, 2004	34,164		10,338		44,502		22,360		4,688		27,048
Sales/Production net of LOE, Taxes & Capital	(15,419	)	(4,494	)	(19,913	)	(6,547	)	(1,596	)	(8,143	)
Changes in Pricing & LOE Costs	1,181		7,699		8,880		(416	)	7,902		7,486
Extensions and Discoveries	4,883				4,883		1,429				1,429
Acquisition of Reserves	27,800		23,600		51,400		1,733,500				1,733,500
Revisions of Volumes	7,678		5,498		13,176		1,701		2,692		4,393
Accretion of Discount	2,580		(6,766	)	(4,186	)	(12,328	)	(11,431	)	(23,759	)
At December 31, 2005	62,867		35,875		98,742		1,739,669		2,255		1,741,954

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The following table sets forth changes between future net revenue estimates attributable to our net proved reserves as at December 31, 2005 against such reserves as at December 31, 2004.

RECONCILIATION OF CHANGES IN NET PRESENT VALUES

OF FUTURE NET REVENUE DISCOUNTED AT 10%

BASED ON CONSTANT PRICES AND COSTS ⁽⁹⁾

	2005 ($)
United States
Estimated Future Net Revenue at December 31, 2004	521,000
Sales/Production net of LOE, Taxes & Capital	(308,400	)
Changes in Capital	1,200
Changes in Pricing & LOE Costs	124,200
Extensions and Discoveries	354,700
Acquisition of Reserves	7,183,300
Revisions of Volumes	29,100
Accretion of Discount	7,700
Estimated Future Net Revenue at December 31, 2005	7,912,800

Notes:

(1) “Gross Reserves” are our working interest (operating or non-operating) share before deducting of royalties and without including our royalty interests. “Net Reserves” are our working interest (operating or non-operating) share after deduction of royalty obligations, plus our royalty interests in reserves.

(2) “Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(3) “Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

(4) “Possible” reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

(5) “Developed” reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

(6) “Developed Producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(7) “Developed Non-Producing” reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

(8) “Undeveloped” reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

(9) The product prices used in the constant price and cost evaluations in the Netherland Sewell Report were as follows: At December 31, 2005 for the United States $57.75 per barrel and $10.08 per MMBTU, both prices being adjusted for energy content, processing fees and a regional price differential. Lease and well operating costs were based on the actual costs provided by the operator.

(10) With respect to its South Gillock prospect, as 100% operator we are responsible for all future abandonment and reclamation costs. We have taken the total number of wells in which we own in the prospect (59) and, using the third party estimated costs, have estimated the undiscounted cost (net of salvage value) to be $629,000 and the cost discounted at 10% to be $350,000. We plan to begin plugging and abandoning certain wells at South Gillock beginning in 2007 and estimate plugging nine wells in both 2007 and 2008 at a total cost of $186,000. With respect to our Bayou Couba prospect, as non-operator, we have adopted the methodology and timing of the future abandonment and reclamation costs as set by the operator. We have taken the total number of wells in which we own an interest in the prospect (61) and using the operator’s estimated costs have estimated the undiscounted cost (net of salvage value) to be $328,000 and the cost discounted at 10% to be $163,000. The operator does not plan to commence abandonment for several years because of the potential for re-entry of the existing wells. No wells are planned to be plugged and abandoned at Bayou Couba in the next three years. Note that in computing the future net revenue for the proved reserves set out above, the discounted abandonment estimate has not been deducted.

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The following table sets forth the number of wells in which we held a working interest as of December 31, 2005:

	Oil		Natural Gas
	Gross(1)	Net(1)	Gross(1)	Net(1)
Louisiana (onshore)
Producing	15	1.5	13	1.3
Non-producing(2)	33	3.3	—	—
Texas (onshore)
Producing	1	1	2	2
Non-producing(2)	56	56	—	—

(1) “Gross Wells” are the wells in which we hold a working interest (operating or non-operating). “Net Wells” are the Gross Wells multiplied by our working interest percentage (operating or non-operating).

(2) All non-producing wells are presented as oil wells.

The following table sets out our undeveloped land position effective December 31, 2005:

	Undeveloped
	Gross(1)	Net(2)
United States	5,141	3,936
Total	5,141	3,936

(1) “Gross” means the total number of acres in which we have a working interest.

(2) “Net” means the sum of the products obtained by multiplying the number of gross acres by our percentage working interest therein.

Item 4A. Unresolved Staff Comments

Not applicable

Item 5. Operating and Financial Review and Prospects

In 2005, we began to execute on a new strategy designed to (1) pursue prospects for crude oil and natural gas exploration and development in foreign countries which are under-explored and offer attractive fiscal terms, and (2) establish a base of low-risk production onshore United States.

During 2005 and 2006, we successfully initiated operations in Morocco, Romania, Turkey and the UK North Sea. In each country, we are looking to combine higher risk/higher reward exploration prospects with near term production opportunities. In the U.S., we acquired a mature field in South Texas consistent with our focus on exploitation prospects and several other low risk prospects.

In June 2005, we sold our interests in Nigeria keeping a $16 million net profits interest. We raised $4 million in additional capital in October 2005 ($0.85 per unit consisting of one common share and one half of one common share purchase warrant with a whole warrant exercise price of $1.05 per share). We ended 2005 with a strong working capital position, which included cash and short term investments of $9 million.

Given the capital-intensive nature of oil and gas exploration as well as the uncertainty of economic success from our existing projects, we anticipate significant capital will likely be required to fund our existing and any additional projects.

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A. Operating Results

The following discussion for the three fiscal years ended December 31, 2005 and the comparative quarters ended March 31, 2006 and 2005 should be read in conjunction with our consolidated financial statements and notes thereto.

Summary. Consolidated revenues for the year ended December 31, 2005 of $2.4 million, represented a decrease of $3.1 million, or 59%, from the $5.5 million reported for 2004. The decrease in revenue is primarily due to our cessation of production of crude oil in Nigeria. The consolidated net loss for 2005 was $3.8 million or $0.11 loss per share (basic), compared to consolidated net loss of $5.2 million or $0.17 loss per share (basic) for 2004. Consolidated revenues for the year ended December 31, 2004 were $5.5 million, which represented a decrease of $3.5 million, or 39%, from the $9.0 million reported for 2003. The decrease in revenue is primarily due to decrease in production of crude oil in Nigeria. The consolidated net loss for 2003 was $584,000 or $0.02 loss per share (basic). Consolidated revenues for the quarter ended March 31, 2006 of $556,000, represented an increase of $274,000, or 97%, from the $282,000 reported for the same quarter 2005. The increase in revenue is primarily due to sales from South Gillock, which was acquired in April 2005. The consolidated net loss for the quarter ended March 31, 2006 was $1.1 million or $0.03 loss per share (basic), compared to consolidated net loss of $105,000 or $nil per share (basic) for the same quarter last year. The workover program at South Gillock and our international exploration efforts constituted the majority of the loss.

Cash used in operations in 2005 was $2.8 million compared to a use of $426,000 in 2004 and cash provided of $805,000 in 2003. We had 37,659,189 common shares outstanding at year end 2005, compared to 31,852,241 at year end 2004 and 23,830,882 at year end 2003 (post consolidation). Cash used in operations during the first quarter 2006 was $863,000 compared to cash provided of $71,000 in the first quarter 2005. We had 37,671,689 common shares outstanding at March 31, 2006, compared with 32,572,241 outstanding at March 31, 2005.

Revenue. We recognized net crude oil and natural gas sales of $1.4 million for 2005, representing 30,962 equivalent barrels ($45.22 per equivalent barrel) from field production in the U.S. This revenue represented a 76% increase from 2004 sales of $796,000 from production in the U.S. as a result of the South Gillock property acquisition and higher commodity prices.

We recognized crude oil and natural gas sales of $796,000 for 2004, representing 21,600 barrels ($36.83 per equivalent barrel) from Bayou Couba field production in the U.S., which represented a 6% decrease from 2003 sales of $843,000 as a result of normal production declines. Sales of crude oil in Nigeria for 2003 were $7.7 million, representing 268,000 barrels ($28.05 per equivalent barrel). From Nigeria, payments of $306,000 were received from our services contractor during 2004 and continued at a rate of approximately $25,000 per month through March 2005. Gross sales of crude oil in Nigeria for 2004 were $4.9 million, representing 240,118 barrels ($33.84 per equivalent barrel).

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In 2003, we participated in the Bayou Couba prospect through a production payment which accounted for a net profits income of $297,000 in 2003. The production payment was repaid in October 2003. There were 13 gross (1.8 net) wells productive at Bayou Couba and 4 wells productive at South Gillock during 2005. There were 11 gross (1.2 net) wells productive at Bayou Couba during 2004.

Interest income increased in 2005 as a result of increased cash on hand and our participation in certain investments during the year. Interest income increased in 2004 as a result of increased cash on hand resulting primarily from the common share offering during the year.

We recognized net crude oil and natural gas sales of $556,000 for the first quarter 2006, representing 11,373 equivalent barrels ($48.82 per equivalent barrel) from field production in the United States. This U.S. revenue represented a 169% increase from first quarter 2005 sales of $207,000 as a result of the South Gillock acquisition and higher commodity prices.

Operating Costs. Lease operating expenses for 2005 decreased 56% to $1.9 million due to the cessation of activities in Nigeria. This decrease was partially offset by increased lease operating expenses at South Gillock. Service fees and other production costs related to Nigeria were $4.1 million for 2004, a decrease of $2.4 million over the comparable period in 2003, primarily because the service fee is only charged when crude is sold, and there were no sales in the second half of 2004.

In June 2005, we were awarded a reconnaissance license covering approximately 3.4 million acres in northeastern Morocco. We have a 60% interest in the license. In conjunction with the award, we agreed to a work program involving the reprocessing of seismic data and other technical work. The work commitment during the one year tem of the license was estimated to cost us a total $600,000. During 2005, we spent approximately $200,000 of the forecasted total.

Depreciation, depletion and accretion (“DD&A”) related to U.S. production decreased 16% to $606,000 for 2005 and represented a DD&A rate per net equivalent barrel of $19.86, largely as a result of a larger reserve base and the impact of the South Gillock acquisition as well as an impairment of $1.2 million recorded in 2004 relating to a ceiling test associated with our U.S. cost center. DD&A related to U.S. production increased 128% to $702,538 for 2004 and represented a DD&A rate per net equivalent barrel of $32.50 as a result of a smaller reserve base and the impact of significant dry hole drilling costs ($1.2 million) incurred in 2004.

DD&A related to Nigeria property and equipment decreased to nil in 2004 since all capitalized costs related to Nigeria were fully depleted at December 31, 2003. With no reserves attributed to Nigeria at December 31, 2004, net property costs related to Nigeria were reduced to zero through depletion.

General and administrative costs of $2.3 million in 2005 increased 34% compared to 2004, primarily resulting from increased staff and consultants related to the support of the South Gillock purchase and expanded business development activities. Other costs included a foreign exchange loss of $29,000 and a write down of our investment in American Natural Energy

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Corporation common stock of $112,000. During the year, we incurred $410,000 of stock-based compensation expense related to an option grant to employees and directors. Finally, we paid $440,000 in costs related to international business development activities which include legal, technical and other professional fees incurred in conjunction the evaluation of our various foreign initiatives and the setup of branch offices in each of the five foreign countries in which we have operations.

General and administrative costs of $1.2 million in 2004 decreased 3% ($38,000) compared to 2003, primarily as a result of reductions in overhead expenses in 2004. Other costs in 2004 included: a $2.1 million write down of our investment in ANEC debentures; a $600,000 increase to our reserve for Nigerian tax liabilities; a foreign currency translation gain of $108,000 on related party investments denominated in Canadian dollars, and a gain of $45,000 on the sale of the Pan Global Energy shares.

Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our results of operations in the future.

DD&A related to U.S. production increased 51% to $265,000 for the first quarter 2006 and represented a DD&A rate per net equivalent barrel of $17.59 as a result of the impact of the South Gillock acquisition in April 2005.

Lease operating expenses increased 310% to $533,000 from $130,000 due to the South Gillock operations and workover program in South Texas. Included in this amount is $338,000 of workover costs at South Gillock that will not be incurred in subsequent periods. General and administrative costs of $602,000 in the first quarter 2006 increased 53% compared to the same quarter of 2005, primarily resulting from increased staff and consultants related to the support of the South Gillock purchase and expanded business development activities. Interest income increased in the first quarter 2006 as a result of increased cash on hand and our participation in certain investments.

Capital Expenditures. In January 2006, we acquired the Jarvis Dome prospect in Anderson County, Texas and capitalized approximately $300,000 in costs associated with this project. In addition, we capitalized approximately $68,000 of costs at South Gillock.

In April 2005, we completed the purchase of the South Gillock property located in Galveston County, Texas. We paid $3.0 million cash and issued 500,000 shares and 500,000 warrants exercisable at $1.00 per share on or before April 15, 2007.

B. Liquidity and Capital Resources

Liquidity. We had cash and short-term investments of $9.1 million and working capital of $7.5 million, at December 31, 2005, $11.4 million and $10.8 million, at December 31, 2004 and $5.7 million and $5.3 million, at December 31, 2003, respectively.

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We have significant commitments for international projects during the next three years. In Turkey, we have work commitments totaling $800,000 for the period 2006 through 2008. We will spend approximately $500,000 to acquire and reprocess seismic data and conduct technical studies in the North Sea during 2006 and 2007. In conjunction with the three production licenses awarded to us in Romania, we anticipate expenditures during 2006 through 2008 of $1,500,000 for seismic and $7,300,000 for drilling and workovers, provided that we have success in the prospects.

In Morocco, we expect to spend approximately $520,000 in 2006 in the Guercif-Beni Znassen area. Furthermore, we plan to shoot a three-dimensional seismic survey and drill one deep exploratory well in the area covered by the Tselfat exploration permit during the period 2006 though 2008 for an anticipated amount of $3,000,000. The work program commitments in Morocco are fully collateralized by certificates of deposit in the amount of $3,600,000. The certificates of deposit may be drawn down to fund expenditures as the work programs progress. We anticipate reducing the deposits to $3,300,000 in August 2006.

In conjunction with the sale of our Nigerian subsidiaries effective June 2005, we deposited $1.76 million into an escrow fund to address any Nigerian tax liabilities and claims relating to our operations in Nigeria from 1998 to 2005. At the time of the sale, the previously recorded reserve of $855,000 was increased to $1.76 million (the amount deposited into escrow), and the charge for the increase to the reserve was included in earnings. In the third quarter 2005, we filed Nigerian tax returns with respect to years 1998 through 2001, and $226,000 was withdrawn from the escrow account to pay all remaining Nigerian tax liabilities for that period. In the first quarter 2006, we filed Nigerian tax returns with respect to years 2002 through 2004, and an additional $550,000 was withdrawn from the escrow to pay the estimated tax due for those years. The tax returns for years 2002 through 2004 still must undergo review by the Nigerian Federal Inland Revenue Service, and we remain responsible for taxes up to the sale date in June 2005. As of June 2006, $961,000 remains in the escrow fund, and we believe this provides adequate provision for the tax liabilities related to our Nigerian activities.

In September 2005, we completed the purchase of 2,237,136 shares of American Natural Energy Corporation (“ANEC”) pursuant to ANEC’s private placement of securities. ANEC is the operator of the Bayou Couba property in which we hold a 10% interest. The purchase price was $268,000, or $0.12 per share. We carry these shares at their anticipated net realizable value of $0.07 per share, as we do not anticipate selling these shares in the short term.

In October 2003, we acquired $3.0 million of convertible debentures issued by ANEC. The convertible debentures pay 8% interest, were for a two-year term maturing September 30, 2005 and are secured by all of the assets of ANEC. In June 2005, the convertible debenture holders approved extending the maturity of the debentures to September 20, 2006 and changing the conversion price from $0.43 per share to $0.15 per share. We have reserved against the original $3.0 million investment in order to present it at its estimated net realizable value. Based upon an analysis of ANEC’s financial position, we determined it appropriate to reserve $2.1 million against this investment as at December 31, 2004 and such reserve continued at December 31, 2005. The investment is accounted for using the cost method.

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In March 2006, we announced a non-binding letter of intent with ANEC to sell our interests in the Bayou Couba property as well as the ANEC 8% Convertible Secured Debentures in the principal amount of $3.0 million (carried at $900,000) held by us. The letter of intent stipulated that ANEC would pay us a total of $3.8 million cash for both the Bayou Couba property and the Debentures. The agreement was subject to ANEC securing financing, definitive terms and final approval by the boards of directors of both companies. The transaction did not close.

In November 2005, we completed a private placement whereby we issued 5,000,000 Units at $0.85 per Unit for gross proceeds of $4.25 million. Each Unit consisted of one common share and one half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one common share at a price of $1.05 through November 6, 2007. If the volume weighted average closing price of our common shares exceeds $1.40 per share for 20 consecutive trading days, we will be entitled to accelerate expiration of the warrants (thereby requiring the warrant holder to exercise the warrant within 30 days of being notified of the accelerated expiration). The proceeds are being used for ongoing international and U.S. exploration and development activities.

Pursuant to a private placement which closed in February 2004, we sold 7.635 million Units at $1.00 per Unit. Each Unit consisted of one post-consolidation common share of common stock and one warrant entitling the warrant holder to purchase one common share at $1.50 per share, which expired on January 6, 2006.

As of March 31, 2006, we had cash and short-term investments of $8.0 million and working capital of $7.0 million, compared to $9.1 million and $7.5 million, respectively, at December 31, 2005.

The timing and continued maintenance of cash flow from our projects is dependent on finding and developing additional oil and gas reserves, oil and gas prices and the availability of additional capital to continue project development.

Capital Resources. Given the capital-intensive nature of oil and gas exploration as well as the uncertainty of economic success from our existing projects, additional capital will likely be required to fund existing and additional projects. We will continue to pursue the divestiture of our interests in Bayou Couba and further anticipate raising funds in the capital markets.

C. Research and Development, Patents and Licenses, etc.

We have no material research and development programs or policies.

D. Trend Information

There are a number of trends in the crude oil and natural gas industry that are shaping the

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near future of the business. Crude oil prices are dependent upon the world economy and the global supply-demand balance. Demand for crude oil continues to grow, particularly in developing countries. The current environment of geopolitical unrest has increased prices well above those supported by current supply-demand balances based on perceived risk. While pricing in the future may more accurately reflect supply-demand fundamentals, it would appear that the current tight supply environment is highly sensitive to political and terrorist risks as evidenced by the risk premium in the current price structure. The magnitude of this risk premium changes over time. Natural gas prices have been somewhat volatile over the past year, particularly due to shut-ins and damages to production facilities in the Gulf of Mexico as a result of adverse weather conditions. With the supply and demand balance for natural gas being tight, the market has experienced volatility in pricing due to a number of factors, including weather, drilling activity, declines, storage levels, fuel switching and demand. In addition, in the next few years liquid natural gas terminals are anticipated to add natural gas supplies to the United States, resulting in a moderation of natural gas prices. It appears that prices of crude oil and natural gas no longer rise and fall in tandem. Any substantial disruptive event could cause crude oil or natural gas prices to spike. Similarly, resolution of certain geopolitical tensions, such as the crisis with Iran concerning the development of nuclear weapons capability, could cause such prices to moderate.

E. Off-Balance Sheet Arrangements

As at June 30, 2006, we had no off-balance sheet arrangements.

F. Tabular Disclosure of Contractual Obligations

As at December 31, 2005, we had the following contractual and commercial commitments:

As part of our June 2005 award of a reconnaissance license in Morocco, we committed to a work program that will involve the reprocessing of seismic data and other technical work over the property. Our portion of the work commitment for the first year cost $600,000. The exclusive license was for a term of one year. We have extended the license for an additional six months based upon an additional work program to cost $120,000. At the end of the reconnaissance license, we have the right to convert portions of the area to an exploration permit.

We posted a $591,000 certificate of deposit pursuant to a guarantee of the work program, and it is included in restricted cash at December 31, 2005. We have entered into an operating lease in respect of its office premises. The minimum payments under this lease commitment, including estimated operating costs are as follows:

(in thousands)
2006	$	85
2007	$	87
2008	$	44
Total	$	216

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G. Safe Harbor

Certain statements in this registration statement, including those appearing under this Item 5, constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, Section 27A of the United States Securities Act of 1933, as amended and within the meaning of applicable Canadian securities legislation. Additionally, forward looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us on our behalf. Such statements are generally identifiable by the terminology used such as “plans”, “expects, “estimates”, “budgets”, “intends”, anticipates”, “believes”, “projects”, “indicates”, “targets”, “objective”, “could”, “may” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for natural gas, natural gas liquids and oil products; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdown; actions by governmental authorities including increases in taxes, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; and the other factors discussed in Item 3 Key Information - “Risk Factors”, and in other documents that we file with the United States Securities and Exchange Commission and with Canadian securities regulatory authorities. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors; our course of action would depend upon our assessment of the future considering all information then available. In that regard, any statements as to future natural gas, or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectibility of receivables; availability of trade credit; expected operating costs; and changes in any of the foregoing are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should

32

recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results , may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

Item 6. Directors, Senior Management and Employees

A. Directors and Senior Management

Name	Position Held	Age
Michael D. Winn	Director	44
Brian B. Bayley	Director	53
Alan C. Moon	Director	60
Scott C. Larsen	President and Chief Executive Officer, Director	54
Christopher H. Lloyd	Chief Financial Officer	34
Dr. David Campbell	International Exploration Manager	54
Dr. Weldon Beauchamp	Consulting Geophysicist/Geologist	47
Jeffrey S. Mecom	Corporate Secretary	40
Hilda Kouvelis	Controller	43

Michael D. Winn has served as a director since 2004. He is currently President of Terrasearch Inc. a consulting company that provides analysis on mining and energy companies. Prior to forming his own company in 1997, Mr. Winn spent four years as an analyst for a Southern California based brokerage firm where he was responsible for the evaluation of emerging oil and gas and mining companies. Mr. Winn has worked in the oil and gas industry since 1983 and the mining industry since 1992, and is also a director of several companies that are involved in mineral exploration in Canada, Latin America, Europe and Africa. Mr. Winn has completed graduate course work in accounting and finance and received a B.S. degree in geology from the University of Southern California. Mr. Winn is currently a director of the following public companies:

Company	Exchange
Alexco Resource Corp	TSX
Eurasian Minerals Inc.	TSX Venture Exchange
General Minerals Corp.	TSX
Lake Shore Gold Corp.	TSX Venture Exchange
Mena Resources Inc.	TSX Venture Exchange
Quest Capital Corp.	TSX
Sanu Resources Ltd.	TSX Venture Exchange

Brian B. Bayley has served as a director since 2001. Mr. Bayley is currently the Chief Executive Officer and President of Quest Capital Corp, a publicly traded merchant banking

33

organization that focuses on providing financial services, specifically bridge loans, to small and mid-cap companies in North America. He was also the co-founder of Quest Ventures Ltd., a privately held merchant bank based in Vancouver which also specialized in bridge loans. Prior to Quest Ventures, Mr. Bayley was President and CEO of Quest Oil & Gas, which was sold to Enermark Income Fund in 1997. Mr. Bayley is currently a director of the following public companies:

Company	Exchange
American Natural Energy Corp.	TSX Venture Exchange
Arapaho Capital Corp.	TSX Venture Exchange
Cypress Hills Resource Corp.	TSX Venture Exchange
Esperanza Silver Corp.	TSX Venture Exchange
Eurasian Minerals Inc.	TSX Venture Exchange
Greystar Resources Ltd.	TSX
Groundstar Resources Limited	TSX Venture Exchange
Hatton Capital Corp.	TSX Venture Exchange
Kirkland Lake Gold Inc.	TSX
LARA Exploration Ltd.	TSX Venture Exchange
Midway Gold Corp.	TSX Venture Exchange
Navan Capital Corp.	TSX Venture Exchange
PetroFalcon Corp.	TSX
Quest Capital Corp.	TSX
Sanu Resources Ltd.	TSX Venture Exchange
Torque Energy Inc.	TSX Venture Exchange

Alan C. Moon has served as a director since 2004. Mr. Moon is currently President of Crescent Enterprises Inc., a private Calgary-based consulting firm. Prior to forming this company in 1997, Mr. Moon was President and COO of TransAlta Energy Corporation. The company was an international independent electric power generation and distribution company with approximately $1 billion in assets and operated in Ontario, New Zealand, Australia, South America, and the United States. Mr. Moon is currently a director of the following public companies:

Company	Exchange
Avenir Diversified Income Trust	TSX
Superior Diamonds Inc.	TSX Venture Exchange
Calpine Power Income Fund	TSX
Lake Shore Gold Corp.	TSX Venture Exchange
Maxy Gold Corp.	TSX Venture Exchange
Enervest Diversified Income Trust	TSX

Scott C. Larsen has served as our President and Chief Executive Officer since March 2004. He was appointed director in 2005. He previously served as our Vice President - Operations since July 2002 and has been involved in our international activities since their inception in 1994. An attorney by training with over 25 years experience in the oil and gas

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industry, Mr. Larsen previously served as general counsel for a Texas independent exploration company, spent several years as a partner in a business litigation law firm in Dallas, Texas and served as general counsel for a venture capital and management company. He received a B.A. degree in biology from Rutgers College and a J.D. degree from Rutgers School of Law.

Christopher H. Lloyd has served as our Chief Financial Officer since October 2004. Before joining us, Mr. Lloyd was a Director in the Business Restructuring and Management Consulting practice of PriceWaterhouseCoopers in Dallas, Texas. Mr. Lloyd previously served as a Director of Business Development for Panda Energy International, Inc., an international oil and gas and power generation company. Prior to that he worked in the oil and gas audit practice of Ernst and Young LLP. He received an M.B.A. degree in finance from the University of Texas at Austin and a B.B.A degree in accounting from the University of Oklahoma. Mr. Lloyd is a licensed Certified Public Accountant.

Dr. David Campbell currently serves as our International Exploration Manager. He received a B.Sc. degree in geology from St Andrews University and a Ph.D. degree in geology at Glasgow University. After university he joined Esso Expro UK as a seismic interpreter and later spent the majority of his professional career with ARCO both in the UK and overseas. He was North Sea Chief Geophysicist for ARCO British Limited, Geophysical Research Manager for ARCO Exploration and Production Technology Company, and Middle East Exploration Manager for ARCO International Oil and Gas Company. Following his retirement from ARCO, Dr Campbell became an officer or a director in a number of energy-related companies, including Balli Resources Limited, Balli Naft CFZ and VND Energy Limited.

Dr. Weldon Beauchamp currently serves as our Consulting Geophysicist/Geologist. He received a B.A. degree in geology from New England College, New Hampshire, and an M.S. degree in geology from Oklahoma State University and a Ph.D. in geophysics from Cornell University. He worked for Sun Exploration and Production Company in the mid-continent region, prior to joining Sun International Exploration and Production Company in Dallas, Texas and London, England. He served as a new venture exploration geologist in the North Sea, Africa, and the Middle East regions. Upon leaving Sun, he completed his doctoral work, which focused on the tectonic evolution of the Atlas Mountains in North Africa. Dr. Beauchamp then joined ARCO in Plano, Texas where he worked as a geophysicist in New Ventures - Middle East. Since leaving ARCO, he has consulted for Triton Energy in Equatorial Guinea, for Hunt Oil in offshore Togo as well as for TransAtlantic in Nigeria and Morocco.

Jeffrey S. Mecom has served as our Corporate Secretary since May 2006. He also serves as Vice President - Legal of our TransAtlantic Petroleum (USA) Corp. subsidiary. Prior to joining us, Mr. Mecom served as Vice President, Legal and Corporate Secretary with Aleris International, Inc., an NYSE-listed international metals recycling and processing company, where he was employed from 1995 until 2005. He received his B.A. degree in economics from the University of Texas at Austin and his J.D. degree from the University of Texas School of Law.

Hilda D. Kouvelis has served as our Controller since May 2006. Ms. Kouvelis has more than 20 years of industry experience, including 18 years with FINA, Inc., where she held various positions in finance and accounting, including Controller and Treasurer. Ms Kouvelis served as

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Financial Controller for international operations at the headquarters of PetroFina, S.A. in Brussels, Belgium from 1998 through 2000. She holds an M.B.A. degree in corporate finance and investment analysis from the University of Dallas and a B.B.A. degree in accounting from Angelo State University. Ms. Kouvelis is a licensed Certified Public Accountant.

None of our directors, officers or employees has any family relationship with one another. To the best of our knowledge, there are no arrangements or understandings with major shareholders, customers, suppliers or others, pursuant to which any person referred to above was selected as a director or member of senior management.

B. Compensation

The following table sets forth all annual and long-term compensation for services in all capacities in Fiscal 2005 for our directors, chief executive officer and chief financial officer.

								Options Granted
	Salary		Bonus		Other Annual Compensation			Number	Exercise Price		Expiry Date
Scott C. Larsen President, Chief Executive Officer and Director	$	216,000	$	50,000	$	100,000	(1)	100,000	$	0.90	October 11, 2010
Christopher H. Lloyd Chief Financial Officer	$	144,000	$	30,000	$	15,000	(2)	125,000 35,000	$ $	0.71 0.90	May 6, 2010 October 11, 2010
Michael D. Winn Director		-0-		-0-	$	59,840	(3)	100,000	$	0.90	October 11, 2010
Brian B. Bayley Director		-0-		-0-	$	12,000	(3)	25,000	$	0.90	October 11, 2010
Alan C. Moon Director		-0-		-0-	$	12,000	(3)	25,000	$	0.90	October 11, 2010

(1) Mr. Larsen was paid a one-time bonus of $100,000 upon the successful sale of our Nigerian interests in June 2005 which represented the culmination of nearly 3 years of work to sell the Nigerian interests. In addition, we agreed to pay Mr. Larsen a bonus payment equal to 3.87% of the amount received by us from a net profits agreement with the purchaser of the Nigerian asset, if and when any such net profits are actually received, up to a total bonus payment of $600,000.

(2) Mr. Lloyd was paid a referral fee of $15,000 by Quest Capital Corp. with respect to a syndicated loan opportunity he presented to Quest in March 2005; the Company participated in the syndication and the loan has now been repaid.

(3) Represents director fees paid in accordance with resolutions passed by our Compensation Committee.

The following table sets forth details of all stock options exercised in Fiscal 2005 by each of our directors, chief executive officer and chief financial officer.

	Options Exercised	Exercise Price		Market Price		Aggregate Value Realized
Scott C. Larsen President, Chief Executive Officer and Director	120,000	$	0.75	$	0.85	$	12,000

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C. Board Practices

Term of Office. At the end of Fiscal 2005, we had four directors. The terms of all four expire at the annual meeting of shareholders:

Name	Term Expires	Held Office Since
Michael D. Winn	May 2007	May 2004
Brian B. Bayley	May 2007	May 2001
Alan C. Moon	May 2007	May 2004
Scott C. Larsen	May 2007	May 2005

Our board of directors currently has three committees: the Audit Committee, the Compensation Committee and the Corporate Governance Committee. Our three independent directors, Michael D. Winn, Brian B. Bayley and Alan C. Moon, comprise the Audit Committee, the Compensation Committee and the Corporate Governance Committee.

Audit Committee. The Audit Committee reviews the effectiveness of our financial reporting, management information and internal control systems, and the effectiveness of our independent auditors. It monitors financial reports, the conduct and results of the annual independent audit, finance and accounting policies and other financial matters. The Audit Committee also reviews and approves our interim consolidated financial statements and year end financial statements. The Audit Committee has been designated by the Board to serve as the Reserves Committee and reviews the reserve reports and conducts inquiries with the reserve engineers as it deems appropriate. To maintain the effectiveness and integrity of our financial controls, the Audit Committee monitors internal control and management information systems.

Compensation Committee. The Compensation Committee establishes and reviews our compensation policies. The Compensation Committee also reviews our senior management’s performance. The Compensation Committee makes recommendations to the full Board for approval of granting stock options under our Amended Stock Option Plan and with respect to salaries and bonuses for executive officers. Our compensation philosophy is aimed at attracting and retaining quality and experienced personnel, which is critical to our success. Employee compensation, including executive officer compensation, is comprised of three elements: base salary, short-term incentive compensation (being cash bonuses) and long-term incentive compensation (being stock options). Since our focus has been in international oil and gas exploration, consideration is given to the factors such as time overseas, the risk inherent in certain international operations and the greater degree of time and effort international transactions may require. The Compensation Committee views the totality of our performance in its evaluation of compensation for executive officers.

D. Employees

As of December 31, 2005, our TransAtlantic Petroleum (USA) Corp. subsidiary employed five people full time in our Dallas, Texas office. The persons employed are the

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President and Chief Executive Officer, the Chief Financial Officer, and 3 persons in accounting, engineering and administration. None of our employees are related. None of our employees are members of a collective bargaining unit. In addition to the foregoing, we also received technical services from a number of exploration, geophysical, geological, engineering, accounting and legal consultants in Fiscal 2005.

E. Share Ownership.

None of our officers or directors owns more than one percent of our issued and outstanding common shares. For a description of our Amended and Restated Stock Option Plan (2006), please see Part II, Item 10.C – Material Contracts and Agreements.

Item 7. Major Shareholders and Related Party Transactions

A. Major Shareholders

To the best of our knowledge, no person beneficially owns, directly or indirectly, or exercises control or direction over shares constituting more than five percent of the voting rights of our shares, other than as set forth below:

Shareholder	Number of Shares	Percentage
Resource Capital Investment Corp.	4,421,500	11.7%

Our major shareholders do not have different voting rights than any other shareholders. As of June 30, 2006, our shareholders list showed 37,936,939 common shares outstanding with 221 registered shareholders in Canada holding 31,174,270 common shares. We are not controlled, directly or indirectly, by any corporation, foreign government or other person.

B. Related Party Transactions

Except as follows, none of our officers, directors or persons owning at least five percent of our outstanding securities, or affiliate thereof, has or has had any material interest, directly or indirectly, in any transaction involving us since January 1, 2003, or in any proposed transaction involving us.

We participated in four loan syndications through Quest Capital Corp. in 2003, 2004 and 2005. All are secured, short term investments. Brian B. Bayley, one of our directors, is President, CEO and a director of Quest Capital Corp. Michael D. Winn, another of our directors, is also a director of Quest Capital Corp. Both Mr. Bayley and Mr. Winn abstained from decisions relating to the loan syndications.

One of our directors, Brian B. Bayley, was also a director on the board of ANEC when we purchased an interest in the Bayou Couba property from ANEC and funded a $1.8 million production payment in March 2003. Mr. Bayley was also on the board of ANEC when we purchased $3 million of convertible debentures issued by ANEC. Mr. Bayley abstained from voting on both transactions. John Fleming, one of our former directors, became a director of ANEC following the purchase of the convertible debentures by us in October 2003 and continued as a director of ANEC until he passed away in March 2004. During the first quarter 2006, we received net payments (oil and gas sales plus debenture interest less drilling advances and lease operating expenses) of $69,000 (1Q2005 – $145,000) from ANEC. These transactions have been recorded at the exchange amount agreed to between the related parties. At March 31, 2006, one of our directors was also a director of ANEC.

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Scott C. Larsen, our chief executive officer, was paid a one-time bonus of $100,000 upon the successful sale of our Nigerian interests in June 2005 which represented the culmination of nearly 3 years of work to sell the Nigerian interests. In addition, we agreed to pay Mr. Larsen a bonus payment equal to 3.87% of the amount received by us from a net profits agreement with the purchaser of the Nigerian asset, if and when any such net profits are actually received, up to a total bonus payment of $600,000.

Christopher H. Lloyd, our chief financial officer, was paid a referral fee of $15,000 by Quest Capital Corp. with respect to a syndicated loan opportunity he presented to Quest in March 2005; the Company participated in the syndication and the loan has now been repaid.

C. Interests of Experts and Counsel

Not applicable.

Item 8. Financial Information

A. Consolidated Statements and Other Financial Information

Financial statements are provided under Part III, Item 17.

Legal or Arbitration Proceedings. As of the date of this registration statement, we are, to the best of our knowledge, not subject to any material active or pending legal proceedings or claims against us or any of our properties. However, from time to time, we may be subject to claims and litigation generally associated with any business venture. Additionally, our operations are subject to risks of accident and injury, possible violations of environmental and other regulations, and claims associated with the risks of exploration operations some of which cannot be covered by insurance or other risk reduction strategies.

Dividend Policy. We have not paid any cash dividends on our common stock and have no present intention of paying dividends. Our current policy is to retain earnings, if any, for use in operations and in business development.

B. Significant Changes

None

Item 9. The Offer and Listing

A. Offer and Listing Details

Not Applicable

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B. Plan of Distribution

Not Applicable

C. Markets

Our shares of common stock are traded in Canada on the Toronto Stock Exchange (“TSX”) under the symbol “TNP.U.” As of June 30, 2006, we had 37,936,939 shares of common stock outstanding. Our shares of common stock are issued in registered form and the number of shares of common stock reported to be held by record holders in Canada and the United States is taken from the records of Computershare Trust Company of Canada, the registrar and transfer agent for our shares of common stock. For U.S. reporting purposes, we are a foreign private issuer. We currently have no established market for trading our shares in the United States. The high and low prices for our common stock from January 1, 2001 through December 31, 2005 on the TSX are as follows:

	High		Low
January 1, 2001 through December 31, 2001	$	0.02	$	0.175
January 1, 2002 through December 31, 2002	$	0.03	$	0.185
January 1, 2003 through December 31, 2003	$	0.33	$	0.12
January 1, 2004 through December 31, 2004	$	1.20	$	0.19
January 1, 2005 through December 31, 2005	$	1.02	$	0.59

The high and low prices for our common stock for each quarter from January 1, 2004 through June 30, 2006 on the TSX are as follows:

	High		Low
January 1, 2004 through March 31, 2004	$	1.12	$	0.19
April 1, 2004 through June 30, 2004	$	1.20	$	0.73
July 1, 2004 through September 30, 2004	$	1.00	$	0.66
October 1, 2004 through December 31, 2004	$	0.90	$	0.58
January 1, 2005 through March 31, 2005	$	0.90	$	0.65
April 1, 2005 through June 30, 2005	$	0.85	$	0.67
July 1, 2005 through September 30, 2005	$	0.96	$	0.59
October 1, 2005 through December 31, 2005	$	1.02	$	0.73
January 1, 2006 through March 31, 2006	$	1.30	$	0.82
April 1, 2006 through June 30, 2006	$	1.35	$	1.09

The high and low prices for our common stock for the most recent six months on the TSX are as follows:

	High		Low
January 1, 2006 through January 31, 2006	$	1.10	$	0.82
February 1, 2006 through February 28, 2006	$	1.09	$	1.00
March 1, 2006 through March 31, 2006	$	1.30	$	1.00
April 1, 2006 through April 30, 2006	$	1.30	$	1.09
May 1, 2006 through May 31, 2006	$	1.35	$	1.16
June 1, 2006 through June 30, 2006	$	1.29	$	1.10

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Warrants. In November 2005, pursuant to a financing, we issued 5,000,000 Units at a price of $0.85 per Unit. Each Unit consists of one common share and one half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one common share at a price of $1.05 per share until November 2007; provided however, if the volume weighted average closing price of our common shares exceeds $1.40 per share for 20 consecutive trading days, we are entitled to accelerate expiration of the warrants (thereby requiring the warrant holder to exercise the warrant within 30 days of being notified of the accelerated expiration). In connection with issuance of the Units, we also issued 375,000 broker warrants to the underwriters exercisable on the same terms as the warrants forming part of the financing Units.

In April 2005, we issued 500,000 share purchase warrants as part of the consideration for our purchase of the South Gillock property. Each warrant entitles the holder to acquire one common share at a price of $1.00 per share until April 2007.

D. Selling Shareholders

Not Applicable

E. Dilution

Not Applicable

F. Expenses of the Issue

Not Applicable

Item 10. Additional Information

A. Share Capital

Our authorized share capital consists of an unlimited number of common shares without par value. All issued shares are fully paid and non-assessable. As of December 31, 2005 and June 30, 2006 we had 37,659,189 and 37,936,939, respectively, shares issued and outstanding. As of June 30, 2006, we have outstanding an aggregate of 2,685,000 options to purchase shares pursuant to our Amended and Restated Stock Option Plan (2006). We also have outstanding 3,257,250 share purchase warrants related to a private placement which closed in November 2005 and the South Gillock property purchase which closed in April 2005. Each April 2005 warrant entitles the holder to acquire one common share at a price of $1.00 through April 15, 2007. Each November 2005 warrant entitles the holder to acquire one common share at a price of $1.05 through November 6, 2007. If the volume weighted average closing price of our common shares exceeds $1.40 per share for 20 consecutive trading days, we are entitled to accelerate expiration of the November 2005 warrants, thereby requiring the warrant holder to exercise the warrant within 30 days of being notified of the accelerated expiration.

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B. Articles of Incorporation and Bylaws

The Business Corporations Act (Alberta) requires any one of our directors or officers who is a party to a material contract or a material transaction, whether made or proposed, with us or who is a director or officer of or has a material interest in any person who is a party to a material contract or a material transaction, whether made or proposed, with us to disclose in writing to us or request to have entered in the minutes of the meeting of directors or committees of directors the nature and extent of his or her interest, and shall, except in limited circumstances (including votes in respect of contracts relating primarily to a director’s remuneration or for a director’s indemnity or insurance), refrain from voting in respect of the material contract or material transaction. Neither the Act, our articles nor our bylaws require an independent quorum to enable the directors to vote compensation to themselves or any of their members.

The board of directors has an unlimited power to borrow, issue debt obligations and to charge our assets, provided only that such power is exercised honestly and in good faith with a view to our best interests and that in exercising such power, the directors exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. There is no mandatory retirement age for our directors, and the directors are not required to own any of our shares in order to qualify as a director.

We have only one class of common shares, without any special rights or restrictions. Holders of common shares are entitled to receive notice of and attend all meetings of our shareholders and are entitled to one vote for each common share held on all votes taken at such meetings. There are no cumulative voting rights, in consequence of which a simple majority of votes at the annual meeting can elect all of our directors. Each common share carries with it the right to share equally with every other common share in such dividends as the directors may in their discretion declare. The dividend entitlement of a shareholder of record is fixed at the time of any such declaration by the board of directors. Pursuant to our by-laws, any dividend which is unclaimed after a period of six years from the date on which such dividend is declared to be payable will be forfeited and revert to us. Each common share also carries with it the right to share equally with every other common share in any distribution of any of our remaining property, after payment to creditors, on any winding up, liquidation or dissolution. There are no sinking fund provisions. All common shares must be fully paid for prior to issue and are thereafter subject to no further capital calls by us. There exists no discriminatory provision affecting any existing or prospective holder of common shares as a result of such shareholder owning a substantial number of shares.

Under the Business Corporations Act (Alberta), the amendment of certain rights attaching to the common shares requires the shareholders to pass a special resolution approved by not less than two-thirds of the votes cast by the holders of such shares voting at a special meeting of such holders. The Act requires notice of a special meeting to state the nature of the proposed business in sufficient detail to permit a shareholder to form a reasoned judgment and to include the text of any special resolution to be submitted at the meeting. Pursuant to our bylaws, a quorum for a

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meeting of the holders of common shares occurs when there are at least two persons present in person, each being a shareholder or a duly appointed proxy or representative for an absent shareholder, and representing in the aggregate not less than 10% of the outstanding common shares. In circumstances where the rights of common shares may be amended to add, change or remove any provisions restricting or constraining the issue, transfer or ownership of common shares, holders of common shares have the right under the Business Corporations Act (Alberta) to dissent from such amendment and require us to pay them the then fair value of the common shares.

There are two types of shareholder meetings: annual meetings and special meetings. Pursuant to the Business Corporations Act (Alberta), an annual shareholder meeting shall be held not later than 15 months after the holding of the last preceding annual meeting. The Board may call a special meeting of shareholders at any time. Notice of any shareholder meeting must be accompanied by an information circular describing the proposed business to be dealt with and making disclosures as prescribed by the Securities Act (Alberta). A shareholder or shareholders having in the aggregate 5% of our issued shares may requisition our directors to call a meeting for the purposes stated in the requisition. Except in certain circumstances, the Board is required to call such meeting within 21 days after receiving such requisition and if they do not, the shareholders who requisitioned the meeting may call the meeting. Admission to shareholder meetings is open to registered shareholders and their duly appointed proxies and our directors and auditors. Others may be admitted on the invitation of the chairman of the meeting or with the consent of the meeting.

Neither our articles nor our bylaws contain any limitations on the rights of non-resident or foreign shareholders to hold or exercise rights on our shares and there is no limitation under the Business Corporation Act (Alberta) on the right of a non-resident to hold shares in a corporation incorporated under such Act.

There are no provisions in our articles or bylaws that would have an effect of delaying, deferring or preventing a change in control and that would operate only with respect to a merger, acquisition or corporate restructuring involving us or any of our subsidiaries.

There is no provision in our articles setting a threshold or requiring or governing disclosure of shareholder ownership above any level. Securities Acts, regulations and the policies and rules thereunder in the Provinces of Alberta, British Columbia and Ontario, where we are a reporting issuer, require any person holding or having control of more than 10% of our issued shares to file insider returns disclosing such share holdings.

C. Material Contracts and Agreements

Employment Agreements. We entered into an employment agreement with Mr. Larsen, our President and Chief Executive Officer, effective July 1, 2005. The agreement expires upon the death, disability, resignation or other termination of employment of Mr. Larsen. This agreement provides for an annual base salary to Mr. Larsen as approved by our Board, initially at the rate of $240,000 per year. The agreement also provides for Mr. Larsen’s participation in our Amended and Restated Stock Option Plan (2006) and other benefits made available to our executives resident in the U.S.

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If the employment agreement is terminated (1) by us at any time without cause (as defined in the agreement) or (2) by Mr. Larsen within sixty days of an event that constitutes “constructive dismissal” (as defined in the agreement), then we will pay Mr. Larsen a lump sum amount equal to Mr. Larsen’s annual salary plus $15,000 (the “termination amount”). If a “change in control” (as defined in the agreement) results in either (1) the termination of Mr. Larsen’s employment without cause within thirty days prior to or within one year after the change in control, or (2) a constructive dismissal within one year of the change in control, we will pay Mr. Larsen a lump sum amount equal to the termination amount. Under the agreement, Mr. Larsen agreed to certain confidentiality and non-solicitation obligations, and in order to receive the termination amount set forth in the agreement, Mr. Larsen must first sign a release in the form set forth in the agreement.

We entered into a substantially similar employment agreement with Mr. Lloyd, our Chief Financial Officer. His agreement provides for an annual base salary of $144,000 and is dated effective May 1, 2005. Mr. Lloyd’s termination amount is equal to one-half of his annual salary plus $7,500.

Participating Interest Agreement. We entered into an agreement with Mr. Larsen under which we granted Mr. Larsen a participating interest in any compensation we receive pursuant to the agreement we entered into with Tetrarch Limited in June 2005 concerning the sale of our Nigerian assets (the “TWL Compensation Agreement”). Under the participating interest agreement, Mr. Larsen will receive 3.87% of any TWL Compensation (as defined in the TWL Compensation Agreement) we receive, provided that in no event will Mr. Larsen receive more than $599,850 of the TWL Compensation.

Amended and Restated Stock Option Plan (2006). Our only equity compensation plan is the Amended and Restated Stock Option Plan (2006) (the “Option Plan”), which has been approved and adopted by our shareholders. Pursuant to the Option Plan, we may grant stock options to our directors, officers, employees and consultants or to directors, officers, employees or consultants of our subsidiaries. The stock options enable such persons to purchase our common shares at the exercise price fixed by our Board at the time the option is granted. Our Board determines the number of common shares purchasable pursuant to each option and such exercise price within the guidelines established by the Option Plan. These guidelines allow the Board to authorize the issuance of options with a term not to exceed 10 years and to set other conditions to the exercise of options, including any vesting provisions. All options presently issued have terms of five years and all are fully vested. Consistent with the rules of the Toronto Stock Exchange, our Option Plan requires that the exercise price of the options at the time of grant may not be lower than the market price of our common shares, which is the closing price of our common shares on the Toronto Stock Exchange on the trading day immediately prior to the date the stock option is granted.

The option agreements must provide that the option can only be exercised by the optionee and only for so long as the optionee shall continue in the capacity outlined above or within a specified period after ceasing to continue in such capacity. The options are exercisable by the

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optionee giving us notice and payment of the exercise price for the number of common shares to be acquired. Under the Option Plan, our Board is empowered to grant stock options to insiders without further shareholder approval. The aggregate maximum number of common shares which may be reserved for issuance to any one person at any time under the Option Plan is five percent of the number of common shares that are outstanding immediately prior to the reservation in question, excluding common shares issued pursuant to our share compensation arrangements over the preceding one-year period (the “Outstanding Issue”). The aggregate number of common shares which may be issued to any one our insiders within a one year period cannot exceed 5% of the Outstanding Issue. In addition, (a) the maximum aggregate number of common shares which can be reserved for issuance to insiders is limited to 10% of the Outstanding Issue and (b) the maximum aggregate number of common shares which can be issued to insiders, within a one year period, is limited to 10% of the Outstanding Issue.

Stock options granted under the Option Plan are not assignable. We do not provide financial assistance to facilitate the purchase of common shares on exercise of stock options. The Option Plan is a fixed maximum percentage plan pursuant to which the maximum number of our common shares which can be reserved for issuance pursuant to stock options is equal to 10% of the number of issued and outstanding common shares on the date of grant of any stock option. Since the Option Plan is a fixed percentage plan rather than a fixed number plan, the Option Plan allows the reloading of common shares authorized for issuance upon the exercise or cancellation of stock options granted under the Option Plan up to the 10% maximum percentage amount. Because our Option Plan is a fixed maximum percentage plan, it must be approved every three years by both our Board and our shareholders. In addition, any change to the maximum percentage of our common shares authorized under the Option Plan must be approved by both our Board and our shareholders. The Option Plan sets forth the types of amendments that can be made by our Board without shareholder approval, which include altering the terms and conditions of vesting applicable to any stock options; extending the term of stock options held by a person other than any of our insiders; accelerating the expiry date in respect of stock options; and adding a cashless exercise feature, payable in cash or common shares..

Warrants. In November 2005 we closed a $4.25 million bought deal underwritten private placement financing. Pursuant to the financing, we issued 5,000,000 Units at a price of $0.85 per Unit. Each Unit consists of one common share and one half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one common share at a price of $1.05 per share until November 6, 2007, provided however, if the volume weighted average closing price of our common shares exceeds $1.40 per share for 20 consecutive trading days, we are entitled to accelerate expiration of the warrants (thereby requiring the warrant holder to exercise the warrant within 30 days of being notified of the accelerated expiration). In connection with issuance of the Units, we also issued 375,000 broker warrants to the underwriters exercisable on the same terms as the warrants forming part of the financing Units.

In April 2005, we issued 500,000 share purchase warrants as part of the consideration for our purchase of the South Gillock property. Each warrant entitles the holder to acquire one common share at a price of $1.00 per share until April 15, 2007.

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D. Exchange Controls

There are no governmental laws, decrees, or regulations in Canada that restrict the export or import of capital or that affect the remittance of dividends, interest, or other payments to nonresident holders of our common stock. However, any such remittance to a non-corporate resident of the United States may be subject to a 15% withholding tax pursuant to Article XI of the reciprocal tax treaty between Canada and the United States.

Except as provided in the Investment Canada Act (the “Act”), enacted on June 20, 1985, as amended, as further amended by the North American Free Trade Agreement (NAFTA) Implementation Act (Canada) and the World Trade Organization (WTO) Agreement Implementation Act, there are no limitations under the laws of Canada, the Province of Alberta or in the charter or any other of our constituent documents on the right of non-Canadians to hold and/or vote our common stock.

E. Taxation

The following paragraphs set forth certain United States and Canadian federal income tax considerations in connection with the payment of dividends on and purchase or sale of our shares of common stock. The tax considerations are stated in general terms and are not intended to be advice to any particular shareholder. Each prospective investor is urged to consult his or her own tax advisor regarding the tax consequences of his or her purchase, ownership and disposition of shares of our common stock.

The discussion set forth below is based upon the provisions of the Income Tax Act (Canada) (the “Tax Act”), the Internal Revenue Code of 1986, as amended (the “Code”) and the Convention between Canada and the United States of America with respect to Taxes on Income and on Capital (the “Convention”), as well as United States Treasury regulations and rulings and judicial decisions. Except as otherwise specifically stated, the following discussion does not take into account or anticipate any changes to such laws, whether by legislative action or judicial decision. The discussion does not take into account the provincial tax laws of Canada or the tax laws of the various state and local jurisdictions in the United States.

Canadian Federal Income Tax Considerations. The following discussion applies only to citizens and residents of the United States and United States corporations who are not resident in Canada and will not be resident in Canada and who do not use or hold nor are deemed to use or hold such shares of our common stock in carrying on a business in Canada.

The payment of cash dividends and stock dividends on the shares of our common stock will generally be subject to Canadian withholding tax. The rate of the withholding tax will be 25% or such lesser amount as may be provided by treaty between Canada and the country of residence of the recipient. Under the Convention, the withholding tax generally would be reduced to 15%.

Neither Canada nor any province thereof currently imposes any estate taxes or succession duties. Provided a holder of shares of our common stock has not, within the preceding five years,

46

owned (either alone or together with persons with whom he or she does not deal at arm’s length) 25% or more of the shares of common stock, the disposition (or deemed disposition arising on death) of such shares of common stock will not be subject to the capital gains provisions of the Tax Act.

United States Federal Income Tax Considerations. The following discussion is addressed to US holders. As used in this section, the term “US holder” means a holder of our common stock that is for United States federal income tax purposes (1) an individual citizen or resident of the United States, (2) a corporation created or organized in or under the laws of the United States, any state of the United States or the District of Columbia, (3) an estate the income of which is subject to United States federal income taxation regardless of its source, or (4) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons (as defined in the Code) have the authority to control all substantial decisions of the trust, or a trust was in existence on August 20, 1996, and validly elected to continue to be treated as a United States person. This discussion deals only with the holders that hold their common stock as capital assets within the meaning of Section 1221 of the Code. The discussion does not address all aspects of United States federal income taxation that may be relevant to US holders in light of their particular circumstances, nor does it address the United States federal income tax consequences to US holders that are subject to special rules under the Code, including, but not limited to, (i) dealers or traders in securities, (ii) financial institutions, (iii) tax-exempt organizations or qualified retirement plans, (iv) insurance companies, (v) entities that are taxed under the Code as partnerships, pass-through entities or “Subchapter S Corporations”, (vi) persons or entities subject to the alternative minimum tax, (vii) persons holding common stock as a hedge or as part of a straddle, constructive sale, conversion transaction, or other risk management transaction, and (viii) holders who hold their common stock other than as a capital asset.

Dividends. Subject to the discussion of the “passive foreign investment company” rules below, a US holder owning shares of common stock must generally treat the gross amount of dividends paid by us to the extent of our current and accumulated earnings and profits without reduction for the amount of Canadian withholding tax, as dividend income for United States federal income tax purposes. To the extent that distributions exceed our current or accumulated earnings and profits, they will be treated first as a tax-free return of capital, which will reduce the holder’s adjusted tax basis in his or her common stock (but not below zero), then as capital gain. The dividends generally will not be eligible for the “dividends received” deduction allowed to United States corporations. The amount of Canadian withholding tax on dividends may be available, subject to certain limitations, as a foreign tax credit or, alternatively, as a deduction (see discussion at “Foreign Tax Credit” below). In general, dividends paid by us will be treated as income from sources outside the United States if less than 25% of our gross worldwide income for the 3-year period ending with the close of our taxable year preceding the declaration date of the dividends was effectively connected with a trade or business in the United States. If 25% or more of our worldwide gross income for the 3-year testing period is effectively connected with a trade or business in the United States, then for United States federal income tax purposes our dividends will be treated as U.S. source income in the same proportion that the U.S. trade or business income bears to our total worldwide gross income. Dividends paid by us generally will be “passive income,” or in the case of certain types of taxpayers, “financial services income” for foreign tax credit purposes.

47

If we make a dividend distribution in Canadian dollars, the U.S. dollar value of the distribution on the date of receipt is the amount includible in income. Any subsequent gain or loss in respect of the Canadian dollars received arising from exchange rate fluctuations generally will be U.S. source ordinary income or loss.

Long-term capital gain of noncorporate taxpayers generally is eligible for preferential tax rates. Additionally, for taxable years beginning after December 31, 2002 and before January 1, 2011, subject to certain exceptions, dividends received by certain noncorporate taxpayers from “qualified foreign corporations” are taxed at the same preferential rates that apply to long-term capital gain. The maximum federal tax rate on net long-term capital gains recognized by noncorporate taxpayers currently is 15%. Provided that we are not a “passive foreign investment company,” as discussed below, we currently should meet the definition of “qualified foreign corporation.” As a consequence, dividends paid to certain noncorporate taxpayers should be taxed at the preferential rates.

Sale or Exchange of Common Stock. Subject to the discussion of the “passive foreign investment company” rules below, the sale of a share of our common stock generally results in the recognition of gain or loss to the US holder in an amount equal to the difference between the amount realized and the US holder’s adjusted tax basis in such share. Gain or loss upon the sale of the share will be long-term or short-term capital gain or loss, depending on whether the share has been held for more than one year. The maximum federal tax rate on net long-term capital gains currently is 15% for noncorporate taxpayers and 35% for corporations. Capital gain that is not long-term capital gain is taxed at ordinary income rates. The deductibility of capital losses is subject to certain limitations. Gain recognized by a US holder on the sale or other disposition of our common stock will generally be treated as United States source income.

Foreign Tax Credit. Subject to the limitations set forth in the Code, as modified by the Convention, a US holder may elect to claim a credit against his or her U.S. federal income tax liability for Canadian income tax withheld from dividends received in respect of shares of our common stock. Holders of our common stock and prospective US holders of our common stock should be aware that dividends we pay generally will constitute “passive income” for purposes of the foreign tax credit, which could reduce the amount of foreign tax credit available to them. The rules relating to the determination of the foreign tax credit are complex. US holders of our common stock and prospective US holders of our common stock should consult their own tax advisors to determine whether and to what extent they would be entitled to such credit. Holders who itemize deductions may instead claim a deduction for Canadian income tax withheld.

Information Reporting and Backup Withholding. Information reporting requirements will generally apply to dividends on, and the proceeds of a sale or exchange of, our common stock that are paid within the United States (and, in some cases, outside the United States) to US holders and certain exempt recipients (such as corporations). Certain US holders may be subject to backup withholding at the rate of 28% on dividends paid or the proceeds of a sale or exchange of our common stock. Generally, backup withholding will apply to a US holder only when the US holder fails to furnish us with or to certify to us the US holder’s proper United States tax

48

identification number or we are informed by the Internal Revenue Service of the United States that the US holder has failed to report payments of interest and dividends properly. US holders should consult their own tax advisors regarding the qualification for exemption from backup withholding and information reporting and the procedure for obtaining any applicable exemption.

Passive Foreign Investment Company Considerations. Special rules apply to US holders that hold stock in a “passive foreign investment company” (“PFIC”). A non-U.S. corporation generally will be a PFIC for any taxable year in which either (i) 75% or more of its gross income is passive income or (ii) 50% or more of the gross value of its assets consists of assets, determined on the basis of a quarterly average, that produce, or that are held for the production of, passive income. For this purpose, passive income generally includes, among other things, interest, dividends, rents, royalties and gains from certain commodities transactions.

We believe that we should not be classified as a PFIC for the current taxable year or prior taxable years, and we do not anticipate being a PFIC with respect to future taxable years. However, there can be no assurance that we will not be considered a PFIC for any taxable year, because (1) the application of the PFIC rules to our circumstances is unclear and (2) status under the PFIC rules is based in part on factors not entirely within our control (such as market capitalization). Furthermore, there can be no assurance that the Internal Revenue Service will not challenge our determination concerning our PFIC status. Therefore, US holders and prospective US holders are urged to consult with their own tax advisors with respect to the application of the PFIC rules to them.

If, contrary to our expectations, we were to be classified as a PFIC for any taxable year, a US holder may be subject to an increased tax liability (including an interest charge) upon the receipt of certain distributions from us or upon the sale, exchange or other disposition of our common stock, unless such US holder timely makes one of two elections. First, if, for any taxable year that we are treated as a PFIC, a US holder makes a timely election to treat us as a qualified electing fund (“QEF”) with respect to such Holder’s interest in common stock, the electing US holder would be required to include annually in gross income (1) such Holder’s pro rata share of our ordinary earnings, and (2) such Holder’s pro rata share of any of our net capital gain, regardless of whether such income or gain is actually distributed. In general, a US holder may make a QEF election for any taxable year at any time on or before the due date (including extensions) for filing such Holder’s United States federal income tax return for such taxable year. However, Treasury regulations provide that a US holder may be entitled to make a retroactive QEF election for a taxable year after the election’s due date if certain conditions are satisfied. In the event of a determination by us or the Internal Revenue Service that we are a PFIC, we intend to comply with all record-keeping, reporting and other requirements so that US holders, at their option, may maintain a QEF election with respect to us. However, if meeting those record-keeping and reporting requirements becomes onerous, we may decide, in our sole discretion, that such compliance is impractical, and will notify US holders accordingly.

As an alternative to the QEF election, US holders may elect to mark their common stock to its market value (a “mark-to-market election”). If a valid mark-to-market election is made, the electing US holder generally will recognize ordinary income for the taxable year an amount

49

equal to the excess, if any, of the fair market value of their common stock as of the close of such taxable year over the US holder’s adjusted tax basis in the common stock. In addition, the US holder generally is allowed a deduction for the lesser of (1) the excess, if any, of the US holder’s adjusted tax basis in the common stock over the fair market value of the common stock as of the close of the taxable year, or (2) the excess, if any of (A) the mark-to-market gains for the common stock included in gross income by the US holder for prior taxable years, over (B) the mark-to-market losses for common stock that were allowed as deductions for prior tax years.

If we were determined to be a PFIC in any year, a US holder who beneficially owned shares of our common stock during that year would be required to file an annual return on Internal Revenue Service Form 8621 with the Internal Revenue Service that described any distributions received from us and any gain realized by that US holder on the disposition of their shares of our common stock.

The PFIC rules are complex. Accordingly, US holders and prospective US holders of our common stock are strongly urged to consult their own tax advisors concerning the impact of these rules, including the making of QEF or mark-to-market elections, on their investment or prospective investment in our common stock.

F. Dividends and Paying Agents

We have not paid any dividends since our inception and have no plans to pay dividends.

G. Statement of Experts

Our consolidated financial statements as of December 31, 2005 and 2004, and for each of the years in the three year period ended December 31, 2005, have been included herein and in the registration statement, in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Netherland, Sewell & Associates, Inc. have consented to the inclusion in this registration statement of its independent engineering report of our proved reserves as at December 31, 2005.

H. Documents on Display

We have filed this Registration Statement on Form 20-F with the SEC, under the Securities and Exchange Act of 1934, as amended, with respect to our common stock. You may read and copy all or any portion of this registration statement or other information in the SEC’s public reference room at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington D.C. 20549. You can also request copies of these documents upon payment of a duplicating fee, by writing the SEC. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference rooms. The SEC maintains a web site (http://www.sec.gov) that contains all of our filings with the SEC. The documents concerning us may also be viewed at our offices in Dallas, Texas during normal business hours.

I. Subsidiary Information

Not applicable.

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Item 11. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the risk of loss that may impact our financial position, results of operations, or cash flows due to adverse changes in financial market prices, including interest rate risk, foreign currency exchange rate risk, commodity price risk, and other relevant market or price risks. We do not have activities related to derivative financial instruments or derivative commodity instruments. We do hold a portfolio of equity securities resulting from previous business transactions. These securities are susceptible to equity market risk.

The oil and gas industry is exposed to a variety of risks including the uncertainty of finding and recovering new economic reserves, the performance of hydrocarbon reservoirs, securing markets for production, commodity prices, interest rate fluctuations, potential damage to or malfunction of equipment and changes to income tax, royalty, environmental or other governmental regulations. We mitigate these risks to the extent we are able by:

• utilizing competent, professional consultants as support teams to company employees;

• performing careful and thorough geophysical, geological and engineering analyses of each prospect;

• maintaining adequate levels of property liability and other business insurance;

• limiting our prospect operations to the extent appropriate.

Market risk is the possibility that a change in the prices for natural gas, natural gas liquids, condensate and oil, foreign currency exchange rates, or interest rates will cause the value of a financial instrument to decrease or become more costly to settle. We are exposed to commodity price risks, credit risk and foreign currency exchange rates.

Commodities Price Risk. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on year-end 2005 production levers, if 2005 average natural gas prices were to change by $0.50 per mcf, the impact on our earnings and cash flow would have been approximately $40,000; if the 2005 average oil prices were to change by $1.00 per bbl, the impact on our earnings and cash flow would have been approximately $18,000.

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Credit Risk. In addition to market risk, our financial instruments involve, to varying degrees, risk associated with trade credit and risk associated with operatorship of certain properties as well as credit risk related to our customers and trade payables. All of our accounts receivable are with customers or partners and are subject to normal industry credit risk. We do not require collateral or other security to support financial instruments nor do we provide collateral or security to counterparties. Currently, we do not expect non-performance by any counterparty.

Foreign Exchange Risk. Although our functional and reporting currencies are U.S. Dollars, we hold a portion of our cash and short term investments in Canadian Dollar denominated accounts. Therefore, whenever we fund subsidiary company operations, foreign exchange gains or losses are incurred (upon conversion from Canadian to U.S. Dollars). If the average currency exchange rate for 2005 between Canadian and U.S. Dollars were to change by ten percent, the net impact on our earnings and cash flow would have been approximately $19,590 (all exchange costs are paid at the time of exchange).

Interest Rate Risk. Interest rate risk exists principally with respect to our cash invested in short term investments that bears interest at floating rates. At December 31, 2005, we had approximately $2.5 million invested in money market funds which bear interest at floating rates. If average interest rates for 2005 were to change by one full percentage point, the net impact on our earnings and cash flow for 2005 would have been approximately $86,000.

The following table presents our approximate sensitivities to various market risks:

	Estimated 2005 impact on:
Sensitivities	Earnings		Cash Flow
Natural gas - US$0.50/mcf change	$	39,791	$	39,791
Crude oil - $1.00/bbl change	$	17,698	$	17,698
Foreign exchange — 10% change in the F/X Canadian to U.S. $	$	19,590	$	19,590
Interest rate - 1% change (money markets only)	$	86,085	$	86,085

Item 12. Description of Securities Other than Equity Securities

Not applicable.

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PART II.

Item 13. Defaults, Dividend Arrearages and Delinquencies

Not applicable.

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

Item 15. Controls and Procedures

Not applicable.

Item 16. [Reserved]

Item 16(A). Audit Committee Financial Expert

Not applicable.

Item 16(B). Code of Ethics

Not applicable.

Item 16(C). Principal Accountant Fees and Services

Not applicable.

Item 16(D). Exemption from the Listing Standards for Audit Committees

Not applicable.

Item 16(E). Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Not applicable.

PART III.

Item 17. Financial Statements

Independent Auditors’ Report	F-1
Consolidated Balance Sheets as at December 31, 2005 and December 31, 2004	F-2
Consolidated Statements of Operations and Deficit for the Years Ended December 31, 2005, December 31, 2004 and December 31, 2003	F-3
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, December 31, 2004 and December 31, 2003	F-4

53

Notes to Consolidated Financial Statements	F-5
Consolidated Balance Sheets as at March 31, 2006 and March 31, 2005 (Unaudited)	F-24
Consolidated Statements of Operations and Deficit for the Three Months Ended March 31, 2006 and March 31, 2005 (Unaudited)	F-25
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2006 and March 31, 2005 (Unaudited)	F-26
Notes to Consolidated Financial Statements (Unaudited)	F-27

54

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE DIRECTORS OF TRANSATLANTIC PETROLEUM CORP.

We have audited the consolidated balance sheets of TransAtlantic Petroleum Corp. as at December 31, 2005 and 2004 and the consolidated statements of operations and deficit and cash flows for the three years ended December 31, 2005, 2004 and 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2005 and 2004 and the consolidated statements of operations and deficit and cash flows for the three years ended December 31, 2005, 2004 and 2003 in accordance with Canadian generally accepted accounting principles.

Canadian generally accepted accounting principles vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences is presented in Note 13 to the consolidated financial statements.

Chartered Accountants

Calgary, Canada

March 21, 2006, except for Note 13, which is as of August 11, 2006.

F-1

TRANSATLANTIC PETROLEUM CORP.

Consolidated Balance Sheets

December 31, 2005 and 2004

(Thousands of U.S. Dollars)

	2005			2004
Assets
Current assets
Cash and cash equivalents	$	7,567		$	9,650
Short-term investment (note 9)		1,500			1,761
Accounts receivable		780			482
Marketable securities (note 2(a))		92			43
Other current assets		8			42
		9,947			11,978
Restricted cash (note 1)		2,110			2,466
Property and equipment (note 3)		5,813			704
Investments (note 2(b))		1,057			900
	$	18,927		$	16,048
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	924		$	325
Settlement provision (note 10)		1,511			855
		2,435			1,180
Asset retirement obligations (note 4)		556			155
Shareholders’ equity
Share capital (note 5)		20,476			16,518
Warrants (note 5)		3,502			2,670
Contributed surplus (note 5)		1,508			1,302
Deficit		(9,550	)		(5,777	)
		15,936			14,713
Commitments (notes 11 and 12)
Subsequent event (note 12)
	$	18,927		$	16,048

See accompanying notes to consolidated financial statements.

F-2

TRANSATLANTIC PETROLEUM CORP.

Consolidated Statements of Operations and Deficit

Years ended December 31, 2005, 2004 and 2003

(Thousands of U.S. Dollars, except for per share amounts)

	2005			2004			2003
Revenues
Oil and gas sales, net of royalties	$	1,409		$	5,108		$	8,494
Interest income		943			441			534
		2,352			5,549			9,028
Expenses
Lease operating and other production costs		1,918			4,396			7,034
Business development activities (note 3(d))		440			—			—
Depreciation, depletion and accretion		606			718			872
Write down of property and equipment (note 3)		—			1,235			360
General and administrative		2,295			1,823			1,346
Write down of investment (note 2(b))		112			2,100			—
Settlement provision (note 10)		905			600			—
Gain on sale of subsidiary (note 3(b))		(180	)		—			—
Foreign exchange (gain) loss		29			(130	)		—
		6,125			10,742			9,612
Net loss for the year		3,773			5,193			584
Deficit, beginning of year		5,777			584			18,403
Reduction of share capital (note 4)		—			—			(18,403	)
Deficit, end of year		9,550			5,777			584
Loss per share - basic and diluted (note 5)	$	0.11		$	0.17		$	0.02

See accompanying notes to consolidated financial statements.

F-3

TRANSATLANTIC PETROLEUM CORP.

Consolidated Statements of Cash Flows

Years ended December 31, 2005, 2004 and 2003

(Thousands of U.S. Dollars)

	2005			2004			2003
Cash provided by (used in)
Operating activates
Net loss for the year	$	(3,773	)	$	(5,193	)	$	(584	)
Items not involving cash
Gain on sale of subsidiary (note 3(b))		(180	)		—			—
Depreciation, depletion and accretion		606			718			872
Stock-based compensation		410			714			157
Write down of property and equipment		—			1,235			360
Write down of investment		112			2,100			—
Changes in non-cash working capital		1,022			(529	)		254
		(1,803	)		(955	)		1,059
Investing activities
Property and equipment		(4,839	)		(1,706	)		(1,536	)
Proceeds from sale of property and equipment		—			155			164
Proceeds from sale of subsidiary		180			—			—
Restricted cash		356			(32	)		(42	)
Marketable securities		(268	)		—			—
Investments		104			—			(3,000	)
		(4,467	)		(1,583	)		(4,414	)
Financing activities
Issuance of common shares, net		4,187			7,519			—
Repayments of indebtedness		—			—			(2,146	)
		4,187			7,519			(2,146	)
Change in cash and cash equivalents		(2,083	)		4,981			(5,501	)
Cash and cash equivalents, beginning of year		9,650			4,669			10,170
Cash and cash equivalents, end of year	$	7,567		$	9,650		$	4,669
Supplemental cash flow information:
Interest received	$	943		$	411		$	534

See accompanying notes to consolidated financial statements.

F-4

TRANSATLANTIC PETROLEUM CORP.

Notes to Consolidated Financial Statements

Years ended December 31, 2005, 2004 and 2003

(U.S. Dollars)

1. Significant accounting policies

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada which, in the case of TransAtlantic Petroleum Corp. (the “Company”), differ in certain respects from those in the United States. These differences are described in Note 13—“Reconciliation to Accounting Principles Generally Accepted in the United States”. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Actual results could differ from those estimates and assumptions; however, management believes that such differences would not be material.

(a) Property and equipment

The Company uses the full cost method to account for its oil and gas activities. Under this method, oil and gas assets are evaluated at least annually to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties exceed the carrying value of the oil and gas assets. If the carrying value of the oil and gas assets is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are estimated using the future product prices and costs and are discounted using a risk-free rate.

Under the full cost method of accounting, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves in cost centers on a country-by-country basis. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from the sale of oil and gas properties are applied against capitalized costs, and gains or losses are not recognized unless the sale would alter the depletion rate by more than 20%.

The Company computes the provision for depreciation and depletion of oil and gas properties using the unit-of-production method based upon production and estimates of gross proved reserve quantities as determined by independent reservoir engineers. Unevaluated property costs are excluded from the amortization base until the properties associated with these costs are evaluated and determined to be productive or become impaired.

F-5

1. Significant accounting policies (continued)

(a) Property and equipment (continued)

Depreciation of furniture, fixtures and computer equipment and software is provided for on the straight-line basis at rates between three and seven years designed to amortize the cost of the assets over their estimated useful lives.

(b) Asset retirement obligation

The Company records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost, which is depleted on a unit-of production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability and any remaining difference is recognized as a gain or loss to earnings in the period in which the settlement occurs.

(c) Revenue recognition

Revenue from the sale of product is recognized upon delivery to the purchaser when title passes.

(d) Foreign currency translation

The Company translates foreign currency denominated transactions and the financial statements of integrated foreign operations using the temporal method. Assets and liabilities denominated in foreign currencies are translated into U.S. dollars at exchange rates in effect at the balance sheet date for monetary items and at exchange rates in effect at the transaction dates for non-monetary items. Income and expenses are translated at the average exchange rates in effect during the applicable period. Exchange gains or losses are included in operations in the period incurred.

(e) Stock-based compensation

The Company uses the fair value method when stock options are granted to employees and directors under the fixed share option plan. Under this method, compensation expense is measured at the grant date and recognized as a charge to earnings over the vesting period with a corresponding credit to contributed surplus. Upon exercise of the stock options, consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. The fair value of the options is determined using the Black-Scholes option pricing model.

F-6

1. Significant accounting policies (continued)

(f) Income taxes

The Company uses the liability method of accounting for future income taxes. Under the liability method, future income tax assets and liabilities are determined based on “temporary differences” (differences between the accounting basis and the tax basis of the assets and liabilities), and are measured using the currently enacted, or substantively enacted, tax rates and laws expected to apply when these differences reverse. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the asset will not be realized.

(g) Per share information

Basic per share amounts are calculated using the weighted average common shares outstanding during the year. The Company uses the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted earnings per share. Diluted calculations reflect the weighted average incremental common shares that would reflect the weighted average incremental common shares that would be issued upon exercise of dilutive options assuming the proceeds would be used to repurchase shares at average market prices for the period.

(h) Cash and cash equivalents

Cash and cash equivalents include term deposits and investments with original maturities of three months or less.

(i) Restricted cash

Restricted cash represents cash placed in escrow accounts or in certificates of deposit that is pledged for the satisfaction of liabilities or performance guarantees. At December 31, 2005, restricted cash includes: $1.5 million in respect of the settlement of Nigerian liabilities (see note 10) and $591,000 for a guarantee of the Morocco work program (See note 11).

(j) Marketable securities and investments

Marketable securities are stated at the lower of cost or market on a portfolio basis. Investments in companies over which the Company can exercise significant influence are accounted for using the equity method. Other long-term investments are carried at the lower of cost or estimated net realizable value.

F-7

2. Investments

(a) Marketable securities

Pursuant to certain short-term investments made in prior periods, the Company received, in addition to interest, shares in other publicly traded companies. The Company also received shares on the settlement of a claim with a joint venture partner. Pursuant to this settlement, the Company recorded a gain of $65,000 upon receipt of the shares. At December 31, 2005, the Company’s total cost of marketable securities was $92,000 (2004 - $62,000) and had a total quoted market value of $239,000 (2004 - $43,000).

The following table summarizes the marketable securities held at December 31, 2005 and 2004:

Security (all Common)	Number Of Shares December 31,		Cost Basis December 31,				Market Value December 31,
	2005	2004	2005		2004		2005		2004
American Natural Energy Corp. (b)	—	176,128	$	—	$	35,221	$	—	$	21,135
Transco Resources	100,000	100,000		27,000		27,000		111,000		21,602
Tuscany Energy	325,000	—		65,000		—		128,375		—
			$	92,000	$	62,221	$	239,375	$	42,737

(b) Investments

On September 1, 2005, the Company completed the purchase of 2,237,136 shares of American Natural Energy Corporation (“ANEC”) pursuant to ANEC’s private placement dated August 16, 2005. The purchase price was U.S. $268,000 or U.S. $0.12 per share. These shares are carried at their anticipated net realizable value of $0.07 per share (the year-end closing price) as the Company does not anticipate selling these shares in the short term.

In October 2003, the Company acquired $3.0 million of convertible debentures issued by ANEC. The convertible debentures issued by ANEC pay 8% interest, were for a two-year term maturing September 30, 2005 and are secured by all of the assets of ANEC. On June 23, 2005, the debenture holders approved extending the maturity of the debentures to September 20, 2006 and changing the conversion price from $0.43 per share to $0.15 per share. The original $3.0 million investment has been reserved against in order to be presented at its estimated net realizable value. Based upon an analysis of ANEC’s financial position, the Company determined it appropriate to reserve $2.1 million against this investment as at December 31, 2004 and such reserve continued at December 31, 2005. The investment is accounted for using the cost method.

F-8

3. Property and equipment

(Thousands of U.S. Dollars)

2005	Cost		Accumulated depreciation and depletion		Net book value
Crude oil and natural gas properties
United States	$	11,308	$	5,521	$	5,787
Furniture, fixtures and other assets		238		212		26
Balance, December 31, 2005	$	11,546	$	5,733	$	5,813
2004
Crude oil and natural gas properties
United States	$	4,890	$	4,199	$	691
Nigeria		14,436		14,436		—
Furniture, fixtures and other assets		381		368		14
Balance, December 31, 2004	$	19,707	$	19,003	$	704

(a) Property acquisitions:

On April 15, 2005, the Company completed the purchase of an oil and gas property located in Texas. The Company paid $3.0 million cash and issued 500,000 shares and 500,000 warrants exercisable at $1.00 per share on or before March 31, 2007 for the property. The fair value of the warrants was determined using a Black-Scholes pricing model. A purchase equation is provided below:

Consideration:
Cash	$	3,000,000
Common shares		350,000
Warrants		125,434
Acquisition costs		66,630
	$	3,542,064
Assets acquired:
Property and equipment	$	3,892,064
Asset retirement obligations		(350,000	)
	$	3,542,064

F-9

3. Property and equipment (continued)

(b) Sale of subsidiary:

Effective June 20, 2005, the Company sold its Bahamian subsidiary which owned 30% interest in certain properties, offshore Nigeria. In consideration, TransAtlantic received $540,000 prior to disposal costs of $220,000 (including legal, consulting and other deal-related costs) a future contingent cash payment (after two wells have been drilled) of $240,000 and contingent compensation of up to a maximum of $16 million. A bonus equivalent to 3.87% will be paid to the President, if and when this contingent compensation is received by the Company. No amount of contingent consideration has been recognized in these financial statements. The Company paid the President a bonus of $100,000 upon finalization of this agreement (included in general and administrative expense). Of the $2.5 million reserved at December 31, 2004 as an abandonment fund, $1.76 million remained in escrow to address any Nigerian claims relating to the Company’s prior operations in Nigeria, with the balance of approximately $730,000 being released from escrow.

(c) Ceiling test:

Based upon a ceiling test at December 31, 2004, the Company recorded an impairment of $1.2 million related to its United States cost center. This impairment was largely due to dry hole costs incurred at Bayou Couba during the year costing approximately $1.2 million. The Company recorded an impairment of $360,000 related to its United States cost center based upon a ceiling test at December 31, 2003. At December 31, 2005, $491,000 (2004 - $141,000) of asset retirement costs are included in property and equipment. No overhead costs were capitalized and future development costs of $553,000 (2004 and 2003 – nil) were included in the computations of depreciation and depletion for the year. Unproved property costs of $362,000 (2004 and 2003 – nil) were excluded from depletion and depreciation.

F-10

3. Property and equipment (continued)

The following table summarizes the pricing used in the December 31, 2005 ceiling test:

Period ending December 31,	Oil Price ($/BBL)		Gas Price ($/MMBTU)
2006	$	61.37	$	8.81
2007		62.52		8.42
2008		61.67		7.65
2009		60.52		7.37
Thereafter		60.28		7.35

(d) Business development activities:

Throughout 2005, the Company continued significant business development activities in foreign countries including consulting, legal, accounting, travel and other costs necessary to further the Company’s identification and development of business opportunities.

4. Asset retirement obligations

As part of its development of oil and gas opportunities, the Company incurs asset retirement obligations (“ARO”) on its properties. The Company’s ARO results from its responsibility to abandon and reclaim its net share of all working interest properties. At December 31, 2005 the net present value of the Company’s total ARO is estimated to be $556,000 (2004 - $155,000), with the undiscounted value being $958,000 (2004 - $310,000). Payments to settle the obligations are expected to occur continuously over the next 15 years, with the majority of obligations being expected to begin in year six. A discount rate of 10% was used to calculate the present value of the ARO.

	2005		2004
Beginning balance	$	155	$	132
Liabilities incurred		350		9
Accretion expense		51		14
Ending balance	$	556	$	155

F-11

5. Share capital

The following information presented for shares and options issued and outstanding have been adjusted to give effect in the periods presented to the share consolidation (five common shares for one common share) effective in January 2004.

(a) Authorized

Unlimited number of common shares, without par value

(b) Issued

Common shares:

(In thousands)	Number of Shares		Amount
Balance, December 31, 2002	23,831			30,502
Reduction in stated capital – accumulated deficit	—			(18,403	)
Balance, December 31, 2003	23,831		$	12,099
Private placement of common stock	7,635			4,795
Share issue costs	338			(420	)
Stock options exercised	48			44
Balance, December 31, 2004	31,852			16,518
Private placement of common stock	5,000			3,487
Share issue costs	—			(267	)
Stock options exercised	370			389
Issued in conjunction with acquisition (note 3)	500			350
Unconverted shares forfeited	(63	)		—
Balance, December 31, 2005	37,659		$	20,476
Warrants:
(In thousands)	Number of Shares		Amount
Balance, December 31, 2002	—			—
Balance, December 31, 2003	—			—
Issued pursuant to private placement	7,635		$	2,840
Issue costs	—			(170	)
Balance, December 31, 2004	7,635			2,670
Issued in conjunction with acquisition (note 3)	500			133
Issued pursuant to private placement	2,500			762
Issue costs	375			(63	)
Balance, December 31, 2005	11,010		$	3,502

F-12

5. Share capital (continued)

(c) January 2004 private placement

The Company issued 7.635 million Units at $1.00 per Unit. Each Unit consisted of one common share and one warrant entitling the warrant holder to purchase one share of common stock at $1.50 per share on or before January 6, 2006 (the warrants expired unexercised).

The gross proceeds of $7,635,000 were allocated to common shares in the amount of $4,795,000 and to warrants in the amount of $2,840,000. The Company paid a finder’s fee of 337,500 Units which had an estimated fair value of $457,500. In addition to the finder’s fee, $133,000 of legal and filing fees were incurred related to the private placement.

(d) November 2005 private placement

The Company issued 5,000,000 Units at $0.85 per Unit for gross proceeds of $4.25 million. Each Unit consisted of one common share and one half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one common share at a price of $1.05 through November 6^th 2007. If the volume weighted average closing price of the Company’s common shares exceeds $1.40 per share for 20 consecutive trading days, the Company will be entitled to accelerate expiration of the warrants (thereby requiring the warrant holder to exercise the warrant within 30 days of being notified of the accelerated expiration).

In connection with issuance of the Units, the Company paid the Underwriters a commission of $330,000 and issued to the Underwriters 375,000 broker warrants with an estimated fair value of $83,000 exercisable on the same terms as the purchase warrants.

(e) Option Grant

On May 6, 2005, the Company granted an employee 125,000 stock purchase options. On October 11, 2005, the Company granted to various employees and directors a total of 595,000 stock purchase options. All of the options were granted pursuant to the Company’s Stock Option Plan with the following terms: i) immediate vesting; ii) five year term; iii) exercisable at $0.71 and $0.90 per share, respectively. Based upon these terms, a Black Scholes pricing model derives a fair value for the grants of approximately $410,000 recognized as stock-based compensation expense.

(f) Reduction of stated capital

At the 2003 Annual and Special Shareholders Meeting on June 2, 2003, the shareholders of the Company adopted a special resolution to reduce the stated capital of the common shares by $18.4 million and, as a result, the deficit of the Company was reduced by the same amount.

F-13

5. Share capital (continued)

The estimated fair value of share options issued during the periods was determined using the Black-Scholes option-pricing model with the following assumptions:

Option Value Inputs	2005		2004		2003
Risk free interest rate	5.3	%	5.3	%	2.6	%
Expected option life	5 Years		5 Years		5 Years
Volatility in the price of the Company’s shares	80.0	%	81.0	%	84.0	%
Dividend yield	0.0	%	0.0	%	0.0	%

(g) Per share amounts

A total of 219,195 shares were added to the weighted average number of common shares outstanding during the year ended December 31, 2005 (2004 – 475,538; 2003 – 502,008) for the dilutive effect of employee stock options. No adjustments were required to reported earnings in computing diluted per share amounts. A total of 1,240,000 (2004 – 763,000; 2003 – 282,000) options were excluded from the diluted calculations as the Company had a net loss which causes them to be anti-dilutive. Basic per common share amounts were calculated using a weighted average number of common shares outstanding for 2005 of 33,023,412 (2004 – 30,908,065; 2003 – 23,802,595).

(h) Contributed Surplus

(In thousands)	2005			2004
Beginning balance	$	1,302		$	157
Increase from stock option grants		410			714
Transfer to share capital on option exercise		(204	)		(26	)
Share and warrant issue costs		—			457
Ending balance	$	1,508		$	1,302

F-14

5. Share capital (continued)

(i) Stock option plan

The Company has a Stock Option Plan under which 2,762,000 common shares were reserved for issuance as at December 31, 2005. All options presently issued under the Plan have a five-year expiry. Details of the Company’s plan as at December 31, 2005 and 2004 are presented below.

	2005				2004
(Shares in thousands)	Number of options		Weighted average exercise price		Number of options		Weighted average exercise price
Outstanding at beginning of year	2,543		$	0.70	1,525		$	0.62
Granted	720			0.87	1,285			0.83
Expired	(353	)		0.83	(219	)		0.88
Exercised	(370	)		0.50	(48	)		0.35
Outstanding at end of year	2,540		$	0.76	2,543		$	0.70
Exercisable at end of year	2,540		$	0.76	2,543		$	0.70

The following table summarizes information about stock options as at December 31, 2005 (Shares in thousands):

Options Outstanding					Options Exercisable
Range of Prices			Number Outstanding	Weighted- average remaining contractual Life	Weighted- average exercise price		Number Exercisable	Weighted - average exercise price
Low	High
				(years)
$0.35	$	0.35	380	0.87	$	0.35	380	$	0.35
0.70		1.00	2,160	3.82		0.83	2,160		0.83
$0.35	$	1.00	2,540	3.38	$	0.76	2,540	$	0.76

F-15

6. Income taxes

The income tax provision differs from the amount that would be obtained by applying the Canadian basic federal and provincial income tax rate to net loss for the year as follows:

(Thousands of U.S. Dollars)	2005			2004			2003
Statutory tax rate		37.62	%		38.62	%		40.6	%
Expected income tax reduction	$	(1,419	)	$	(2,006	)	$	(237	)
Increase (decrease) resulting from
Stock-based compensation		154			276			64
Change in enacted tax rates		—			588			158
Change in valuation allowance		1,265			1,142			15
	$	—		$	—		$	—

The components of the net future income tax asset at December 31, 2005 and 2004 is as follows:

(Thousands of U.S. Dollars)	2005			2004
Future income tax assets
Property and equipment	$	46		$	655
Operating loss carry-forwards		7,679			4,954
Capital loss carry-forwards		576			—
Share issue costs		208			444
Investments		396			—
Valuation allowance		(8,905	)		(6,053	)
Net future income tax asset	$	—		$	—

The Company and its wholly owned subsidiaries have accumulated losses or resource related deductions available for income tax purposes in Canada and the United States. No recognition has been given in these consolidated financial statements to the future benefits that may result from the utilization of these losses for income tax purposes. The Company has non-capital tax losses in Canada of approximately $1.9 million which expire commencing in 2006 and non-capital tax losses in the United States of approximately $18.1 million which expire commencing in 2008. The Company has capital tax losses in Canada of approximately $3.4 million which have no expiry date.

F-16

7. Segment information

As at December 31, 2005, the Company and its subsidiaries operate in one reportable segment, the exploration for and the development and production of crude oil and natural gas. Identifiable assets, revenues and net loss in each of its geographic areas are as follows:

2005 (Thousands of U.S. Dollars)	Identifiable assets (liabilities)			Revenues		loss
United States	$	11,094		$	1,398	$	2,922
Morocco		644			9		67
Corporate assets		7,189			945		784
	$	18,927		$	2,352	$	3,773
2004
United States	$	3,880		$	797	$	2,288
Canada		(134	)		389		2,367
Nigeria		198			4,364		538
Corporate assets		12,106			—		—
	$	16,048		$	5,549	$	5,193
2003
Nigeria	$	52		$	7,744	$	(81	)
United States		4,203			1,037		787
Canada		1,044			247		(123	)
Corporate assets		7,092			—		—
	$	12,391		$	9,028	$	584

8. Financial instruments

The fair value of the Company’s financial instruments at December 31, 2005 of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable and accrued liabilities approximate their fair values.

9. Related party transactions

(a) In 2005, the Company made investments (in unrelated parties) in loan syndications through a Canadian merchant bank in the amount of $1.5 million (2004 - $3.2 million). As of December 31, 2005, the Company has accrued $395,000 in interest from this investment (2004 - $149,000). All principal and interest on this investment was paid to the Company in March, 2006. During 2003, the Company paid an affiliate of a director of the Company a total of $90,000 (2002 – $82,500) to provide head office services and financial and administrative consulting services.

F-17

During February 2003, the Company made short-term, secured, interest-bearing investments aggregating $2.1 million in three loan syndications made by a Canadian merchant banking corporation. At December 31, 2003, $0.8 million remained invested. Interest income attributable to these investments was $249,000 for 2003. The Company also was issued common shares in two companies pursuant to these investments, which are reflected in marketable securities at December 31, 2003. The Company and the Canadian merchant-banking corporation have two directors in common.

(b) At December 31, 2005, a director of the Company was also a director of ANEC (see notes 2 and 3). During 2005 and 2004, the Company received or made the following payments to (from) ANEC:

(in thousands)	2005			2004			2003
Receipts from ANEC:
Proceeds from oil & gas sales	$	702		$	796		$	635
Redemption of production payment		—			—			1,673
Interest on debentures		240			240			47
Payments to ANEC:
Drilling advances		(423	)		(1,418	)		(425	)
Joint lease operations expenses		(356	)		(207	)		(269	)
Purchase of production payment		—			—			(1,800	)
Purchase of debenture		—			—			(3,000	)
	$	163		$	(589	)	$	(3,139	)

These transactions have been recorded at the exchange amount being the amount agreed to between the related parties. (see note 3(b)).

10. Settlement provision

In conjunction with the sale of the Company’s Nigerian subsidiaries effective June 20, 2005, the Company deposited $1.76 million into an escrow fund to address any Nigerian liabilities and claims relating to the Company’s operations in Nigeria over the past 10 years. The Company has reached agreement with respect to years 1998 through 2001 in the amount of $226,000 (plus associated settlement expenses of approximately $25,000) which was paid out of the escrow account during 2005. Years 2002 through the date of sale in June 2005 remain to be resolved. Management believes the escrow fund provides adequate provision for the liabilities related to the Company’s Nigerian activities during these periods. At the time of the sale, the reserve of $855,000 was increased to $1.76 million (the amount deposited into escrow), and the charge for the increase to the reserve was included in earnings. At December 31, 2005, the remaining restricted cash fully provides for the settlement provision (see note 12).

F-18

11. Commitments

As part of the Company’s June 2005 award of a reconnaissance license in Morocco, the Company committed to a work program that will involve the reprocessing of seismic and other technical work over the property. The Company’s portion of the work commitment is estimated to cost $0.6 million and is required to be completed by June 2007. The exclusive license is for a term of one year. The Company has the right to extend the license for an additional year or, based upon the work program, to convert it to a three year petroleum agreement.

The Company posted a $591,000 certificate of deposit pursuant to a guarantee of the work program and is included in restricted cash at December 31, 2005.

The Company has entered into an operating lease in respect of its office premises. The minimum payments under this lease commitment, including estimated operating costs are as follows:

(in thousands)
2006	$	85
2007	$	87
2008	$	44
Total	$	216

12. Subsequent events

(a) On February 16, 2006, the Company announced that it had been awarded three production licenses in Romania. The Company expects to spend less than $1.0 million in 2006 on technical analysis and environmental impact studies.

(b) On March 1, 2006, tax returns were filed with the Nigerian taxing authorities with respect to years 2001 through 2004 in the amount of $482,000 (plus associated expenses of $68,000). Accordingly, a total of $550,000 was paid out of the escrow account to reflect this settlement.

(c) On March 10, 2006, the Company announced a non-binding letter of intent with ANEC to sell the Company’s interests in the Bayou Couba properties as well as the ANEC 8% Convertible Secured Debentures in the principal amount of $3.0 million (carried at $900,000) held by TransAtlantic. The letter of intent stipulates that ANEC will pay TransAtlantic a total of $3.8 million cash for both the Bayou Couba properties and the Debentures. The agreement is subject to ANEC securing financing, definitive terms and final approval by the boards of directors of both companies.

F-19

13. Reconciliation to Accounting Principles Generally Accepted in the United States

The Company’s consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). The Company’s accounting policies do not differ materially from accounting principles generally accepted in the United States (“U.S. GAAP”) except for the following:

(a) Comprehensive Income

Comprehensive income is recognized and measured under U.S. GAAP pursuant to SFAS No. 130, “Reporting Comprehensive Income”. Under U.S. GAAP, comprehensive income is defined as all changes in equity other than those resulting from investments by owners and distributions to owners. Comprehensive income is comprised of two components, net income (loss) and other comprehensive income. Other comprehensive income includes the unrealized holding gains and losses on the available-for-sale securities.

(b) Marketable Securities

Under accounting principles generally accepted in Canada, marketable securities are stated at the lower of cost or market. Under U.S. GAAP, investments classified as available for sale securities are recorded at market value and the unrealized gains and losses are recorded as comprehensive income and accumulated other comprehensive income within the shareholder’s equity section of the balance sheet unless impairments are considered other than temporary.

(c) Oil and Gas Properties

Under Canadian GAAP the ceiling test is performed by comparing the carrying value of the cost centre based on the sum of the undiscounted cash flows expected from the cost centre’s use and eventual disposition. If the carrying value is unrecoverable, the cost centre is written down to its fair value using the expected present value approach of proved plus probable reserves using future prices. Under U.S. GAAP, companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and gas reserves using a discount factor of 10 percent. Prices used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable year-end. There was no material difference arising out of the differences in prices. At December 31, 2003 and 2004, the Company recognized a U.S. GAAP ceiling test write down of $502 thousand before and after tax and $1,481 thousand before and after tax respectively. Depletion expense for the years ended December 31, 2004 and 2005 for U.S. GAAP is reduced by $131 thousand before and after tax and $51 thousand before and after tax respectively.

(d) Deficit Elimination

As a result of the reorganization of the capital structure which occurred in 2003, the deficit of TransAtlantic Petroleum Corp. of $18,403 thousand was eliminated. Elimination of the deficit would not be permitted under U.S. GAAP.

(e) Stock based compensation

Under Canadian GAAP, the Company follows the fair value method of accounting for stock based compensation. Effective January 1, 2003, the Company also adopted SFAS No. 123, “Accounting for stock-based compensation” under the prospective transition methodology described in SFAS No. 148. Accordingly, there is no difference between Canadian GAAP and U.S. GAAP in relation to accounting for stock-based compensation.

(f) Recently Issued United States Accounting Standards

Inventory Costs: The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) 151, Inventory Costs. This statement amends accounting Research Bulletin (ARB) 43 to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) should be recognized as current-period charges and requires the allocation of fixed production overhead to inventory based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The adoption of this statement will not have any material impact on results of our operations or financial position.

Share-based Payments: The FASB issued SFAS 123(R), Share-Based Payments, which replaces SFAS 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion 25, Accounting for Stock Issued to Employees. It requires compensation costs related to share-based payment transactions to be recognized as an expense at fair value with remeasurement to fair value each period. The compensation expense is recognized over the period that an employee provides service in exchange for the award with forfeitures estimated at each period end. This Statement is effective for interim or annual reporting periods beginning after December 15, 2005. Application is to be on a modified retrospective or modified-prospective basis of transition for new or modified awards and to unvested awards. Restatement of prior periods under the modified-retrospective approach is optional. The Company is currently assessing the impact of these new requirements on the Consolidated Financial Statements.

F-20

Exchanges of Nonmonetary Assets: The FASB issued SFAS 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29, Accounting for Nonmonetary Transactions. This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under Statement 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. This statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. The adoption of this statement will not have any material impact on our Consolidated Financial Statements.

Accounting for Changes and Error Corrections: The FASB issued SFAS 154, Accounting Changes and Error Corrections, which replaces APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements and changes the requirements for the accounting and reporting of a change in accounting principles. The Statement applies to all voluntary changes in accounting principles as well as changes required by an accounting pronouncement unless the pronouncement includes specific transition provisions. The Statement requires the retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Application is on a prospective basis and is effective for changes in accounting principles made in fiscal years beginning after December 15, 2005. The change, which harmonizes United States GAAP with Canadian GAAP, will affect the reporting of future changes in accounting principles under United States GAAP.

Purchase and Sales of Inventory with the Same Counterparty: The EITF issued EITF Abstract 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The Abstract provides accounting guidance where an entity may sell inventory to another entity in the same line of business from which it also purchases inventory. It prescribes under what circumstances these exchanges with the same counterparty would be viewed as a single nonmonetary transaction and whether they would be accounted for at fair value or carrying value. The Abstract is applicable to transactions completed in reporting periods beginning after March 15, 2006, whether pursuant to arrangements that were in place at the date of initial application of the Abstract or arrangements executed subsequent to that date. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of the Abstract.

The effects of the differences between Canadian GAAP and U.S. GAAP on the consolidated statement of operations and deficit would be as follows:

	Years ended December 31,
(Thousands of U.S. dollars other then share and per share amounts)	2005			2004			2003
Net loss under Canadian GAAP	$	3,773		$	5,193		$	584
Additional write-down of property and equipment (c)		—			246			142
Depletion and depreciation (c)		(51	)		(131	)		—
Unrealized gain (loss) on marketable securities (b)		—			(19	)		—
Net loss under U.S. GAAP		3,722			5,289			726
Unrealized (loss) gain on marketable securities (b)		(147	)		19			(259	)
Comprehensive net loss under U.S. GAAP	$	3,575		$	5,270		$	467
Basic and diluted net loss under U.S. GAAP	$	0.11		$	0.17		$	0.03
Shares used in the computation of basic and diluted net loss per share		33,023,412			30,908,065			23,830,882

F-21

After differences discussed above have been adjusted for, the condensed balance sheets under Canadian and U.S. GAAP would be:

	December 31, 2005						December 31, 2004
(Thousands of U.S. dollars)	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Current assets (b)	$	9,947		$	10,094		$	11,978		$	11,978
Restricted cash		2,110			2,110			2,466			2,466
Property and equipment (c)		5,813			5,607			704			447
Long-term investments		1,057			1,057			900			900
		18,927			18,868			16,048			15,791
Current liabilities		2,435			2,435			1,180			1,180
Asset retirement obligations		556			556			155			155
Share capital (d)		20,476			38,879			16,518			34,921
Warrants		3,502			3,502			2,670			2,670
Contributed surplus		1,508			1,508			1,302			1,302
Deficit (b)(c)(d)		(9,550	)		(28,140	)		(5,777	)		(24,418	)
Accumulated other comprehensive
Income (Loss) (c)		—			128			—			(19	)
		18,927			18,868			16,048			15,791

After differences discussed above have been adjusted for, the condensed statements of Deficit and Accumulated Other Comprehensive Income (Loss) under Canadian and U.S. GAAP would be:

	December 31, 2005					December 31, 2004
(Thousands of U.S. dollars)	Canadian GAAP		U.S. GAAP			Canadian GAAP		U.S. GAAP
Deficit, beginning of year	$	5,777	$	24,418		$	584	$	19,129
Net loss		3,773		3,722			5,193		5,289
Deficit, end of year		9,550		28,140			5,777		24,418
Accumulated, other comprehensive
Income (Loss), beginning of year		—		(19	)		—		259
Unrealized gain (loss) on marketable securities		—		147			—		(278	)
Accumulated other comprehensive
Income (Loss), end of year		—		128			—		(19	)

F-22

Interim Consolidated Financial Statements of

TRANSATLANTIC PETROLEUM CORP.

Three Months Ended March 31, 2006 and 2005

UNAUDITED

F-23

TRANSATLANTIC PETROLEUM CORP.

Interim Consolidated Balance Sheets

(Thousands of U.S. Dollars)

	March 31, 2006			Dec. 31, 2005
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	8,048		$	7,567
Short-term investment		—			1,500
Accounts receivable		371			780
Marketable securities (note 2(a))		92			92
Other current assets		136			8
		8,647			9,947
Restricted cash (note 1)		1,560			2,110
Property and equipment (note 3)		5,943			5,813
Investments (note 2(b))		1,057			1,057
	$	17,207		$	18,927
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	854		$	924
Settlement provision (note 9)		961			1,511
		1,815			2,435
Asset retirement obligations (note 4)		570			556
Shareholders’ equity
Share capital (note 5)		20,490			20,476
Warrants (note 5)		819			3,502
Contributed surplus (note 5)		4,191			1,508
Deficit		(10,678	)		(9,550	)
		14,822			15,936
Contingency (note 9)
Commitment (note 10)
	$	17,207		$	18,927

See accompanying notes to consolidated financial statements.

Approved by the Board of Directors:

“Brian Bayley”	Director
“Michael Winn”	Director

F-24

Transatlantic Petroleum Corp.

Interim Consolidated Statements of Operations and Deficit

(Unaudited)

(Thousands of U.S. Dollars, except for per share amounts)

	Three months ended March 31,
	2006			2005
Revenues
Oil and gas sales, net of royalties	$	556		$	282
Expenses
Lease operating expenses and other production costs		533			130
Depreciation, depletion and accretion		265			176
General and administrative		602			394
Oil and gas exploration activities		512			—
Foreign exchange gain		(3	)		(133	)
Other income		—			(54	)
Interest income		(225	)		(126	)
		1,684			387
Net loss for the period		1,128			105
Deficit, beginning of period		9,550			5,777
Deficit, end of period	$	10,678		$	5,882
Loss per share - basic and diluted (note 5)	$	0.03		$	—

See accompanying notes to consolidated financial statements.

F-25

Transatlantic Petroleum Corp.

Interim Consolidated Statements of Cash Flows

(Unaudited)

(Thousands of U.S. Dollars)

	Three months ended March 31,
	2006			2005
Cash provided by (used in)
Operating activities
Net loss for the period	$	(1,128	)	$	(105	)
Items not involving cash
Depreciation, depletion and accretion		265			176
Changes in non-cash working capital		761			(261	)
		(102	)		(190	)
Investing activities
Exploration and acquisition of property and equipment, net		(381	)		(372	)
Investment in loan syndications		1,500			(1,500	)
Restricted cash		(550	)		(15	)
		569			(1,887	)
Financing activities
Warrant exercises		14			—
Change in cash and cash equivalents		481			(2,077	)
Cash and cash equivalents, beginning of period		7,567			9,650
Cash and cash equivalents, end of period	$	8,048		$	7,573

See accompanying notes to consolidated financial statements.

F-26

TRANSATLANTIC PETROLEUM CORP.

Notes to Consolidated Financial Statements - Unaudited

Three months ended March 31, 2006 and 2005

(U.S. Dollars)

1. Significant accounting policies

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada and include the accounts of TransAtlantic Petroleum Corp. (the “Company”) and its wholly owned subsidiaries. The interim consolidated financial statements of the Company have been prepared by management following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2005. Readers are referred to the significant accounting policies as outlined in the Notes to the financial statements for the year ended December 31, 2005. These interim financial statements should be read in conjunction with the financial statements for the year ended December 31, 2005. These interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim period presented.

The preparation of financial statements in conformity with generally accepted accounting principles in Canada requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Actual results could differ from those estimates and assumptions; however, management believes that such differences would not be material.

(a) Restricted cash

Restricted cash represents cash placed in escrow accounts or in certificates of deposit that is pledged for the satisfaction of liabilities or performance guarantees. At March 31, 2006, restricted cash includes: $969,000 in respect of the settlement of Nigerian liabilities (see note 9) and $591,000 for a guarantee of the Morocco work program (see note 10).

F-27

2. Investments

(a) Marketable securities

Pursuant to certain short-term investments made in prior periods, the Company received, in addition to interest, shares in another publicly traded company. The Company also received shares on the settlement of a claim with a joint venture partner.

The following table summarizes the marketable securities held at March 31, 2006 and 2005:

Security (all Common)	Number Of Shares March 31,		Cost Basis March 31,				Market Value March 31,
	2006	2005	2006		2005		2006		2005
Transco Resources	100,000	100,000		27,000		27,000		90,000		106,000
Tuscany Energy	325,000	—		65,000		—		103,000		—
			$	92,000	$	27,000	$	193,000	$	106,000

(b) Investments

On September 1, 2005, the Company completed the purchase of 2,237,136 shares of American Natural Energy Corporation (“ANEC”) pursuant to ANEC’s private placement dated August 16, 2005. The purchase price was U.S. $268,000 or U.S. $0.12 per share. These shares were written down to their anticipated net realizable value of $0.07 per share as of December 31, 2005 and are carried at that value as of March 31, 2006. The Company does not anticipate selling these shares in the short term.

In October 2003, the Company acquired $3.0 million of convertible debentures issued by ANEC. The convertible debentures issued by ANEC pay 8% interest, were for a two-year term maturing September 30, 2005 and are secured by all of the assets of ANEC. On June 23, 2005, the debenture holders approved extending the maturity of the debentures to September 20, 2006 and changing the conversion price from $0.43 per share to $0.15 per share. The original $3.0 million investment has been reserved against in order to be presented at its estimated net realizable value. Based upon an analysis of ANEC’s financial position, the Company reserved $2.1 million against this investment as at December 31, 2004 and such reserve continued at March 31, 2006. The investment is accounted for using the cost method.

F-28

3. Property and equipment

2006	Cost		Accumulated depreciation and depletion		Net book value
Crude oil and natural gas properties
United States	$	11,688	$	5,771	$	5,917
Furniture, fixtures and other assets		238		212		26
Balance, March 31, 2006	$	11,926	$	5,983	$	5,943
2005
Crude oil and natural gas properties
United States	$	11,308	$	5,521	$	5,787
Furniture, fixtures and other assets		238		212		26
Balance, December 31, 2005	$	11,546	$	5,733	$	5,813

(a) At March 31, 2006, $490,000 (2005 - $141,000) of asset retirement costs are included in property and equipment. No overhead costs were capitalized and future development costs of $553,000 (2005 - nil) are included in the computations of depreciation and depletion for the three months ended March 31, 2006 or 2005. Unproved property costs of $362,000 (2005 - nil) were excluded from the depletion and depreciation calculation.

4. Asset retirement obligations

As part of its development of oil and gas opportunities, the Company incurs asset retirement obligations (“ARO”) on its properties. The Company’s ARO results from its responsibility to abandon and reclaim its net share of all working interest properties. At March 31, 2006 the net present value of the Company’s total ARO is estimated to be $570,000 (2005 - $159,000), with the undiscounted value being $932,000 (2004 - $328,000). Payments to settle the obligations are expected to occur continuously over the next 15 years, with the majority of obligations expected to commence in year five. A discount rate of 10% was used to calculate the present value of the ARO.

	Three Months ended March 31, 2006		Year ended December 31, 2005
Beginning balance	$	556	$	155
Liabilities incurred		—		350
Accretion expense		14		51
Ending balance	$	570	$	556

5. Share capital

(a) Authorized

Unlimited number of common shares, without par value

F-29

(b) Issued

Common shares:

(In thousands)	Number of Shares		Amount
Balance, December 31, 2004	31,852		$	16,518
Private placement of common stock	5,000			3,487
Share issue costs	—			(268	)
Stock options exercised	370			389
Issued in conjunction with acquisition	500			350
Share forfeiture – unconverted shares	(63	)		—
Balance, December 31, 2005	37,659			20,476
Warrants exercised	13			14
Balance, March 31, 2006	37,672		$	20,490
Warrants:
(In thousands)	Number of Shares		Amount
Balance, December 31, 2004	7,972		$	2,670
Issued in conjunction with acquisition	500			133
Issued pursuant to private placement	2,500			762
Issue costs	375			(63	)
Balance, December 31, 2005	11,347			3,502
Warrant expiration	(7,972	)		(2,670	)
Warrants exercised	(13	)		(13	)
Balance, March 31, 2006	3,362		$	819

(c) November 2005 private placement

The Company issued 5,000,000 Units at $0.85 per Unit for gross proceeds of $4.25 million. Each Unit consisted of one common share and one half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one common share at a price of $1.05 through November 6^th 2007. If the volume weighted average closing price of the Company’s common shares exceeds $1.40 per share for 20 consecutive trading days, the Company will be entitled to accelerate expiration of the warrants (thereby requiring the warrant holder to exercise the warrant within 30 days of being notified of the accelerated expiration).

In connection with issuance of the Units, the Company paid the Underwriters a commission of $330,000 and issued to the Underwriters 375,000 broker warrants with an estimated fair value of $83,000 exercisable on the same terms as the purchase warrants.

(d) Per share amounts

Basic per common share amounts were calculated using a weighted average number of common shares outstanding for the three months ended March 31, 2005 of 37,663,355 (2005 – 32,146,637). No adjustments were required to reported earnings or number of shares in computing diluted per share amounts as the net loss would make these shares anti-dilutive.

F-30

(e) Stock option plan

The Company has a Stock Option Plan under which 2,762,000 million common shares were reserved for issuance and 2,515,000 million share purchase options at a weighted average strike price of $0.76 per share were issued and outstanding at March 31, 2006. All options presently issued under the Plan have a five-year expiry.

(f) Contributed surplus

(thousands of dollars)	Three months ended March 31, 2006		Year ended December 31, 2005
Beginning balance	$	1,508	$	1,302
Increase from stock option grants		—		410
Transfer to share capital on option exercise		—		(204	)
Transfer from share capital on warrant exercise		14		—
Transfer from warrants on warrant expiration		2,669
Ending balance	$	4,191	$	1,508

F-31

6. Segment information

As of March 31, 2006, the Company and its subsidiaries operate in one reportable industry segment, the exploration for and the development and production of crude oil and natural gas. Identifiable assets, revenues and net loss in each of its geographic areas are as follows:

March 31, 2006 (Thousands of U.S. Dollars)	Identifiable assets (liabilities)		Revenues		Net loss
United States	$	16,519	$	556	$	942
Morocco		688		—		186
	$	17,207	$	556	$	1,128
December 31, 2005
United States	$	11,094	$	1,398	$	2,922
Morocco		644		9		67
Corporate Assets		7,189		945		784
	$	18,927	$	2,352	$	3,773

7. Financial instruments

The fair value of the Company’s financial instruments at March 31, 2006 of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their fair values.

8. Related party transactions

During the first quarter 2006, the Company received net payments (oil and gas sales plus debenture interest less drilling advances and lease operating expenses) of $69,000 (2005 – $145,000) from ANEC. These transactions have been recorded at the exchange amount being the amount agreed to between the related parties. At March 31, 2006, a director of the Company was also a director of ANEC (see note 2).

F-32

9. Settlement provision

In conjunction with the sale of the Company’s Nigerian subsidiaries effective June 20, 2005, the Company deposited $1.76 million into an escrow fund to address any Nigerian liabilities and claims relating to the Company’s operations in Nigeria over the past 10 years. With respect to years 1998 through 2004, the amount of $776,000 was paid out of the escrow account in the third quarter 2005 and first quarter 2006 for taxes related to those years. Year 2005 through the date of sale remains to be addressed. Management believes the escrow fund provides adequate provision for the liabilities related to the Company’s Nigerian activities.

10. Commitment

As part of the Company’s June 2005 award of a reconnaissance license in Morocco, the Company committed to a work program that will involve the reprocessing of seismic and other technical work over the property. The Company’s portion of the work commitment is estimated to cost $0.7 million and is required to be completed by December 2006. The Company has the right, based upon the work program, to convert the reconnaissance license to a three year petroleum agreement.

The Company posted a $591,000 certificate of deposit pursuant to a guarantee of the work program and is included in restricted cash at March 31, 2006.

F-33

Item 18. Financial Statements

Not Applicable.

Item 19. Exhibits

See Exhibit Index.

55

Signatures

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

TransAtlantic Petroleum Corp.
By:	/s/ Christopher H. Lloyd
	Christopher H. Lloyd
	Chief Financial Officer

Date: August 14, 2006

56

INDEX TO EXHIBITS

Exhibit Numbers	EXHIBITS
1.1	Certificate and Articles of Continuance dated June 10, 1997
1.2	Certificate and Articles of Amendment dated December 12, 1998
1.3	Certificate and Articles of Amalgamation dated January 1, 1999
1.4	By-law No. 1 dated June 2, 1997
4.1	Executive Employment Agreement dated effective July 1, 2005 by and between TransAtlantic Petroleum Corp. and Scott C. Larsen
4.2	Executive Employment Agreement dated effective May 1, 2005 by and between TransAtlantic Petroleum Corp. and Christopher H. Lloyd
4.3	Participating Interest Agreement dated effective July 11, 2005 by and among TransAtlantic Worldwide Ltd., TransAtlantic Petroleum Corp. and Scott C. Larsen
4.4	Amended and Restated Stock Option Plan (2006)
4.5	Warrant Indenture dated November 17, 2005 by and between TransAtlantic Petroleum Corp. and Computershare Trust Company of Canada
15.1	Consent of KPMG LLC

57