20FR12G/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F/A

Amendment No. 1

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 – 42,556,939 as of December 31, 2006.

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

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	10
Item 4A.	Unresolved Staff Comments	24
Item 5.	Operating and Financial Review and Prospects	25
Item 6.	Directors, Senior Management and Employees	31
Item 7.	Major Shareholders and Related Party Transactions	35
Item 8.	Financial Information	36
Item 9.	The Offer and Listing	36
Item 10.	Additional Information	38
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 12.	Description of Securities Other than Equity Securities	46
	Part II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	46
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	46
Item 15.	Controls and Procedures	46
Item 16.	[Reserved]	46
Item 16(A).	Audit Committee Financial Expert	46
Item 16(B).	Code of Ethics	46
Item 16(C).	Principal Accountant Fees and Services	47
Item 16(D).	Exemption from the Listing Standards for Audit Committees	47
Item 16(E).	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	47
	Part III.
Item 17.	Financial Statements	47
Item 18.	Financial Statements	47
Item 19.	Exhibits	47

PART I.

Item 1. Identity of Directors, Senior Management and Advisers

A. Directors and Senior Management

Name	Business Address	Functions
Michael D. Winn	Suite 1840, 444 – 5th Avenue., S.W. Calgary, Alberta T2P 2T8	Director
Brian B. Bayley	Suite 1840, 444 – 5th Avenue, S.W. Calgary, Alberta T2P 2T8	Director
Alan C. Moon	Suite 1840, 444 – 5th Avenue, S.W. Calgary, Alberta T2P 2T8	Director
Scott C. Larsen	5910 N. Central Expressway, Suite 1755 Dallas, Texas 75206	President, Chief Executive Officer and Director
Hilda Kouvelis	5910 N. Central Expressway, Suite 1755 Dallas, Texas 75206	Vice President and Chief Financial Officer

B. Advisers

Name	Business Address	Position
Macleod Dixon LLP	3700 Canterra Tower 400 3rd Avenue, S.W. Calgary, Alberta T2P 4H2	Canadian legal counsel
Haynes and Boone LLP	901 Main Street Suite 3100 Dallas, Texas 75202	U.S. legal counsel

C. Auditors

Name	Business Address	Professional Body Membership
KPMG LLP	Suite 2700, Bow Valley Square II 205 – 5th Avenue, S.W. 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, 2006 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.

The selected financial data for the years ended December 31, 2006, 2005 and 2004 was derived from our financial statements, which have been audited by KPMG LLP, Chartered Accountants, as indicated in their

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audit report which is included elsewhere in this registration statement. The selected financial data for the six months ended June 30, 2007 and 2006 was derived from our interim financial statements, which are unaudited.

Preparing U.S. GAAP selected financial data for the years ended December 31, 2003 and 2002 would require significant time and expenditures by us. In addition, due to the length of time that has elapsed, we do not believe such financial information is material to investors. As a result, selected financial data under U.S. GAAP for the years ended December 31, 2003 and 2002 are not included in this registration statement.

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 and share data)

	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005			2004			2003			2002
Revenue	$	342		$	1,001		$	1,613		$	1,409		$	5,108		$	8,494		$	36,531
Net income (loss)		(3,095	)		(2,559	)		(9,413	)		(3,773	)		(5,193	)		(584	)		5,957
Net income (loss) per share basic and diluted		(0.07	)		(0.07	)		(0.25	)		(0.11	)		(0.17	)		(0.02	)		0.25
Cash dividends per share	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Weighted average shares (000’s)		42,830			38,182			38,182			33,023			30,908			23,831			23,803
Ending shares outstanding (000’s)		43,131			37,937			42,557			37,659			31,852			23,831			23,831
Total assets	$	14,746		$	16,306		$	15,392		$	18,927		$	16,048		$	12,391		$	14,504
Long term liabilities		2,037			584			1,939			556			155			132			—
Shareholders’ equity		8,152			13,783			10,502			15,936			14,713			11,672			12,099
Capital expenditures		4,123			1,870			4,737			4,839			1,706			1,409			462

Selected Financial Data Presented According to U.S. GAAP

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

	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005			2004
Revenue	$	342		$	1,001		$	1,613		$	1,409		$	5,108
Comprehensive net income (loss)		(5,864	)		(2,433	)		(10,836	)		(3,575	)		(5,567	)
Net income (loss) per share basic and diluted		(0.14	)		(0.07	)		(0.28	)		(0.11	)		(0.17	)
Cash dividends per share	$	—		$	—		$	—		$	—		$	—
Weighted average shares (000’s)		42,830			38,182			38,182			33,023			30,908
Ending shares outstanding (000’s)		43,131			37,937			42,557			37,659			31,852
Total assets	$	10,495		$	16,116		$	13,910		$	18,868		$	15,791
Long term liabilities		2,037			584			1,939			556			155
Shareholders’ equity		3,901			13,593			9,020			15,877			14,456
Capital expenditures		4,123			1,870			4,737			4,839			1,706

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B. Capitalization and Indebtedness

The following table sets forth our capitalization and indebtedness as at September 15, 2007 and is qualified by reference to, and should be read in conjunction with, our consolidated financial statements and related notes.

Capitalization and Indebtedness

(In thousands of U.S. dollars)

(unaudited)

	September 15, 2007
Indebtedness
Accounts payable and accrued liabilities	$	795
Short-term secured loan		4,000
Settlement provision		240
Asset retirement obligations		2,072
Total indebtedness	$	7,107
Shareholders’ equity
Share capital	$	23,872
Warrants		1,877
Contributed surplus		4,667
Deficit		(23,558	)
Net shareholders’ equity	$	6,858

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.

We do not have sufficient capital to fund our international and U.S. development activities beyond March 31, 2008.

We do not have sufficient funds to continue operations beyond March 31, 2008. We entered into a credit agreement with Quest Capital Corp. in April 2007 and must repay the outstanding principal balance of $2.0 million by March 31, 2008. (see Item 5.B. – “Liquidity and Capital Resources”). We require significant immediate funding to continue to develop our properties. We intend to seek partners for our various projects, and we may sell one or more properties, or a portion thereof, to enable us to meet our capital commitments. We may be unable to obtain additional financing or sell all or portions of our properties in the time required on terms acceptable to us or to secure partners for our projects. If we are unable to raise sufficient funds to continue our operations, our business will likely be materially and adversely impacted. The consolidated financial statements do not include any adjustments that might result from the outcome of the uncertainty.

We will have substantial capital requirements that, if not met, may have a material adverse effect on our operations.

Our future growth depends on our ability to make large capital expenditures for the exploration and development of natural gas and oil properties. Future cash flows and the availability of debt or equity financing will be subject to a number of variables, such as:

• the success of our prospects in the U.S., Romania, Morocco, Turkey and the U.K. North Sea;

• success in locating and producing new reserves; and

• prices of natural gas and oil.

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Additional financing sources will be required in the future to fund developmental and exploratory drilling. Issuing equity securities to raise additional capital could cause substantial dilution to our existing stockholders. Additional debt financing could lead to:

• a substantial portion of operating cash flow being dedicated to the payment of principal and interest;

• our being more vulnerable to competitive pressures and economic downturns; and

• restrictions on our operations.

We might not be able to obtain necessary financing on acceptable terms, or at all. If sufficient capital resources are not available, we might be forced to curtail developmental and exploratory drilling and other activities or be forced to sell some assets on an untimely or unfavorable basis, which would have a material adverse effect on our business, financial condition and results of operations.

We might not be able to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.

Our review and evaluation of prospects and future acquisitions might not necessarily reveal all existing or potential problems. For example, inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, may not be readily identified even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we often assume environmental and other risks and liabilities in connection with the acquired properties.

A substantial or extended decline in natural gas and oil prices may adversely affect our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, natural gas and oil. Lower natural gas and oil prices may also reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile and they are likely to continue to be volatile in the future. A decrease in natural gas or oil prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. If natural gas or oil prices decline significantly for extended periods of time in the future, we might not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures. Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. Among the factors that could cause fluctuations are:

• change in local and global supply and demand for natural gas and oil;

• levels of production and other activities of the Organization of Petroleum Exporting Countries, and other natural gas and oil producing nations;

• market expectations about future prices;

• the level of global natural gas and oil exploration, production activity and inventories;

• political conditions, including embargoes, in or affecting other oil producing activity; and

• the price and availability of alternative fuels.

Lower natural gas and oil prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in oil or natural gas prices may materially adversely affect our business, financial condition and results of operations.

To the extent that we establish natural gas and oil reserves, we will be required to replace, maintain or expand our natural gas and oil reserves in order to prevent our reserves and production from declining, which would adversely affect cash flows and income.

In general, production from natural gas and oil properties declines over time as reserves are depleted, with the rate of decline depending on reservoir characteristics. If we establish reserves and are not successful in our subsequent exploration and development activities or in subsequently acquiring properties containing proved

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reserves, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is highly dependent upon our ability to economically find, develop or acquire reserves in commercial quantities.

To the extent cash flow from operations is reduced, either by a decrease in prevailing prices for natural gas and oil or an increase in finding and development costs, and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. Even with sufficient available capital, our future exploration and development activities may not result in additional proved reserves, and we might not be able to drill productive wells at acceptable costs.

Our producing properties are highly concentrated.

Our production is presently concentrated in one property in the United States. We will remain vulnerable to the disproportionate impact of delays or interruptions of production until we develop a more diversified production base.

Our retained net profits interest on Oil Mining License 109 may not yield any revenue to us.

In June 2005, we sold our interest in Oil Mining License 109, a 215,000 acre concession located offshore Nigeria (“OML 109”), and retained a net profits interest of up to $16 million based on future exploration success. Absent a new discovery on OML 109 by the new owner, the retained net profits interest will not yield any revenue to us.

We might incur additional debt in order to fund our operations and our exploration and development activities, which would continue to reduce our financial flexibility.

We currently have a $2.0 million bridge loan with Quest Capital Corp. We must repay this loan by March 31, 2008. Our ability to meet our debt obligations and reduce our level of indebtedness depends on our future financial performance. General economic conditions, oil and gas prices and financial, business and other factors affect our operations and future financial performance and our ability to obtain additional financing. Many of these factors are beyond our control. In addition, our ability to generate sufficient cash flow to pay the interest on our debt or to obtain future working capital, borrowings or equity financing to pay or refinance such debt will depend on factors such as financial market conditions, the value of our assets and our financial performance at the time we need capital. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we might be required to sell significant assets. Any failure to refinance or renew our indebtedness or any sale of significant assets could have a material adverse effect on our business, financial condition and results of operations.

Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plans.

If drilling activities increase in the countries in which we operate generally, shortages of drilling and completion rigs, field equipment and qualified personnel could develop. From time to time, shortages have sharply increased our operating costs in various areas around the world and could do so again. The demand for, and wage rates of, qualified drilling rig crews generally rise in response to the increased number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which may materially adversely affect our business, financial condition and results of operations.

Resource estimates depend on many assumptions that may turn out to be inconclusive, subject to varying interpretations or inaccurate.

Resource estimates are based upon various assumptions, including assumptions relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, ownership and title, taxes and the availability of funds. The process of estimating natural gas and oil resources is complex. It requires interpretations of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Further, potential for future resource revisions, either upward or downward, is significantly greater than normal because all of our resource potential in Romania, Morocco, Turkey and the U.K. North Sea is currently undeveloped.

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Undeveloped resources, by their nature, are significantly less certain than developed resources. The discovery, determination and exploitation of undeveloped resources require significant capital expenditures and successful drilling and exploration programs. We may not be able to raise the capital we need to develop these resources.

Actual natural gas and oil prices, future production, revenues, operating expenses, taxes, development expenditures and quantities of recoverable natural gas resources will most likely vary from those estimated by us. Any significant variance could materially adversely affect the estimated quantities and present value of future net revenues set forth herein. A reduction in natural gas and oil prices, for example, would reduce the value of resources and reduce the amount of natural gas and oil that could be economically produced, thereby reducing the quantity of resources. We might adjust estimates of resources to reflect production history, results of exploration and development, prevailing natural gas prices and other factors, many of which are beyond our control.

The value of our common shares might be affected by matters not related to our own operating performance.

The value of our common shares may be affected by matters that are not related to our operating performance and which are outside our control. These matters include the following:

• general economic conditions in Canada, the U.S., Romania, Morocco, Turkey and the U.K. and globally;

• industry conditions, including fluctuations in the price of oil and natural gas;

• governmental regulation of the oil and natural gas industry, including environmental regulation;

• fluctuation in foreign exchange or interest rates;

• liabilities inherent in oil and natural gas operations;

• geological, technical, drilling and processing problems;

• unanticipated operating events which can reduce production or cause production to be shut in or delayed;

• failure to obtain industry partner and other third party consents and approvals, when required;

• stock market volatility and market valuations;

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

• the need to obtain required approvals from regulatory authorities;

• worldwide supplies and prices of, and demand for, natural gas and oil;

• political conditions and developments in each of the countries in which we operate;

• political conditions in natural gas and oil producing regions;

• revenue and operating results failing to meet expectations in any particular period;

• investor perception of the oil and natural gas industry;

• limited trading volume of our common shares;

• change in environmental and other governmental regulations;

• announcements relating to our business or the business of our competitors;

• our liquidity; and

• our ability to raise additional funds.

In the past, companies that have experienced volatility in the trading price of their common shares have been the subject of securities class action litigation. We might become involved in securities class action litigation in the future. Such litigation often results in substantial costs and diversion of management’s attention and resources and could have material adverse effect on our business, financial condition and results of operation.

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We might not be able to obtain necessary approvals from one or more government agencies, surface owners, or other third parties, which could hamper our exploration or development activities.

There are numerous permits, approvals, and agreements with third parties, which will be necessary in order to enable us to proceed with our development plans and otherwise accomplish our objectives. The government agencies in each country in which we operate have discretion in interpreting various laws, regulations, and policies governing operations under the licenses. Further, we may be required to enter into agreements with private surface owners to obtain access and agreements for the location of surface facilities. In addition, because many of the laws governing oil and gas operations in the countries in which we operate have been enacted relatively recently, there is only a relatively short history of the government agencies handling and interpreting those laws, including the various regulations and policies relating to those laws. This short history does not provide extensive precedents or the level of certainty that allows us to predict whether such agencies will act favorably toward us.

The governments have broad discretion to interpret requirements for the issuance of drilling permits. Our inability to meet any such requirements could have a material adverse effect on our exploration or development activities.

Drilling for and producing natural gas and oil are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success depends on the success of our exploration, development and production activities in each of our prospects. These activities are subject to numerous risks beyond our control, including the risk that we will not find any commercially productive natural gas or oil reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project unprofitable. Further, many factors may curtail, delay or prevent drilling operations, including:

• unexpected drilling conditions;

• pressure or irregularities in geological formations;

• equipment failures or accidents;

• pipeline and processing interruptions or unavailability;

• title problems;

• adverse weather conditions;

• lack of market demand for natural gas and oil;

• delays imposed by, or resulting from, compliance with environmental and other regulatory requirements;

• shortage of, or delays in the availability of, drilling rigs and the delivery of equipment; and

• declines in natural gas and oil prices.

Our future drilling activities might not be successful, and drilling success rate overall or within a particular area could decline. We could incur losses by drilling unproductive wells. Shut-in wells, curtailed production and other production interruptions may materially adversely affect our business, financial condition and results of operations.

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Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.

We operate in the highly competitive areas of oil and gas exploration, development and acquisition with a substantial number of other companies, including U.S.-based and foreign companies doing business in each of the countries in which we operate. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and gas companies in each of the following areas:

• seeking oil and gas exploration licenses and production licenses;

• acquiring desirable producing properties or new leases for future exploration;

• marketing natural gas and oil production;

• integrating new technologies; and

• acquiring the equipment and expertise necessary to develop and operate properties.

Many of our competitors have substantially greater financial, managerial, technological and other resources than we do. These companies are able to pay more for exploratory prospects, and productive oil and gas properties and prospects than we can. To the extent competitors are able to pay more for properties than we are paying, we will be at a competitive disadvantage. Further, many of our competitors enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

Political instability or fundamental changes in the leadership or in the structure of the governments in the jurisdictions in which we operate could have a material negative impact on us.

Our interests may be affected by political and economic upheavals. Local, regional and world events could cause the jurisdictions in which we operate to change the mining laws, tax laws, foreign investment laws, or to revise their policies in a manner that renders our current and future projects unprofitable. Further, the governments in the jurisdictions in which we operate could decide to nationalize the oil and gas industry or impose restrictions and penalties on foreign-owned entities, which could render our projects unprofitable or could prevent us from selling our assets or operating our business. The occurrence of any such fundamental change could have a materially adverse effect on our business, financial condition and results of operations.

We may not be able to complete the exploration and development of any, or a significant portion of, the oil and gas interests covered by our leases or licenses before they expire.

Each license or lease under which we operate has a fixed term. We may be unable to complete our exploration and development efforts prior to the expiration of licenses or leases. Failure to obtain an extension of the license or lease, be granted a new exploration license or lease or the failure to obtain a license or lease covering a sufficiently large area would prevent or limit us from continuing to explore and develop a significant portion of the oil and gas interests covered by the license or lease. The determination of the amount of acreage to be covered by the production licenses is in the discretion of the respective governments.

We are subject to complex laws and regulations, including environmental regulations, which can have a material adverse effect on our cost, manner or feasibility of doing business.

Exploration for and exploitation, production and sale of oil and gas in each country in which we operate is subject to extensive national and local laws and regulations, including complex tax laws and environmental laws and regulations, and requires various permits and approvals from various governmental agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we might not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements of any permits, might result in the suspension or termination of operations and subject us to penalties. Our costs to comply with these numerous laws, regulations and permits are significant. Further, these laws and regulations could change in ways that substantially increase our costs and associated liabilities. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations may harm our business, results of operations and financial condition. See Item 4.B. – “Material Effects of Governmental Regulations” and Item 4.D. – “Property, Plant and Equipment.”

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We do not plan to insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our natural gas and oil operations.

We do not intend to insure against all risks. Our natural gas and oil exploration and production activities will be subject to hazards and risks associated with drilling for, producing and transporting natural gas and oil, and any of these risks can cause substantial losses resulting from:

• environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

• abnormally pressured formations;

• mechanical difficulties, such as stuck oil field drilling, and service tools and casing collapse;

• fires and explosions;

• personal injuries and death;

• regulatory investigations and penalties; and

• natural disasters.

We might elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse affect on our business, financial condition or results of operations.

We are subject to operating hazards.

The oil and gas business 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.

We are dependent on key personnel.

We depend to a large extent on the services of Scott Larsen, our President and CEO, Dr. David Campbell, our International Exploration Manager, and Dr. Weldon Beauchamp, our Consulting Geologist/Geophysicist. The loss of the services of any of these individuals could have a material adverse effect on our operations.

Our small size and the number of staff impacts our internal controls.

Due to the limited number of staff, it is not possible to achieve complete segregation of duties, nor do we currently maintain written policies and procedures at our international offices. We must engage accounting assistance with respect to complex, non-routine accounting issues, Canadian GAAP matters, tax compliance, and reporting for our international operations. At the present time, we have no plans to increase the size of our staff.

Our officers and directors may have 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 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 outside directors are officers and/or directors of other publicly traded financial services, crude oil and natural gas exploration and production companies. See Item 6 – “Directors, Senior Management and Employees.”

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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. S.W., Calgary, Alberta, T2P 2T8. Our registered office is located at Suite 3700, 400 - 3rd Ave. S.W., 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.

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 1992, we acquired a 30% interest in 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.

During 2004, 2005 and 2006, we focused our efforts on acquiring high-impact international properties, evaluating and acquiring lower-risk cash flow opportunities in the U.S. and disposing of OML 109. OML 109 was sold in June 2005, and we retained a net profits interest of $16 million based on future exploration success. Absent a new discovery on OML 109 by the new owner, the retained net profits interest will not yield any revenue to us. During 2005 and 2006, we acquired an exploration permit and a reconnaissance license in Morocco, three production blocks in Romania, three exploration licenses in Turkey and two promote round licenses covering six blocks in the U.K. North Sea. During this same period, we acquired properties in South Texas and East Texas. We also held working interests in five other properties in East Texas, Oklahoma and Louisiana in which we were not the operator. In December 2006, we sold our non-operated working interest in the Bayou Couba property in Louisiana. In 2007, we agreed to farmout one of our licenses in Turkey and were awarded three additional exploration licenses in southeastern Turkey and two exploration permits in Morocco, and we sold our South Texas and East Texas operated properties.

International

Morocco. On November 7, 2007, we announced that we converted a portion of our Guercif - Beni Znassen Reconnaissance License into two exploration permits covering a total of 3,893 square kilometers (962,000 acres) in the Guercif area in northeastern Morocco. Pursuant to a participation agreement between us (30%), Stratic Energy Corporation (“Stratic”) (20%) and Sphere Petroleum QSC (“Sphere”) (50%), Sphere will bear the entire cost of the initial three-year work program to earn its 50% interest in the two Guercif exploration permits. Our interests and the interests of Sphere and Stratic are subject to the interest in the Guercif exploration permits held by the national oil company of Morocco, Office National des Hydrocarbures et des Mines, who is carried during the exploration phase but pays its 25% share of costs in the development phase. We will continue as operator of the Guercif exploration permits during the initial three-year period. The Guercif exploration permits are for an eight-year term divided into three periods. The initial three-year work program is estimated to cost more than U.S. $3 million and will include the re-entry of an existing well and the acquisition of 300 kilometers of 2D seismic. In addition, Sphere has posted the required bank guarantee for the initial work program with the Moroccan government and will reimburse us and Stratic for our back costs.

In May 2006, we were awarded the Tselfat exploration permit covering 900 square kilometers (222,345 acres) in northern Morocco. The permit expires in May 2014. The Tselfat exploration permit covers three abandoned fields, Haricha, Tselfat and a portion of the Bou Draa field, which were discovered in 1954, 1918 and 1934, respectively. We have posted a $3.0 million bank guarantee against a work program commitment that

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includes shooting a 3D survey over the Bou Draa and Haricha fields and then drilling an exploratory well to test the previously untested deeper formations. We also anticipate being able to recover remaining resources from the previously produced formations in each of the abandoned fields. In August 2007, we reached an agreement to farmout 50% of our interest in the Tselfat exploration permit to Sphere. In exchange for an option to acquire 50% of our interest in the Tselfat permit, Sphere will fund the costs to acquire a 110 square kilometer (27,181 acres) 3D seismic survey to be shot over the Haricha field and northern portion of the Bou Draa field in early 2008 and will also fund the cost of additional geological studies. It is estimated the 3D survey and the studies will cost approximately $4.5 million over the next year. Upon its exercise of the option, Sphere will (i) fund the drilling and testing of an exploratory well; and (ii) replace our bank guarantee deposited with the Moroccan government.

Romania. In February 2006, we were awarded three production licenses in Romania. We received final government approval of the licenses in September 2007. The three licenses, Izvoru, Vanatori and Marsa, each cover about 5 square kilometers (1,200 acres) and are located within 100 kilometers of Romania’s capital, Bucharest, in an area known as the Moesin platform. All three fields produced oil and gas but were not fully developed. The licenses were awarded to us based upon certain work programs, such as shooting seismic and drilling or reentering wells, on each of the respective fields over the next three years. The work programs for the three fields total about $9.0 million and must be completed by September 2010. We are the operator and 100% working interest owner of the fields. We shot a 3D seismic survey over Izvoru and 2D surveys over the other two fields in late 2006 and are presently conducting engineering studies which will be merged with the seismic results to provide a field development plan.

U.K. North Sea. In September 2006, we were awarded licenses covering six blocks in the U.K North Sea 23^rd Seaward Licensing Round. The six blocks, which cover 1,500 square kilometers (370,500 acres), lie in the Auk Basin, an area of the North Sea between the producing areas of the Southern Gas Basin and Central North Sea. We have a two-year period that commenced in December 2006 within which to conduct technical studies and acquire and reprocess seismic data. The license will expire in December 2007 if we have not made a firm commitment to the Department of Trade and Industry (the “DTI”) to complete a work program. We can perpetuate the license by committing, prior to December 2007, to drill an exploratory well before the fourth anniversary of the license. We are presently evaluating the reprocessed seismic over the area and are actively seeking partners for a farmout of the property.

Turkey. In June 2006, we were awarded three exploration licenses in southeastern Turkey. Two of the licenses are located near the town of Bismil on the Tigris River adjacent to two producing oil fields. The third license is located near Cizre about 60 kilometers from the Iraq border. The three licenses together cover a total of 660 square kilometers (162,762 acres) and expire in June 2010. The licenses were awarded to us based upon work programs on each of the respective areas involving technical studies, reprocessing of data and contingent plans for drilling wells. We are the operator and 100% working interest owner of the licenses. In October 2007, we announced that we had agreed to the farmout of one of the licenses, Block 4175.

In August 2007, we were awarded three additional exploration licenses, all of which are in southeastern Turkey on the border with Iraq. The three new licenses cover a total of 1,354 square kilometers (334,618 acres) and expire in June 2011. Upon a commercial discovery, each exploration license would be converted to a 20-year production lease which bears a 12.5% royalty. These additional licenses will also involve a work program, including technical studies, reprocessing of data and contingent plans for drilling wells. We will be the operator and 100% working interest owner of the licenses.

Nigeria. In June 2005, we sold our interest in OML 109 and retained a net profits interest of up to $16 million based on future exploration success. We originally acquired an interest in OML 109 in 1992. We drilled both a discovery well and the first appraisal well in the Ejulebe field in 1994 and 1995. The Ejulebe field went into production in September 1998 and had produced about 11 Mmbbls through the date of sale. The new owner has drilled two wells since the sale and the field currently produces about 1,500 Bbls/d. Absent a new discovery on OML 109 by the new owner, the retained net profits interest will not yield any revenue to us.

United States. In April 2005, we acquired the South Gillock and State Kohfeldt Units located in Galveston County, Texas. The property is on the flank of a large salt dome covering approximately 6,000 acres with 61 wells, most of which are temporarily abandoned. We are the operator and 100% owner of the property. The field currently produces a total of approximately 60 Boe/d from two wells. We conducted an extensive workover program in late 2005 and early 2006 in an attempt to increase production from existing wells. One well was producing at a rate of 500-600 Mcf/d for much of 2006 but had to be shut in due to casing collapse in December 2006.

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We commenced drilling the SGU #96 well on the South Gillock property in February 2007. This well tested the existing producing formation, the Big Gas Sand, as well as certain deeper middle Frio formations. On June 29, 2007, we announced that the well had been completed in the Big Gas Sand formation and was producing approximately 1,000 Mcf per day.

In November 2007, we sold the South Gillock and State Kohfeldt Units, as well as the shallow rights over the South Gillock Unit, for $4.0 million, and the buyer assumed the plugging and abandonment liability associated with the units.

In late 2006, we participated for our 20% non-operated working interest in a well being drilled on the Oswego property in Dewey County, Oklahoma. The well is currently producing 32 bbls of oil and 47 Mcf of natural gas per day. A second property located in McClain County, Oklahoma is currently the subject of a declaratory judgment action that we filed to declare that prior leases lapsed due to lack of production. We have filed, and are awaiting a decision on, a motion for summary judgment. The McClain County property that is the subject of the declaratory action and the outcome of the litigation are not material to us.

In January 2006, we acquired the Jarvis Dome property in Anderson County, Texas covering 170 acres with two wells on it. We then leased an additional 630 acres. We re-entered and recompleted one of the wells as a stripper oil well, which produced an average of 4 bbls/d until it was shut-in in March 2007. We re-entered and sidetracked the second well in the Pecan Gap formation. This well was tied into a gas pipeline in December 2006. We were the operator and 100% owner of the property. We sold the Jarvis Dome property in October 2007. At the time of sale, the property was producing about 40 Mcf/d.

In 2005, we participated for a 20% non-operated working interest in two wells drilled in Panola County, Texas. One of the wells is currently producing at a rate of 40 Mcf/d. The other well is temporarily abandoned as non-commercial and is being evaluated.

In December 2006, we sold our interests in the Bayou Couba property located in St. Charles Parish, Louisiana and our interests in debentures we held of American Natural Energy Corporation (“ANEC”), the operator of the Bayou Couba property, to Dune Energy, Inc. for $2 million. The sale included our 10% working interest and related interests and all of the 8% secured debenture issued by ANEC in the principal face amount of $3.0 million held by us (the “Debenture”). We had acquired our 10% interest in the Bayou Couba property in 2003 when we financed the drilling of four wells on the property for a $2 million production payment. The production payment was repaid in October 2003. During 2004 and 2005, we participated in drilling wells on the property; however, the two exploration wells drilled to test the deep gas potential on the flanks of the Bayou Couba dome were unsuccessful. We had purchased the Debenture in October 2003. Due to the lack of drilling success, in 2005 we wrote down our investment in the Debenture to $900,000. In August 2005, in exchange for indebtedness owed to us, we acquired 2,237,136 shares of ANEC in a private placement for $268,456 or U.S. $0.12 per share. This investment was written down to the equivalent of US $0.07 per share at the end of 2005 and is carried at no value as of December 31, 2006.

Principal Capital Expenditures and Divestitures. The following table sets forth our principal capital expenditures and divestitures during 2004, 2005 and 2006:

Principal Capital Expenditures and Divestitures

(In thousands of U.S. dollars)

Expenditure Type	2006			2005		2004
Property acquisition	$	—		$	3,892	$	—
Drilling (leasing, exploration and development)		4,737			947		1,694
Facilities and equipment		—			—		12
Divestiture of property and equipment		(1,500	)		—		(155	)
Total Capital Expenditures and Divestitures	$	3,237		$	4,839	$	1,551

B. Business Overview

Nature of Our Operations. We are engaged in oil and gas exploration and production. Our current activities are focused on:

• developing the oil and gas properties in our portfolio;

• farming out or securing partners for our international properties;

• acquiring additional exploration and development opportunities in the countries in which we presently operate; and

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• realizing value from our onshore U.S. properties (which could include selling, drilling or farming out).

Our success will depend on discovering hydrocarbons in commercial quantities and then bringing the discoveries into production. Our ability to achieve drilling and production success will depend upon obtaining sufficient capital. As to new opportunities, our success will depend on whether we are able to locate and successfully negotiate for oil and gas opportunities in foreign countries which meet our criteria and then successfully exploring for and producing oil and gas from those prospects. Our success will also depend on how well our properties in the U.S. perform. The risks associated with these plans are outlined above under “Risk Factors.” We utilize the latest geophysical and geological technologies to reduce the risks associated with our oil and gas exploration. In the U.S., we will seek to realize value from our properties through drilling, farmouts and sales. All of our production to date as disclosed in later sections of this registration statement is from U.S. properties.

Principal Markets. At December 31, 2006, we operated 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 our geographic areas are as follows:

2006 (In thousands of U.S. dollars)	Identifiable Assets (Liabilities)			Revenues		Loss
United States	$	4,709		$	1,604	$	6,631
Morocco		3,414			—		859
Romania		1,894			—		605
Corporate assets		5,375			9		1,318
	$	15,392		$	1,613	$	9,413
2005
United States	$	11,094		$	1,400	$	2,922
Morocco		644			9		67
Corporate assets		7,189			—		784
	$	18,927		$	1,409	$	3,773
2004
United States	$	3,880		$	744	$	2,288
Canada		(134	)		—		2,367
Nigeria		198			4,364		538
Corporate assets		12,106			—		—
	$	16,048		$	5,108	$	5,193

Seasonality. Seasonality has no material effect on our financial condition or results of operations.

Marketing Channels. Crude oil production from our U.S. properties is sold under market sensitive or spot price contracts. Natural gas production from these properties 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.

Drilling Contractors. As discussed above in “Risk Factors,” shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which may materially adversely affect our business, financial condition and results of operation.

Material Effects of Governmental Regulations. Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations concerning the protection of the environment and human health will not have a material effect upon

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our operations, capital expenditures, earnings or competitive position. We cannot predict what effect additional regulation or legislation, enforcement policies thereunder and claims for damages for injuries to property, employees, other persons and the environment resulting from our operations could have on out activities. Our activities with respect to exploration, development and production of oil and natural gas are subject to stringent environmental regulation by state and federal authorities including the United States Environmental Protection Agency (“EPA”). Such regulation has increased the cost of planning, designing, drilling, operating and in some instances, abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. Although we believe that 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. 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.

Waste Disposal. We currently own or lease, and have owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although we believe operating and disposal practices that were standard in the industry at the time were utilized, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, these properties may have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. State and federal laws applicable to oil and natural gas wastes and properties have become more strict over time. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. Wastes, including hazardous wastes, are generated during oil and gas activities that are subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain hazardous and non-hazardous wastes and are considering the adoption of stricter disposal standards for non-hazardous wastes. Furthermore, certain wastes generated by oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating and disposal requirements.

CERCLA. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These persons include the owner and operator of a site and persons that disposed of or arranged for the disposal of the hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from responsible classes of persons the costs of such action. In the course of our oil and gas operations, wastes may be generated that fall within CERCLA’s definition of “hazardous substances.” We may also be an owner of sites on which “hazardous substances” have been released and, as a result, may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been released. To date, however, we have not and, to our knowledge, our predecessors or successors have not, been named a potentially responsible party under CERCLA or similar state superfund laws affecting property we now own or lease.

Air Emissions. Our operations are subject to local, state and U.S. federal regulations for the control of emissions of air pollution. Legal and regulatory requirements in this area are increasing. We may incur significant costs and liabilities in the future as a result of new regulatory developments. In particular, regulations promulgated under the Clean Air Act Amendments of 1990 may impose additional compliance requirements that could affect our operations. However, it is impossible to predict accurately the effect, if any, of the Clean Air Act Amendments on us at this time. We may in the future be subject to civil or administrative enforcement actions for failure to comply strictly with air regulations or permits. These enforcement actions are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction or operation of certain air emission sources.

OSHA. We are subject to the requirements of the U.S. Occupational Safety and Health Act (“OSHA”) and comparable U.S. state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and similar state statutes require us to prepare information about hazardous materials used, released or produced in oil and gas

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operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.

OPA and Clean Water Act. U.S. federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention control plans, countermeasure plans and facilities response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act 1990 (“OPA”) amends certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act (“CWA”), and other statutes as they pertain to the prevention of, and response to, oil spills into navigable waters. OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground. Regulations are currently being developed under OPA and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the CWA and analogous state laws require permits to be obtained to authorize discharges into surface waters or to construct facilities in wetland areas. The EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. We believe that we are in material compliance with all permits that are required to be obtained and that obtaining such permits in the future will not have a material adverse impact on our operations in the future. With respect to future operations, we believe we will be able to obtain, or be included under, such permits, where necessary.

NORM. Oil and gas exploration and production activities have been identified as generators of concentrations of low-level naturally-occurring radioactive materials (“NORM”). NORM regulations have been adopted in several states. We are unable to estimate the effect of these regulations.

Safe Drinking Water Act. Our operations may involve the disposal of produced saltwater and other non-hazardous oilfield wastes by re-injection into the subsurface. Under the U.S. Safe Drinking Water Act (“SDWA”), oil and gas operators must obtain a permit for the construction and operation of underground Class II injection wells. To protect against contamination of drinking water, periodic mechanical integrity tests are often required to be performed by the well operator. While we expect to be able to obtain all such permits as are required, there can be no assurance that these requirements may not cause us to incur additional expenses.

Toxic Substances Control Act. The Toxic Substances Control Act (“TSCA”) was enacted to control the adverse effects of newly manufactured and existing chemical substances. Under the TSCA, the EPA has issued specific rules and regulations governing the use, labeling, maintenance, removal from service and disposal of PCB items, such as transformers and capacitors used by oil and gas companies. We may own such PCB items.

At December 31, 2006, 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 costs outside the ordinary course of business will be realized.

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
TransAtlantic Maroc, Ltd.	100	%	Bahamas

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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. TransAtlantic Maroc, Ltd. and TransAtlantic Worldwide Romania SRL are 100% owned by TransAtlantic Worldwide, Ltd.

D. Property, Plant and Equipment

United States. On April 15, 2005, we acquired the South Gillock and State Kohfeldt Units covering over 6,000 acres onshore in Galveston County, Texas. The field began producing in the 1940’s and the two units combined have produced over 65 Mmbbls of oil from the Big Gas Sand of the Frio formation which ranges in depth between 7,800 and 9,600 feet in the units. The units were originally operated by Amoco. We believe there are remaining gas reserves in the gas cap of the South Gillock Unit and its acquisition was premised on this belief. Since the acquisition, we have engaged in a workover program entering existing wells. This work doubled production from 60 Boe/d at the time of the acquisition to about 135 Boe/d in March 2006, but the casing failed in the SGU #83 well in December 2006 causing the production to drop back to its initial 60 Boe/d level at year end. There are 61 wells on the units of which two are producing and the remaining wells are temporarily abandoned. We commenced the drilling of the SGU #96 well in February 2007 to test the Big Gas Sand as well as deeper Frio formations below the Big Gas Sand. On June 29, 2007, we announced that the well had been completed in the Big Gas Sand formation and was producing approximately 1,000 Mcf per day. We were the operator and owned 100% of the working interest with a net revenue interest of 77%. The report of Netherland, Sewell & Associates, Inc. indicates gross proved reserves of 7,400 barrels of oil, 1,500 barrels of condensate and 551 Mmcf of natural gas at the South Gillock and State Kohfeldt Units as of December 31, 2006.

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 paid $186,000 for a two-year option on deep rights covering 2,731 acres over the northern portion of the South Gillock Unit and a three-year term assignment over the same 2,731 acres for the shallow rights.

On November 12, 2007, we announced the sale of the South Gillock and State Kohfeldt Units, as well as the shallow rights over the South Gillock Unit, for $4.0 million, and the buyer assumed an estimated $2.0 million in plugging and abandonment liability associated with the units.

In Oklahoma, we leased two properties, one in Dewey County (1,150 net acres) and one in McClain County (110 net acres). We participated for a 20% working interest in a well drilled on the Dewey County property at the end of 2006 that is currently producing 32 bbls of oil and 47 Mcf of natural gas per day. In the McClain County property, we are trying to clear up some title issues prior to developing the property. In Texas, we participated for a 20% interest in two wells in Panola County, Texas in 2005 (257 net acres); one of the wells was non-commercial and is being evaluated and the other is currently producing at a rate of 40 Mcf/d. We are trying to promote a farmout to test deeper formations on the Panola County property. We are also a 20% participant in a property in Gregg County, Texas (324 net acres) and are likewise trying to promote a farmout on that acreage. There are currently no reserves associated with any of these properties.

In the first quarter of 2006, we acquired the Jarvis Dome property in Anderson County, Texas which included two wells and leases covering 170 acres for $220,000. We then leased an additional 630 acres. We were the operator and owned 100% of the working interest in the property (we reacquired the previously outstanding 20% back-in after payout in February 2007). The initial work program on Jarvis Dome consisted of recompleting one of the existing wells and sidetracking the other existing well. This second well was sidetracked in the Pecan Gap formation in the second quarter of 2006. Plans to drill a well to test the Woodbine formation were suspended. The report of Netherland, Sewell & Associates, Inc. indicates gross proved reserves of 1,400 barrels of oil and 98.4 Mmcf of natural gas at the Jarvis Dome property as of December 31, 2006. We sold all of our interests in the Jarvis Dome property in October 2007. At the time of sale, the property was producing about 40 Mcf/d.

Morocco. On November 7, 2007, we announced that we converted a portion of our Guercif - Beni Znassen Reconnaissance License into two exploration permits covering a total of 3,893 square kilometers (962,000 acres) in the Guercif area in northeastern Morocco. Pursuant to a participation agreement between us (30%), Stratic (20%) and Sphere (50%), Sphere will bear the entire cost of the initial three-year work program to earn its 50% interest in the two Guercif exploration permits. Our interests and the interests of Sphere and Stratic are subject to the interest in the Guercif exploration permits held by the national oil company of Morocco, Office National des

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Hydrocarbures et des Mines, who is carried during the exploration phase but pays its 25% share of costs in the development phase. We will continue as operator of the Guercif exploration permits during the initial three-year period. The Guercif exploration permits are for an eight-year term divided into three periods. The initial three-year work program is estimated to cost more than U.S. $3 million and will include the re-entry of an existing well and the acquisition of 300 kilometers of 2D seismic. In addition, Sphere has posted the required bank guarantee for the initial work program with the Moroccan government and will reimburse us and Stratic for our back costs.

In May 2006, we were awarded the Tselfat exploration permit covering 900 square kilometers (222,345 acres) in northern Morocco. Tselfat has three fields, Haricha, Bou Draa and Tselfat, that produced from the early 1920s to 1970s, with limited production continuing into the 1990s. All of the wells are presently either shut-in or abandoned. The exploration permit expires in May 2014. In August 2007 we reached an agreement to farmout 50% of our interest in the Tselfat exploration permit to Sphere. In exchange for an option to acquire 50% of our interest in the Tselfat permit, Sphere will fund the costs to acquire a 110 square kilometers 3D seismic survey to be shot over the Haricha field and northern portion of the Bou Draa field in early 2008 and will also fund the cost of additional geological studies. It is estimated the 3D survey and the studies will cost approximately $4.5 million over the next year. Upon its exercise of the option, Sphere will (i) fund the drilling and testing of an exploratory well; and (ii) replace our bank guarantee deposited with the Moroccan government.

While historical production estimates are difficult, historical data suggests cumulative production is in the range of 4 Mmbbls of oil and 8 Bcf of gas for the three fields. 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. There are currently no reserves associated with our Moroccan properties.

Historical Production. The Haricha Field was discovered in 1954 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 2.6 Mmbbls of oil and 7.8 Bcf of gas from porous Jurassic age sandstones. There is no current production. The field is a complex structural trap formed by a thrust fault that has not been fully exploited. Based on available 2-D seismic, we believe potential exists for a deeper sub-thrust play below the known productive horizon.

The Bou Draa field was discovered in 1934. The Bou Draa structure is a large surface anticline generated by a regional thrust fault. The surface anticline, that has a topographic expression extending for approximately 10 kilometers, was discovered by wells drilled on hydrocarbon seeps. Over 140 shallow wells were drilled in a 6 square kilometers area and produced less than 1 Mmbbls recorded production of light oil from fractured carbonates and sandstones. We believe that hydrocarbon reserves can be recovered using horizontal drilling techniques, artificial stimulation and reservoir pressure maintenance. We believe further upside potential may exist in sub-thrust reservoirs in Jurassic age sandstones. The Bou Draa field is located near the city of Sidi Kacem where there is an active refinery that was originally built to refine oil from the Bou Draa and Haricha Fields.

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 that 500,000 barrels of oil recorded production from Jurassic carbonate reservoirs.

Proposed Work Program. Since the award of the Tselfat permit in May 2006, we have been collecting, collating, digitizing and reviewing all of the existing well, production, seismic and other data. We will likely reprocess some of the 2D seismic that exists over the block. In addition, subject to financing, we plan to shoot a 3D survey over the Bou Draa and Haricha fields in early 2008. This would then be followed by an exploratory well to test the previously untested Jurassic formations in the sub-thrust. As to the existing fields, we have initiated an engineering study over the Haricha field to determine the original resources in place, estimate historical production, determine recoverable resources that remain and develop a plan to access any remaining resources.

Commercial Terms. Pursuant to a Petroleum Agreement (and the companion Association Contract) dated May 18, 2006, we committed to a work program during the initial three-year period that will involve shooting a 3D seismic survey over an area of at least 50 square kilometers and drilling a well to a depth exceeding 2,000 meters. We have posted a $3.0 million bank guarantee in support of the program. During the exploration phase, we will operate and bear 100% of the costs to earn a 75% interest. The national oil company of Morocco, National des Hydrocarbures et des Mines (“ONHYM”), is carried for 25% of the costs during the exploration phase which is governed by the Petroleum Agreement. Once a discovery is made, the area covered by the discovery is converted into an exploitation concession which is governed by the Association Contract. Under the exploitation concession, we (75%) and ONHYM (25%) will each pay our share of costs. Upon conversion

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to an exploitation concession, we pay a discovery bonus of $500,000 to ONHYM. When certain sustained daily production levels are reached, we pay a one-time production bonus (15,000 Bbls/d - $750,000; 25,000 Bbls/d - $1 million; 35,000 Bbls/d - $2 million and 50,000 Bbls/d - $3 million). These production bonuses are treated as development costs for tax purposes. There is a ten-year tax holiday on revenues from petroleum production commencing in the year in which production begins. After ten years, the corporate tax rate is 30%. Oil and gas exploration activities are exempt from both value added tax and customs duties. The royalty paid to the government for onshore production is 10% on oil and 5% on gas. In addition, the first approximately 2.1 Mmbbl of oil production and the first approximately 11 Bcf of gas production are exempt from royalty. Once an area is converted into an exploitation concession, we pay annual surface rentals of $2.85 per acre.

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 for a one-year term to conduct seismic and other exploratory activities (but not drilling). The size 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 2-3 years each. A distinct work program is negotiated for each separate term and the oil company then must post a bank guarantee to cover the cost of the work program for that term. The interests under an Exploration Permit are 75% to the oil company and 25% to ONHYM. Interests under an Exploration Permit are transferable. However, 100% of the costs of all activities under an Exploration Permit are borne by the oil company.

An Exploitation Concession is applied for upon the discovery of a commercially exploitable field. The concession size corresponds to the area of the commercial discovery. The maximum duration of an 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 percentage interests (75% oil company, 25% ONHYM). The oil company serves as operator. The oil company and ONHYM enter into an Association Contract (similar to a joint operating agreement) to govern operations on the concession. Interests under an exploitation concession are transferable. All production is sold at market prices. A bonus (the amount of which is negotiated at the time of negotiation of a Petroleum Agreement) is paid to the government by the oil company upon conversion to an Exploitation Concession. Additional production bonuses are also paid when certain production levels from the Exploitation Concession are achieved. The levels of production and the amount of production bonuses are negotiated as part of a Petroleum Agreement. The bonuses are deductible for tax purposes.

Romania. In February 2006, we were awarded three onshore production licenses by the Romanian government in the 7^th Licensing Round. The three oil and gas fields, Izvoru, Vanatori and Marsa, each cover about five square kilometers (1,200 acres). They were discovered by the former national oil company and are all located within 100 kilometers of Romania’s capital, Bucharest. The licenses were awarded to us based upon certain work programs on each of the respective fields over three years, including shooting seismic and drilling or re-entering wells. There is no current production from any of the fields. The work programs for the three fields total about $9.0 million and must be completed by September 2010. 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 Mmbbls of oil from 26 wells. Completion difficulties and sand production resulted in limited flow rates and recoveries and led to field abandonment in 1998. Izvoru is a stratigraphic play and produces from Sarmatian (Tertiary age) shallow marine sandstones (about 4,000 feet sub sea). Additionally, there is deeper potential in Cretaceous Albian age limestones which are productive in adjacent fields and were

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penetrated by four wells in the Izvoru field but not developed. The initial work program will include re-entering up to nine wells. We shot a 25 square kilometers 3-D seismic survey over the Izvoru Field in late 2006. The seismic results will be merged with engineering studies to provide a field development plan.

Vanatori and Marsa fields 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 of gas over six years from the Sarmatian formation at a depth of 5,600 feet. We believe there is also deeper Cretaceous potential in the field. The Vanatori Field was abandoned due to sand production and water invasion. 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 at a depth of 2,100 feet. We shot a 2-D seismic survey over both of these fields in late 2006. The seismic results will be merged with engineering studies to provide a field development plan. There are currently no reserves associated with our Romanian properties.

Commercial Terms. Romania’s current petroleum laws provide a framework for investment and operation that allows foreign investors to retain the proceeds from the sale of petroleum production. The fiscal regime is comprised of royalties, excise tax and income tax. Two forms of royalty are payable:

• A percentage of the value of gross production on a field basis, such percentage being fixed on a sliding scale depending on production levels. The production royalty rate varies between 3.5% to 13.5% for crude oil and between 3% to 13% for natural gas production; and

• A fixed percentage of the gross income obtained from the transportation and transit of petroleum through the national pipeline system and from petroleum operations carried out through oil terminals belonging to the state. The royalty rate is currently fixed at 5%.

The license holder pays corporate income tax, but enjoys a one-year income tax holiday from the first day of production. Corporate income tax is assessed at a rate of 16%. All costs incurred in connection with exploration, development and production operations are deductible for corporate income tax purposes. Excise duty is payable on crude oil and natural gas at the rate of 4 euro per tonne (7.9 bbls) of crude oil and 7.4 euro per 1,000 cubic metres (35.3 mcf) of natural gas. Excise tax is not payable on crude oil or natural gas delivered as royalty to the government, or on quantities directly exported. Resident companies which remit dividends outside of Romania to non-EU countries are subject to a dividend withholding tax at between 10-15% dependent upon the proportion of the capital owned by the recipient. No customs duty is payable on the export of petroleum nor is customs duty payable on the import of material necessary for the conduct of petroleum operations. There is also a 19% value added tax. Oil is priced at market while gas is tied to a bundle pricing based in part on the import price and in part on the domestic price.

Licensing Regime. The Ministry of Industry and Resources has responsibility for petroleum policy and strategy. The National Agency for Mineral Resources (“NAMR”) was set up in 1993 to administer and regulate petroleum operations. 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 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 favoring petroleum accumulations. A petroleum concession provides exclusive rights to conduct petroleum exploration and production under a petroleum agreement.

U.K. 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 (1,200 square kilometers) in the Auk Basin 150 kilometers east of the Scottish mainland. These blocks are in shallow water (150 feet) and contain a sub-salt Permian gas prospect at moderate depth with significant reserve potential. The official award of these licenses to us occurred in December 2005. During 2006, we purchased and reprocessed available seismic data and conducted other geological and geophysical studies to evaluate the licenses. We have completed its required work program for the initial two-year term of the license.

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The property is composed of a Mesozoic half-graben with underlying early syn-rift Permian evaporite seal, early syn-rift Permian reservoir and pre-rift Lower Carboniferous source rocks. Graben subsidence has formed the Carboniferous gas kitchen and set up an updip migration path from the source rocks into the overlying reservoir. A large scale prospect is formed by stratigraphic pinch out of the Permian reservoirs at western margin of the basin, with four-way dip closure on listric basin-bounding faults. This property is at less than 6,000 feet total vertical depth sub-sea.

The licenses are near the Central Area Transmission System (CATS) gas export pipeline. CATS is a 408 kilometer pipeline that links a riser platform adjacent to the North Everest development in the Central North Sea, with the gas processing terminal at Teesside. The pipeline has a nominal capacity of 1,707 million standard cubic feet per day. The CATS pipeline has been designed to allow access to new gas fields either at the riser platform or through one of six sub-sea tees along its length.

We are seeking to farmout our working interests in the property. Any company farming into the licenses would need to demonstrate its qualifications as an operator to 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 the third and fourth years.

Commercial Terms. In the U.K., there are no royalties. The U.K. corporate income tax rate is 30% of taxable income. Income from oil and gas activities is also subject to a supplemental charge of 20%. The amount and timing of income taxes payable depends on many factors including price, production and capital investment levels.

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 U.K. North Sea.

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 including 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.

Turkey. In June 2006, we were awarded three onshore exploration licenses in southeastern Turkey. The three licenses together cover a total of 660 square kilometers (162,762 acres) and are for a term of four years. These licenses were awarded to us based on work programs for each of the respective areas. We are the operator and 100% working interest owner of the licenses. Following a commercial discovery, each exploration license can be converted to production leases which bear a 12.5% royalty, resulting in an 87.5% net revenue interest to us. The work programs will total about $300,000 on each block over the next two years. Additional commitments to shoot seismic or drill wells will be contingent on the results from the initial work programs.

Two of the licenses (AR/TAT/X/4173 and AR/TAT/X/4174) are located near Bismil on the Tigris River. These licenses are adjacent to two producing oil fields (Molla and Karakilise). The Company’s primary target is a Palaeozoic play located at a depth of approximately 9,843 feet. The work program involves reprocessing existing 2D seismic data and based on these results additional 2D seismic may be shot or a well drilled.

The third license (AR/TAT/X/4175) is located near Cizre about 60 kilometers from the Iraq border. The target is a deep sub-thrust play similar to the major Iraqi and Iranian Zagros fields to the south. We will conduct an initial work program of detailed fieldwork and geochemical analysis that is expected to lead to a 2D seismic program to define a drilling location. There is presently no 2D seismic over the area. In October 2007, we announced that we had agreed to farmout this license.

In August 2007, we were awarded three additional exploration licenses in southeastern Turkey. The three new licenses together cover a total of 1,354 square kilometers (334,618 acres) and are for a term of four years. These additional licenses will also involve a work program, including technical studies, reprocessing of data and contingent plans for drilling wells. We are the operator and 100% working interest owner of the licenses. Following a commercial discovery, each exploration license would be converted to a 20-year production lease which bears a 12.5% royalty.

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We began activities in Turkey in April 2005 when we entered into an exclusive option with Polmak Sondaj Sanayii A.S to acquire a 50% interest in five exploration licenses in southeastern Turkey near the border with Syria. We reprocessed 2D seismic over these five prospects which were identified on the licenses and analyzed other available data to confirm their potential. Our evaluation concluded that there was no drillable prospect with an acceptable risk profile. In February 2006, we elected not to exercise the option and withdrew from the project.

Commercial Terms. Turkey’s fiscal regime is presently comprised of royalties and income tax. Royalties are at 12.5% and the corporate income tax is at a rate of 20%. The licenses have a four-year term but after the third year, a payment must be made to extend the license if no new well has been drilled prior to that date. The award of the licenses was based upon a work program that involves geological and geophysical work, seismic reprocessing and interpretation and contingent shooting of seismic and drilling of wells.

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. 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 for 20 years. Annual rentals are due based on the hectares under lease.

Nigeria. We originally acquired our interest in OML 109 in 1992. OML 109 is located approximately 15 kilometers offshore in water depths between 50 and 200 feet. We drilled both the discovery well and the first appraisal well in the Ejulebe field on OML 109 in 1994 and 1995. We then sought project financing to develop the field and install production facilities and entered into a risk service contract with Nexen (then known as CanOxy). Under a risk service contract with Nexen, Nexen paid all of the development capital, which totaled in excess of $100 million, and drilled development wells, installed a production platform and pipeline and put the Ejulebe field into production in 1998. The Ejulebe field had produced about 11 Mmbbls or about 50% of the estimated 22 Mmbbls in place through 2005 when production ceased. Nexen was paid a service fee out of production revenues. An additional exploitation well drilled in the Ejulebe field in 2001 doubled the field production rate and as a result, we started receiving revenues from the Ejulebe field starting in the first quarter of 2002. We realized net cash distributions of $12 million from Ejulebe crude sales through the first quarter of 2003. Additionally, an outstanding loan obligation from our Nigerian partner was paid off in 2002 resulting in receipt of an additional $3.2 million by us. After production dropped below the volume required for us to receive net cash flow under the service fee agreement, we received only designated minimum payments ($306,000 per year) in 2004 and until the sale in 2005.

In June 2005, we sold our Bahamian subsidiary which owned our 30% interest in OML 109. As part of the transaction, we received cash payments of $780,000 and 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 paid transaction costs of $220,000 (including legal, consulting and other deal-related costs) and, in addition, agreed to pay a bonus to our President for his efforts in completing this transaction equivalent to 3.75% of the deferred payments, if and when received, up to a maximum of $600,000. Absent a new discovery on OML 109 by the new owner, the retained net profits interest will not yield any revenue to us.

In addition, out of the $2.5 million reserved by us as an abandonment fund, $1.76 million was deposited into an escrow fund to address any liabilities and claims relating to our operations in OML 109 over the past 10 years, and the balance of approximately $720,000 was returned to us. The remaining escrow fund amount at December 31, 2006 is $961,000. Pursuant to an agreement reached in 2007, $406,000 of the remaining escrow amount has been allocated for payment of liabilities with respect to years 1998 through 2004. In connection with that agreement, $415,000 was released to us in the first quarter of 2007, and $240,000 remains in the escrow account. We believe the escrow fund provides adequate provision for the liabilities related to activities arising out of OML 109.

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Property and Equipment

(In thousands of U.S. dollars)

2006	Cost		Accumulated Depreciation and Depletion		Net Book Value
Crude oil and natural gas properties
United States	$	11,164	$	6,877	$	4,287
Romania		1,572		—		1,572
Furniture, fixtures and other assets		238		238		—
Balance, December 31, 2006	$	12,974	$	7,115	$	5,859
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
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		13
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 common shares and warrants exercisable for 500,000 common shares at $1.00 per share on or before April 15, 2007. The warrants expired unexercised. 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		133,434
Acquisition costs		58,630
	$	3,542,064
Assets acquired:
Property and equipment	$	3,892,064
Asset retirement obligations		(350,000	)
	$	3,542,064

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.

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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 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, 2006, 2005 and 2004. All of our reserves are located in the United States. Oil is expressed in Mbbls, and natural gas is expressed in Mmcf.

Proved Reserves⁽¹⁾

	Gross		Net
	Oil	Natural Gas	Oil	Natural Gas
Proved Developed Producing	13.4	5.9	9.7	4.3
Proved Developed Non-Producing	20.8	16.4	15.4	12.3
	34.2	22.3	25.1	16.6
Proved Undeveloped	0.0	0.0	0.0	0.0
2004 Total:	34.2	22.3	25.1	16.6
Proved Developed Producing	39.3	1,094.7	31.1	847.9
Proved Developed Non-Producing	23.6	139.6	17.0	107.9
	62.9	1,234.3	48.1	955.8
Proved Undeveloped	0.0	505.3	0.0	391.3
2005 Total:	62.9	1,739.6	48.1	1,347.1
Proved Developed Producing	8.9	483.3	7.2	374.0
Proved Developed Non-Producing	0.0	139.3	0.0	107.8
	8.9	622.6	7.2	481.8
Proved Undeveloped	0.0	0.0	0.0	0.0
2006 Total:	8.9	622.6	7.2	481.8

Notes:

(1) “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.

(2) “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.

(3) “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.

(4) “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.

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(5) “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.

(6) “Undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. 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.

(7) “Oil” volumes include condensate (light oil) and medium crude oil.

Our proved reserves decreased significantly at December 31, 2006 as compared to 2005. The decline in proved reserves resulted in a material increase in depreciation, depletion and accretion expense for the year as well as a $3.1 million impairment charge under Canadian GAAP in the fourth quarter to our oil and gas producing properties in the U.S. cost center. The impairment charge was largely due to lower reserves resulting from the sale of our non-operated interest in the Bayou Couba property, the failure to add substantial reserves at the Jarvis Dome property, significantly lower gas prices used to calculate the value of year-end 2006 reserves compared to 2005 and a significant increase in asset retirement cost estimates included in property and equipment for the South Gillock property. The lower anticipated production may result in reduced revenue in future periods as compared to prior years. The potential decrease in revenue could result in decreased cash flow from operations further increasing the need for outside sources of capital for workovers and drilling.

The following table sets forth the number of wells in which we held a working interest as of December 31, 2006:

	Oil		Natural Gas
	Gross(1)	Net(1)	Gross(1)	Net(1)
Texas (onshore)
Producing	2	2	2	2
Non-producing(2)	57	57	0	0

(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 forth our net production of oil (in bbls) and natural gas (in Mcf), after payment of royalties, as of December 31, 2006, 2005 and 2004:

	Net Production
Year	Oil(1)	Natural Gas
2004	15,884	41,317
2005	16,903	93,661
2006	8,975	129,867

(1) “Oil” volumes include condensate (light oil) and medium crude oil.

As of June 30, 2007, with respect to the properties in which we, as 100% operator, are responsible for future abandonment and reclamation costs, we have taken the total number of wells which we own (61) and, using third party estimated costs, have estimated the undiscounted cost (net of salvage value) to be $2.4 million and the cost discounted at 7% to be $1.9 million. In connection with the sale of our Jarvis Dome, South Gillock and State Kohfeldt properties in the third quarter of 2007, the buyers of the properties assumed these abandonment and reclamation liabilities.

Item 4A. Unresolved Staff Comments

Not applicable

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Item 5. Operating and Financial Review and Prospects

A. Operating Results

The following discussion for the three fiscal years ended December 31, 2006 and the comparative six month periods ended June 30, 2007 and 2006 should be read in conjunction with our consolidated financial statements and notes thereto.

Summary

Consolidated net revenues for the year ended December 31, 2006 were $1.6 million, which represents an increase of 14% from the $1.4 million reported for 2005. The increase in revenue is primarily due to higher oil and gas sales from the United States. Consolidated revenues for the year ended December 31, 2005 of $1.4 million represented a decrease of $3.7 million or 72% from the $5.1 reported for 2004. The decrease in revenue was primarily due to our cessation of production of crude oil in OML 109. Consolidated net revenues for the six months ended June 30, 2007 of $342,000 represented a substantial decrease from the $1.0 million reported for the six months ended June 30, 2006. This decrease is primarily due to the sale of our Bayou Couba property in December 2006 and declining production at our South Gillock property. The consolidated net loss for 2006 was $9.4 million or $0.25 loss per share (basic), compared to consolidated net loss of $3.8 million or $0.11 loss per share (basic) for fiscal 2005 and $5.2 million or $0.17 loss per share (basic) in 2004. The significant increase in the loss for 2006 as compared to 2005 comes from the expansion of foreign activities where $2.3 million was expensed towards the pre-acquisition, reconnaissance and evaluation of opportunities in Morocco, Romania, Turkey and the U.K. North Sea, a $400,000 loss on the sale of a debenture owned by us in connection with the Bayou Couba property disposition and an impairment of $3.1 million. The consolidated net loss for the six months ended June 30, 2007 was $3.1 million or $0.07 loss per share (basic), compared to consolidated net loss of $2.6 million or $0.07 per share (basic) for the six months ended June 30, 2006. The loss is primarily composed of $1.3 million relating to international expenditures and general and administrative expenses of $1.4 million.

We incurred $4.7 million in capital expenditures in 2006 compared to $4.8 million in 2005 and $1.7 million in 2004. The increase in capital expenditures in 2005 is due to the purchase of the South Gillock property in April 2005. At December 31, 2006, we had working capital of $2.2 million and significant capital expenditures projected for 2007. In the first quarter of 2007, we drilled and logged an exploratory well at the South Gillock property in Galveston County, Texas. The expenditures incurred in connection with this well, which we completed in June 2007, have had a significant adverse impact on our working capital. We are evaluating several options for additional sources of funding for 2007 to continue to develop our portfolio of properties, including farm-in arrangements at each of our projects, the sale of certain non-core properties, and one or more equity financings. We had 42,556,939 common shares outstanding at year-end 2006, compared to 37,659,189 at year-end 2005 and 31,852,241 at year-end 2004.

U.S. Operations

Revenue and Production. We recognized net oil and gas sales of $1.6 million for 2006 representing a 14% increase from 2005 sales of $1.4 million which is a result of higher sales volumes partially offset by slightly lower commodity prices. Net oil and gas sales for 2004 were $744,000. During the year, we had production from two operated fields in Texas (South Gillock and Jarvis Dome) as well as from our non-operated interest in Bayou Couba, Louisiana (first three quarters). Production for 2006 was impacted by continued declines at Bayou Couba as well as at South Gillock where the SGU #83 gas well declined more rapidly then anticipated and then had to be shut-in due to casing failure in December 2006. We produced 36,300 net barrels of oil equivalent (Boe) in 2006 compared to 30,962 Boe for 2005 and 21,600 Boe for 2004. 2005 revenue represented a 89% increase from 2004 sales of $744,000 from production in the U.S. as a result of the South Gillock property acquisition and higher commodity prices. At year-end 2006, our gross daily production was 392 mcf of gas and 25 barrels of oil compared to 887 mcf and 20 barrels, respectively, at year-end 2005. The reduction in daily production at year-end 2006 relates to the loss of the SGU #83 well and the sale of the Bayou Couba property.

We recognized net crude oil and natural gas sales of $342,000 for the first six months of 2007 representing 7,645 Boe ($57.26 per bbl of oil and $5.97 per mcf of gas) from field production in the United States. This U.S. revenue represented a substantial decrease from sales of $1.0 million during the same period in 2006. The decrease is primarily the result of reduced production from the South Gillock property when the SGU #83 well

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had to be shut-in at the end of 2006 due to casing problems as well as the sale of our interests in the Bayou Couba property in the fourth quarter 2006.

Operating and DDA Expenses. Lease operating expenses decreased 7% to $1.8 million in 2006 as compared to 2005. We continued to experience higher field costs and workover expenses at South Gillock related to the age and condition of the field as well as costs associated with workover and completion of the Brittani well at Jarvis Dome. Fiscal 2005 lease operating expenses declined 56% from $4.4 million in 2004, due to the cessation of activities in OML 109. Depreciation, depletion and accretion (“DDA”) increased to $1.5 million for 2006 as compared $606,000 for 2005 ($718,000 - 2004). This increase in DDA relates to lower reserves due to a substantially lower gas price at year end 2006 ($5.40 MMBtu) compared to year-end 2005 ($10.08 MMBtu). DDA decreased 16% for 2005 and represented a DDA rate per net equivalent barrel of $19.86, largely as a result of 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. DDA related to U.S. production decreased to $351,000 for the first six months of 2007 as compared with $549,000 during the same period in 2006, due primarily to the reduction in production in the first quarter 2007.

Lease operating expenses in the first six months of 2007 decreased to $482,000 from $1.0 million as reported for the first six months of 2006. The difference is largely due to nonrecurring workover costs at South Gillock of $338,000 incurred in the first quarter of 2006. Approximately $170,000 of the lease operating expenses in the first quarter 2007 relates to changing out pumping equipment at one of the South Gillock wells. General and administrative costs of $1.4 million in the first six months of 2007 increased compared to $1.5 million for same period in 2006, primarily because of charges of $295,000 for stock based compensation.

Exploration. In 2006 at South Gillock, we incurred costs of $220,000 towards the preparation of drilling the SGU #96 well. Subsequent to year-end 2006, we spudded the SGU #96 well which was drilled to a total measured depth of 9,860 feet and tested the principal producing zone (Big Gas Sand) as well as other deeper zones within the Frio formation. On June 29, 2007, we announced that the well had been completed in the Big Gas Sand formation and was producing approximately 1,000 Mcf per day. We acquired the South Gillock property in April 2005 for $3.0 million cash, 500,000 common shares and warrants exercisable for 500,000 common shares at an exercise price of $1.00 per share on or before April 15, 2007. All of these warrants expired unexercised.

In the first six months of 2007, we drilled the SGU #96 well on our South Gillock property and capitalized approximately $3.8 million (2006 - $300,000) in costs associated with this project. In addition, we capitalized approximately $140,000 of costs at our Oswego property in Dewey County, Oklahoma.

During 2006 we participated in three wells in Oklahoma and Texas. At Jarvis Dome in East Texas, we acquired a 100% working interest in 170 acres with two inactive wells, acquired an additional 630 acres, completed one work over (Brittani well) and drilled an exploratory horizontal well (Lasiter well). We incurred costs of $1.9 million towards these activities in Jarvis Dome. The Brittani well was initially put on production at 12 bbl/day but declined to 5 bbl/day at year end. The Lasiter well targeted a fractured limestone (Pecan Gap) which was projected to produce 1 to 2 mmcf/day. However, the Lasiter well was producing 130 mcf/day at year end and has now declined to 40 mcf/day; accordingly, we have considered the costs of the Lasiter well in the ceiling test. We incurred costs of $710,000 for our 20% participation in the first well drilled on the Oswego property in Dewey County, Oklahoma. That well is currently producing 32 bbls of oil and 47 mcf of natural gas per day.

An impairment of $3.1 million on U.S. properties was recorded for 2006. This impairment results from the write-off of Jarvis Dome ($1.7 million), the write-down relating to the sale of the Bayou Couba property, and a reduction of reserves due primarily to a 46% lower gas price used to calculate the value of year-end 2006 reserves compared to 2005.

Bayou Couba Sale. In December 2006, we sold for $2.0 million our non-operated interest in the Bayou Couba, Louisiana property to Dune Energy Inc. (Dune). Concurrent with this property sale, we also sold to Dune the debenture we held in American Natural Energy Corporation (ANEC). We recorded an impairment of our interests and a loss of $400,000 on the sale of our ANEC debenture.

International Operations

We continued to evaluate and expand our initiatives in Morocco, Romania, Turkey and the U.K. North Sea during 2006. Approximately, $2.3 million of costs was incurred and expensed from the pre-acquisition,

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reconnaissance, evaluation and development of our international oil and gas activities including technical, professional and administrative costs. In the first six months of 2007, we spent $1.3 million pursuing our international prospects. The following table outlines these expenditures by country for 2006, 2005 and 2004 and the six months ended June 30, 2007 and 2006:

	Six Months Ended June 30,				Year Ended December 31,
(In thousands of U.S. dollars)	2007		2006		2006		2005		2004
Morocco - Reconnaissance License and Exploration Permit	$	289	$	459	$	874	$	75	$	—
U.K. North Sea - Two Exploration Licenses		133		111		553		—		—
Romania - Three Production Licenses		664		173		605		—		—
Turkey - Three Exploration Licenses		150		149		222		96		—
Nigeria		—		—		—		—		4,902
Other Unallocated		106		18		25		269		—
Total	$	1,342	$	910	$	2,279	$	440	$	4,902

In addition to these costs, we also capitalized $1.6 million of expenditures related to the seismic surveys completed at the end of the year in Romania. These surveys included a 3D seismic survey at the Izvoru license and 2D seismic surveys at the Vanatori and Marsa licenses. The work programs for each of the licenses must be completed by September 2010. The Romanian programs will include re-entering up to nine wells on the Izvoru license and drilling one or more new wells on each license. The estimated cost to complete these programs is $7.4 million.

The most significant international development for 2006 was the signing of the Tselfat exploration permit in May 2006 covering 222,345 acres in northern Morocco. Tselfat has three former producing fields with existing shallow potential as well as deeper exploration potential. We are reviewing all the existing well and seismic data on the permit, and will likely reprocess some of the existing 2D seismic over the license area. In addition, we have committed to shooting a 3D survey over two of the former oil fields in the license area that will be followed by the drilling of an exploratory well. As a condition of the Tselfat permit, we posted $3.0 million in certificates of deposit to guarantee the Tselfat work program. In August 2007 we reached an agreement to farmout 50% of our interest in the Tselfat exploration permit to Sphere. In exchange for an option to acquire 50% of our interest in the Tselfat permit, Sphere will fund the costs to acquire a 110 square kilometers 3D seismic survey to be shot over the Haricha field and northern portion of the Bou Draa field in early 2008 and will also fund the cost of additional geological studies. It is estimated the 3D survey and the studies will cost approximately $4.5 million over the next year. Upon its exercise of the option, Sphere will (i) fund the drilling and testing of an exploratory well and (ii) replace our bank guarantee deposited with the Moroccan government.

On November 7, 2007, we announced that we converted a portion of our Guercif - Beni Znassen Reconnaissance License into two exploration permits covering a total of 3,893 square kilometers (962,000 acres) in the Guercif area in northeastern Morocco. Pursuant to a participation agreement between us (30%), Stratic (20%) and Sphere (50%), Sphere will bear the entire cost of the initial three-year work program to earn its 50% interest in the two Guercif exploration permits. Our interests and the interests of Sphere and Stratic are subject to the interest in the Guercif exploration permits held by the national oil company of Morocco, Office National des Hydrocarbures et des Mines, who is carried during the exploration phase but pays its 25% share of costs in the development phase. We will continue as operator of the Guercif exploration permits during the initial three-year period. The Guercif exploration permits are for an eight-year term divided into three periods. The initial three-year work program is estimated to cost more than U.S. $3 million and will include the re-entry of an existing well and the acquisition of 300 kilometers of 2D seismic. In addition, Sphere has posted the required bank guarantee for the initial work program with the Moroccan government and will reimburse us and Stratic for our back costs.

We have fulfilled all of our required commitments for the initial two years with respect to the U.K. North Sea property and are now actively seeking a farmout or partner for the property. By December 2007, we must commit to drill a well by the end of the fourth year of the license if we intend to retain our interests in the property.

In Turkey, we have six exploration licenses and plan to spend a total of $1.1 million on work programs during the terms of the licenses, three of which extend through June 2009 and three of which extend through June 2010. We spent $115,000 toward these work programs in 2006. We are actively seeking partners to assist in the development of the Turkey licenses, and in October 2007 we announced that we had agreed to the farmout of one of the licenses, Block 4175.

We have been actively marketing our international portfolio with the intent of bringing partners into the development of our projects and the completion of our work commitments.

During 2004 we received payments of $306,000 from our services contractor in OML 109. We also received $75,000 in payments from our services contractor in 2005 prior to the sale of OML 109 in June 2005. Gross sales of crude oil in OML 109 for 2004 were $4.9 million representing 240,118 barrels ($33.84 per equivalent barrel). DDA related to OML 109 property and equipment decreased to nil in 2004 since all capitalized costs related to OML 109 were fully depleted at December 31, 2003. With no reserves attributed to OML 109 at December 31, 2004, net property costs related to OML 109 were reduced to zero through depletion.

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G&A and Other Expenses

General and administrative costs of $2.4 million in 2006 were approximately the same as 2005. The increase from $1.8 million in 2004 is due to increased staff and consultants related to support of the South Gillock purchases and expanded business development activities. Other costs include a foreign exchange loss of $59,000 and $260,000 of stock-based compensation expense.

General and administrative costs of $899,000 in the first quarter 2007 increased compared to $602,000 for same quarter of 2006, primarily because of charges of $246,000 for stock based compensation.

Contingency

In conjunction with the sale of our Nigerian subsidiaries effective June 20, 2005, we deposited $1.76 million into an escrow account to address claims relating to prior operations in OML 109. The balance of the escrow fund at December 31, 2006 was $961,000. Pursuant to an agreement reached in 2007, $406,000 of the remaining escrow amount has been allocated for payment of liabilities with respect to years 1998 through 2004. In connection with that agreement, $415,000 was released to us in April 2007, and $240,000 remains in the escrow account. The remaining potential liability to us is for taxes owed for the period January through June 2005, and we expect the remaining escrow amount to be sufficient to cover any potential liabilities.

B. Liquidity and Capital Resources

As of December 31, 2006, we had cash and short-term investments of $4.7 million and working capital of $2.2 million compared to $9.1 million and $7.6 million, respectively, at December 31, 2005. We had cash and short-term investments of $11.4 million and working capital of $10.8 million at December 31, 2004. In 2007, we drilled and completed the SGU #96 exploratory well at our South Gillock property in Galveston County, Texas. We estimate we spent $4.1 million on drilling and completing the well.

We have work program commitments of $3.0 million under our Tselfat exploration permit in Morocco that are supported by fully-funded bank guarantees. The bank guarantees are reduced periodically based on work performed. In the event we fail to perform the required work commitments, the remaining amount of the bank guarantee would be forfeited. The Tselfat work commitments are due to be completed by March 2009.

We hold substantially all of our cash and short-term investments in U.S. dollars. Cash and cash equivalents held in local currencies (Canadian dollar, British pound sterling, Turkish lira, Moroccan dirham and Romanian lei) totaled approximately $200,000 at December 31, 2006, June 30, 2006 and June 30, 2007. We held $2.0 million and $100,000 in Canadian dollars at December 31, 2005 and December 31, 2004, respectively. We convert from U.S. dollars to other currencies as needed. Our treasury policy regarding liquidity management, including funding for capital expenditures and foreign exchange, are approved by our Chief Executive Officer and administered by our Chief Financial Officer.

Changes in cash, short-term investments and working capital

The decrease in cash and cash equivalents for 2006 was $2.9 million compared to the decrease of $2.1 million for fiscal 2005 and an increase in cash and cash equivalents of $5.0 million in 2004. The significant decrease in cash during 2006 was primarily due to cash used in operations of $3.3 million, an increase in restricted cash for the Tselfat work commitment guarantee of $3.0 million and the investment in oil and gas properties of $4.7 million in the U.S. and Romania. We received proceeds from the redemption of a short-term investment of $1.5 million plus accrued interest in March 2006 when the investment matured. We also received $2.0 million in December 2006 for proceeds from the sale of our non-operated interest in the Bayou Couba property and the debenture we held in ANEC. Working capital decreased approximately $5.3 million in 2006 as a result of a decrease in cash and short-term investment of $4.4 million and an increase in payables of approximately $1.0 million.

In 2005 cash and cash equivalents decreased due to cash used in operations of $1.8 million and the investment in oil and gas properties of $4.8 million in the U.S., including $3.0 million for purchase of the South Gillock property in April 2005. Working capital decreased approximately $3.3 million in 2005 mostly as a result of a decrease in cash and short-term investments of $2.3 million, and an increase in payables of $600,000.

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In January 2004 we raised net proceeds of $7.5 million from the private placement of stock and warrants. The increase in cash and cash equivalents in 2004 of $5.0 million resulted from the equity issuance less cash used in operation of approximately $955,000 and investment in U.S. oil and gas properties of $1.7 million.

As of June 30, 2007, we had cash of $624,000, $3.0 million in current debt and a working capital deficit of $3.2 million compared to cash and short-term investments of $3.0 million, no debt and positive working capital of $1.5 million, at June 30, 2006. The decrease in cash and working capital in the first six months of 2007 is primarily related to $3.8 million in cash expenditures for the SGU #96 well and $1.3 million in technical, professional and administrative costs for pre-acquisition, reconnaissance and evaluation of our international oil and gas activities.

In April 2007, we entered into a U.S. $3.0 million short-term standby bridge loan from Quest Capital Corp., a Canadian bank (“Quest”). We mortgaged certain of our assets, including the South Gillock property, and pledged 100% of the common stock of our wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. At closing, we paid Quest a loan fee totaling 132,353 common shares at a deemed price of $0.68 per share. In addition, we paid Quest an amount equal to 5% of the principal drawn down, payable in our common shares using a formula based on a discount to the five-day volume weighted average trading price. We drew down $1.0 million on the loan on April 16, 2007 and issued 64,766 common shares to Quest at a deemed issue price of $0.77 per share. We drew down $1.5 million on the loan on May 9, 2007 and issued 102,174 common shares to Quest at a deemed issue price of $0.73 per share. We drew down $500,000 on the loan on June 6, 2007 and issued 65,074 common shares to Quest at a deemed issue price of $0.38 per share. On August 10, 2007, we increased the loan facility to $4.0 million, and we drew down the additional $1.0 million on the loan and issued 139,456 common shares to Quest at a deemed issue price of $0.58 per share. On November 13, 2007, we paid down $2.0 million in principal on the loan in connection with the sale of our South Gillock property and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008. The outstanding principal balance bears interest at an effective annual rate of 16.27%.

We do not have sufficient funds to continue operations beyond March 2008. We will require significant additional funding to continue to develop our properties. Accordingly, we will continue to consider other debt or equity financing to meet our obligations. We will also consider sales and farmouts of our properties to raise capital. The development of our properties is also dependent on finding and developing additional oil and gas reserves, oil and gas prices and the availability of additional capital to continue project development.

We completed a private placement in December 2006 whereby we issued 4,500,000 Units at $0.85 per Unit for gross proceeds of $3.83 million. Each Unit consisted of one common share and one common share purchase warrant. Each warrant entitles the holder to acquire one common share at a price of $1.05 through December 4, 2008. The proceeds were used for U.S. exploration and development activities and general corporate purposes.

We completed a private placement in November 2005 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 warrant entitles the holder to acquire one common share at a price of $1.05 through November 17, 2007. The proceeds were used for U.S. and international exploration and development activities and general corporate purposes.

Portions of the December 2006 and November 2005 private placements were conducted in the United States. Neither transaction described above involved any public offering, and we believe that the transactions were exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof or Regulation D promulgated thereunder. The investors represented their intentions to acquire the securities for investment purposes only and not with a view to or for sale in connection with any distribution thereof, and appropriate legends were affixed to the instruments issued to them. The investors had adequate access, through their relationships with us or our agents, to information about us. The April 2007 loan transaction with Quest was conducted wholly within Canada in compliance with Canadian securities laws.

Asset Retirement Obligations

We have estimated undiscounted asset retirement obligations of $2.4 million as of June 30, 2007 for the abandonment and reclamation of oil and gas properties in the United States. In connection with the sale of our Jarvis Dome, South Gillock and State Kohfeldt properties in the third quarter of 2007, the buyers of the properties assumed these abandonment and reclamation liabilities.

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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 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 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 and refining 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, which may result 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 December 31, 2006, we had no off-balance sheet arrangements.

F. Contractual Obligations

The following table sets forth our contractual obligations as at December 31, 2006.

Payments Due By Period

(In thousands of U.S. dollars)

	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Operating Leases	$	336	$	80	$	164	$	92	—

We have a long-term lease for office space in the U.S. and office lease commitments of less than one year for offices in Romania, Turkey and Morocco.

We have work program commitments of $3.0 million under our Tselfat exploration permit in Morocco that is supported by a fully-funded bank guarantee. The bank guarantee is reduced periodically based on work performed. In the event we fail to perform the required work commitments, the remaining amount of the bank guarantee would be forfeited. We also hold six exploration licenses in Turkey, two exploration licenses in the U.K. North Sea and three production licenses in Romania. Under each of these licenses, we have a work program but have not posted any financial guarantee. If we fail to perform the work program under any of these licenses, we would risk forfeiture of that license.

We have estimated undiscounted asset retirement obligations of $2.4 million as of June 30, 2007 for the abandonment and reclamation of oil and gas properties in the U.S. In connection with the sale of our Jarvis Dome, South Gillock and State Kohfeldt properties in the third quarter of 2007, the buyers of the properties assumed these asset retirement obligations.

G. Forward Looking Statements

Certain statements in this registration statement, including those appearing under this Item 5, constitute “forward-looking statements” within the meaning of applicable U.S. and 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

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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 slowdowns; 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 or furnish to the United States Securities and Exchange Commission and 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; changes in any of the foregoing and other statements using forward-looking terminology 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 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	45
Brian B. Bayley	Director	54
Alan C. Moon	Director	61
Scott C. Larsen	President and Chief Executive Officer, Director	55
Hilda Kouvelis	Vice President and Chief Financial Officer	43
Dr. David Campbell	International Exploration Manager	54
Dr. Weldon Beauchamp	Consulting Geophysicist/Geologist	47
Jeffrey S. Mecom	Vice President and Secretary	41

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Michael D. Winn has served as a director since 2004. He has been the President of Terrasearch Inc., a consulting company that provides analysis on mining and energy companies, since he formed that company in 1997. Prior to that, 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
Reservoir Capital Corp.	TSX Venture Exchange
Sanu Resources Ltd.	TSX Venture Exchange

Brian B. Bayley has served as a director since 2001. Since 2003, Mr. Bayley has served as the Chief Executive Officer and President of Quest Capital Corp, a publicly traded merchant banking organization that focuses on providing financial services, specifically bridge loans, to small and mid-cap companies in North America. Prior to that, he served as Chief Executive Officer of Quest Investment Corporation, a publicly listed merchant bank based in Vancouver. 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
Kirkland Lake Gold Inc.	TSX
Midway Gold Corp.	TSX Venture Exchange
PetroFalcon Corp.	TSX
Pretium Capital Corp.	TSX Venture Exchange
Quest Capital Corp.	TSX
Rockhaven Resources Ltd.	CNQ
Sanu Resources Ltd.	TSX Venture Exchange
Torque Energy Inc.	TSX Venture Exchange

Alan C. Moon has served as a director since 2004. Mr. Moon has been the President of Crescent Enterprises Inc., a private Calgary-based consulting firm, since he formed that company in 1997. Prior to that, 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
Lake Shore Gold Corp.	TSX Venture Exchange
Maxy Gold Corp.	TSX Venture Exchange
Enervest Diversified Income Trust	TSX

Mr. Winn, Mr. Bayley and Mr. Moon estimate that they devote 20%, 5% and 5% of their time, respectively, to the business and affairs of TransAtlantic.

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 industry, Mr. Larsen previously served as general counsel for Humble Exploration Company, Inc., a Dallas, Texas independent exploration company, spent several years as a partner in Vineyard, Drake and Miller, a business litigation law firm in Dallas, Texas and served as general counsel for

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Summit Partners Management Co., a venture capital and management company based in Dallas, Texas. He received a B.A. degree in biology from Rutgers College and a J.D. degree from Rutgers School of Law.

Hilda D. Kouvelis has served as our Chief Financial Officer since January 2007. She served as our Controller since joining us in June 2005. Prior to that, Ms. Kouvelis served as Controller for Ascent Energy, Inc. from 2001 to 2004. 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 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.

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 in 2000, 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 in 2000, 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 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., 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.

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 2006 for our directors, chief executive officer and chief financial officer.

	Salary		Bonus		Other Annual Compensation			Options Granted
								Number	Exercise Price		Expiry Date
Scott C. Larsen President, Chief Executive Officer and Director	$	240,000	$	-0-	$	-0-		70,000	$	1.10	April 5, 2011
Christopher H. Lloyd(1) Chief Financial Officer	$	144,000	$	-0-	$	-0-		-0-		—	—
Michael D. Winn Director		-0-		-0-	$	60,000	(2)	-0-		—	—
Brian B. Bayley Director		-0-		-0-	$	12,000	(2)	-0-		—	—
Alan C. Moon Director		-0-		-0-	$	12,000	(2)	-0-		—	—

(1) 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; we participated in the syndication and the loan has now been repaid. Mr. Lloyd’s employment terminated in January 2007.

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(2) Represents director fees paid in accordance with resolutions passed by our Compensation Committee. In 2006, none of the non-executive directors were granted stock options. However, in January 2007 for services rendered in 2006, Michael Winn was granted options to acquire 150,000 common shares, Brian Bayley was granted options to acquire 50,000 common shares and Alan Moon was granted options to acquire 50,000 common shares.

The following table sets forth details of all stock options exercised in fiscal 2006 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	80,000	$	0.35	$	0.86	$	40,800

C. Board Practices

Term of Office. At the end of fiscal 2006, we had four directors. The terms of all four expire at the 2008 annual meeting of shareholders:

Name	Term Expires	Held Office Since
Michael D. Winn	May 2008	May 2004
Brian B. Bayley	May 2008	May 2001
Alan C. Moon	May 2008	May 2004
Scott C. Larsen	May 2008	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

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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, 2006, our TransAtlantic Petroleum (USA) Corp. subsidiary employed seven people full time. The persons employed are the Chief Executive Officer, the Chief Financial Officer, and five persons in accounting, geology, 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 2006.

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

As of October 31, 2007, 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
The Rule Family Trust	4,050,394	9.4	%

Our major shareholders do not have different voting rights than any other shareholders. As of October 31, 2007, our shareholders list showed 43,270,762 common shares outstanding with 219 registered shareholders in Canada holding 32,264,583 common shares. We are not controlled, directly or indirectly, by any corporation, foreign government or other person. There has been no significant change in the percentage ownership held by major shareholders during the past three years.

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, 2004, or in any proposed transaction involving us.

We made investments (in unrelated parties) in the amount of $1.5 million in loan syndications through Quest Capital Corp. in 2004 and 2005. All were secured, short term investments. In April 2007, we entered into a U.S. $3.0 million short-term standby bridge loan from Quest Capital Corp. (“Quest”). We mortgaged certain of our assets, including the South Gillock property, and pledged 100% of the common stock of our wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. On August 10, 2007, we increased the loan facility to $4.0 million. On November 13, 2007, we paid down $2.0 million in principal on the loan in connection with the sale of our South Gillock property and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008. The outstanding principal balance bears interest at an effective annual rate of 16.27%. 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 and the credit agreement.

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 $3.0 million of convertible debentures issued by ANEC. He was also on the board of ANEC when we sold our ANEC convertible debentures and our 10% interest in the Bayou Couba property to Dune Energy, Inc. Mr. Bayley abstained from voting on all three 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 fiscal 2006, we received net payments (oil and gas sales plus debenture interest less drilling advances and lease operating expenses) of $345,000 (fiscal 2005 – $163,000) from ANEC. These transactions have been recorded at the exchange amount agreed to between the related parties.

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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 OML 109 interests in June 2005. 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 OML 109, if and when any such net profits are actually received, up to a total bonus payment of $600,000.

Christopher H. Lloyd, our former 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; we participated in the syndication and the loan has now been repaid.

Each of the above transactions was conducted in an arms-length manner.

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

In April 2007, we entered into a U.S. $3.0 million short-term standby bridge loan from Quest. We mortgaged certain of our assets, including the South Gillock property, and pledged 100% of the common stock of our wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. At closing, we paid Quest a loan fee totaling 132,353 shares of our common stock at a deemed price of $0.68 per share. In addition, we paid Quest an amount equal to 5% of the principal drawn down, payable in our common shares using a formula based on a discount to the five-day volume weighted average trading price. We drew down $1.0 million on the loan on April 16, 2007 and issued 64,766 common shares to Quest at a deemed issue price of $0.77 per share. We drew down $1.5 million on the loan on May 9, 2007 and issued 102,174 common shares to Quest at a deemed issue price of $0.73 per share. We drew down $500,000 on the loan on June 6, 2007 and issued 65,074 common shares to Quest at a deemed issue price of $0.38 per share. On August 10, 2007, we increased the loan facility to $4.0 million, and we drew down the additional $1.0 million on the loan and issued 139,456 common shares to Quest at a deemed issue price of $0.58 per share. On November 13, 2007, we paid down $2.0 million in principal on the loan in connection with the sale of our South Gillock property and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008. The outstanding principal balance bears interest at an effective annual rate of 16.27%.

Item 9. The Offer and Listing

A. Offer and Listing Details

See Item 9.C below.

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, 2007, we had 43,131,306 common shares outstanding. Our common shares are issued in registered form and the number of common shares 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

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transfer agent for our common shares. For U.S. reporting purposes, we are a foreign private issuer. We currently have no established market for trading our common shares in the United States. The high and low prices for our common shares from January 1, 2002 through December 31, 2006 on the TSX are as follows:

	High ($US)		Low ($US)
January 1, 2002 through December 31, 2002	$	0.03	$	0.19
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
January 1, 2006 through December 31, 2006	$	1.48	$	0.76

The high and low prices for our common shares for each quarter from January 1, 2005 through September 30, 2007 on the TSX are as follows:

	High ($US)		Low ($US)
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
July 1, 2006 through September 30, 2006	$	1.48	$	1.05
October 1, 2006 through December 31, 2006	$	1.12	$	0.76
January 1, 2007 through March 31, 2007	$	0.99	$	0.64
April 1, 2007 through June 30, 2007	$	0.92	$	0.35
July 1, 2007 through September 30, 2007	$	0.68	$	0.25

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

	High ($US)		Low ($US)
May 1, 2007 through May 31, 2007	$	0.90	$	0.40
June 1, 2007 through June 30, 2007	$	0.48	$	0.35
July 1, 2007 through July 31, 2007	$	0.68	$	0.48
August 1, 2007 through August 31, 2007	$	0.60	$	0.34
September 1, 2007 through September 30, 2007	$	0.40	$	0.25
October 1, 2007 through October 31, 2007	$	0.31	$	0.26

Warrants. In December 2006 we issued 4,500,000 Units at a price of $0.85 per Unit. Each Unit consisted of one common share and 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 December 2008; provided however, if the volume weighted average closing price of our common shares exceeds $1.55 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 warrants to acquire 219,375 common shares as fees to our financial advisors exercisable on the same terms as the warrants forming part of the financing Units.

In November 2005, pursuant to a financing, we issued 5,000,000 Units at a price of $0.85 per Unit. 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 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 warrants to acquire 375,000 common shares to the underwriters exercisable on the same terms as the warrants forming part of the financing Units.

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Portions of the December 2006 and November 2005 private placements were conducted in the United States. Neither transaction described above involved any public offering, and we believe that the transactions were exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof or Regulation D promulgated thereunder. The investors represented their intentions to acquire the securities for investment purposes only and not with a view to or for sale in connection with any distribution thereof, and appropriate legends were affixed to the instruments issued to them. The investors had adequate access, through their relationships with us or our agents, and from public sources, to information about us.

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 entitled the holder to acquire one common share at a price of $1.00 per share until April 15, 2007. All of these warrants expired unexercised.

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, 2006 and June 30, 2007, we had 42,556,939 and 43,131,306, respectively, common shares issued and outstanding. As of December 31, 2006 and June 30, 2007, we had outstanding an aggregate of 2,280,000 and 3,410,000, respectively, options to purchase common shares pursuant to our Amended and Restated Stock Option Plan (2006). As of December 31, 2006 and June 30, 2007, we also had outstanding 7,976,625 and 7,451,625, respectively, share purchase warrants related to private placements which closed in December 2006 and November 2005. Each of the outstanding 2,732,250 November 2005 warrants entitles the holder to acquire one common share at a price of $1.05 through November 6, 2007. Each of the outstanding 4,719,375 December 2006 warrants entitles the holder to acquire one common share at a price of $1.05 through December 4, 2008. 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. If the volume weighted average closing price of our common shares exceeds $1.55 per share for 20 consecutive trading days, we are entitled to accelerate expiration of the December 2006 warrants, thereby requiring the warrant holder to exercise the warrant within 30 days of being notified of the accelerated expiration.

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

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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 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,

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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. In accordance with the terms of the agreement, one of our subsidiaries pays a portion of Mr. Larsen’s annual salary to Charles Management Inc., a consulting company wholly-owned by Mr. Larsen.

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. Mr. Lloyd’s employment was terminated in January 2007, and he received $79,500 in severance pay per the terms of his employment agreement.

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 in June 2005 concerning the sale of OML 109 assets (the “Compensation Agreement”). Under the participating interest agreement, Mr. Larsen will receive 3.87% of any “TWL Compensation” (as defined in the Compensation Agreement) we receive, provided that in no event will Mr. Larsen receive more than $600,000 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 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.

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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 December 2006 we issued 4,500,000 Units at a price of $0.85 per Unit. Each Unit consisted of one common share and 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 December 2008; provided however, if the volume weighted average closing price of our common shares exceeds $1.55 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 warrants to acquire 219,375 common shares as fees to our financial advisors exercisable on the same terms as the warrants forming part of the financing Units.

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 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 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 warrants to acquire 375,000 common shares 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 entitled the holder to acquire one common share at a price of $1.00 per share until April 15, 2007. All of these warrants expired unexercised.

Credit Agreement. In April 2007, we entered into a U.S. $3.0 million short-term standby bridge loan from Quest. We mortgaged certain of our assets, including the South Gillock property, and pledged 100% of the common stock of our wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. At closing, we paid Quest a loan fee totaling 132,353 shares of our common stock at a deemed price of $0.68 per share. In addition, we paid Quest an amount equal to 5% of the principal drawn down, payable in our common shares using a formula based on a discount to the five-day volume weighted average trading price. We drew down $1.0 million on the loan on April 16, 2007 and issued 64,766 common shares to Quest at a deemed issue price of $0.77 per share. We drew down $1.5 million on the loan on May 9, 2007 and issued 102,174 common shares to Quest at a deemed issue price of $0.73 per share. We drew down $500,000 on the loan on June 6, 2007 and issued 65,074 common shares to Quest at a deemed issue price of $0.38 per share. On August 10, 2007, we increased the loan facility to $4.0 million, and we drew down the additional $1.0 million on the loan and issued 139,456 common shares to Quest at a deemed issue price of $0.58 per share. On November 13, 2007, we paid down $2.0 million in principal on the loan in connection with the sale of our South Gillock property and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008. The outstanding principal balance bears interest at an effective annual rate of 16.27%.

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.

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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, 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

42

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.

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 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.

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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 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, 2006 and 2005, and for each of the years in the three year period ended December 31, 2006, have been included herein and in the registration statement, in

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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, 2006.

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 100 F. Street, NE, 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.

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 2006 production levels, if 2006 average natural gas prices were to change by $0.50 per mcf, the impact on our earnings and cash flow would have been approximately $936,000; if the 2006 average oil prices were to change by $1.00 per bbl, the impact on our earnings and cash flow would have been approximately $753,000.

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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 2006 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 $50,000 (all exchange costs are calculated as 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, 2006, we had approximately $3.9 million invested in money market funds which bear interest at floating rates. If average interest rates for 2006 were to change by one full percentage point, the net impact on our earnings and cash flow for 2006 would have been approximately $61,000.

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

	Estimated 2006 impact on:
Sensitivities	Earnings		Cash Flow
Natural gas - US$0.50/mcf change	$	74,283	$	74,283
Crude oil - $1.00/bbl change	$	11,505	$	11,505
Foreign exchange — 10% change in the F/X Canadian to U.S. $	$	49,730	$	49,730
Interest rate - 1% change (money markets only)	$	61,275	$	61,275

Item 12. Description of Securities Other than Equity Securities

Not applicable.

PART II.

Item 13. Defaults, Dividend Arrearages and Delinquencies

Not applicable.

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

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.

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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

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as at December 31, 2006 and December 31, 2005	F-3
Consolidated Statements of Loss and Deficit for the Years Ended December 31, 2006, December 31, 2005 and December 31, 2004	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, December 31, 2005 and December 31, 2004	F-5
Notes to Consolidated Financial Statements	F-6
Interim Consolidated Balance Sheets as at June 30, 2007 and December 31, 2006 (Unaudited)	F-19
Interim Consolidated Statements of Operations, Comprehensive Loss and Deficit for the Three and Six Months Ended June 30, 2007 and June 30, 2006 (Unaudited)	F-20
Interim Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2007 and June 30, 2006 (Unaudited)	F-21
Notes to Consolidated Financial Statements (Unaudited)	F-22

Item 18. Financial Statements

Not Applicable.

Item 19. Exhibits

See Exhibit Index.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

TransAtlantic Petroleum Corp.

We have audited the accompanying consolidated balance sheets of TransAtlantic Petroleum Corp. ( the “Company”) and subsidiaries as at December 31, 2006 and 2005 and the consolidated statements of loss and deficit and cash flows for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance 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 consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company and subsidiaries as at December 31, 2006 and 2005 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006 in accordance with Canadian generally accepted accounting principles.

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

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada

April 2, 2007, except for note 13, which is as of July 20, 2007 and note 1, which is as of November 13, 2007

F-1

COMMENTS BY AUDITORS FOR US READERS ON CANADA – US REPORTING DIFFERENCES

To the Board of Directors of TransAtlantic Petroleum Corp.

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when the financial statements are affected by conditions and events that cast substantial doubt on the Company’s ability to continue as a going concern, such as those described in note 1 to the consolidated financial statements. Our report to the board of directors dated April 2, 2007, except for note 13, which is as of July 20, 2007, and note 1, which is as of November 13, 2007, is expressed in accordance with Canadian reporting standards, which do not permit a reference to such events and conditions in the auditors’ report when these are adequately disclosed in the financial statements.

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principle that has a material effect on the comparability of the Company’s financial statements, such as the change described in note 13 to the consolidated financial statements as at December 31, 2006 and 2005 and for each of the years in the three-year period ended December 31, 2006. Our report to the board of directors dated April 2, 2007, except for note 13, which is as of July 20, 2007, and note 1, which is as of November 13, 2007, is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

“KPMG LLP”

Chartered Accountants

Calgary, Canada

April 2, 2007, except for note 13, which is as of July 20, 2007 and note 1, which is as of November 13, 2007.

F-2

TRANSATLANTIC PETROLEUM CORP.

Consolidated Balance Sheets

December 31, 2006 and 2005

(Thousands of U.S. Dollars)

	2006			2005
Assets
Current assets
Cash and cash equivalents	$	4,688		$	7,567
Short-term investment (note 10)		—			1,500
Accounts receivable		422			780
Marketable securities (note 3(a))		—			92
Other current assets		84			8
		5,194			9,947
Restricted cash (notes 2, 11 and 12)		4,339			2,110
Property and equipment (note 4)		5,859			5,813
Investments (note 3(b))		—			1,057
	$	15,392		$	18,927
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	1,990		$	924
Settlement provision (notes 4 and 11)		961			1,511
		2,951			2,435
Asset retirement obligations (note 5)		1,939			556
Shareholders’ equity
Share capital (note 6)		23,164			20,476
Warrants (note 6)		2,017			3,502
Contributed surplus (note 6)		4,284			1,508
Deficit		(18,963	)		(9,550	)
		10,502			15,936
Going concern (note 1)
Commitments (notes 4 and 12)
Subsequent events (notes 1 and 11)
	$	15,392		$	18,927

See accompanying notes to consolidated financial statements.

Approved by the Board of Directors:
“Brian Bayley”	Director
“Alan Moon”	Director

F-3

TRANSATLANTIC PETROLEUM CORP.

Consolidated Statements of Loss and Deficit

Years ended December 31, 2006, 2005 and 2004

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

	2006			2005			2004
Revenues
Oil and gas sales	$	2,149		$	1,598		$	6,359
Royalties		536			189			1,251
Oil and gas sales, net of royalties		1,613			1,409			5,108
Expense
Lease operating and other production costs		1,779			1,918			4,396
International oil and gas activities (note 4)		2,279			440			—
Depreciation, depletion and accretion		1,513			606			718
Write down of property and equipment (note 4)		3,061			—			1,235
General and administrative		2,441			2,295			1,823
Write down of investment (note 3(b))		157			112			2,100
Settlement provision (note 11)		—			905			600
Gain on sale of marketable securities (note 3(a))		(118	)		—			—
Loss on sale of investment (note 3(b))		400			—			—
Gain on sale of subsidiary (note 4)		—			(180	)		—
Foreign exchange loss (gain)		59			29			(130	)
		11,571			6,125			10,742
Interest and other income		545			943			441
Net loss for the year		9,413			3,773			5,193
Deficit, beginning of year		9,550			5,777			584
Deficit, end of year	$	18,963		$	9,550			5,777
Loss per share - basic and diluted (note 6)	$	0.25		$	0.11		$	0.17

See accompanying notes to consolidated financial statements.

F-4

TRANSATLANTIC PETROLEUM CORP.

Consolidated Statements of Cash Flows

Years ended December 31, 2006, 2005 and 2004

(Thousands of U.S. Dollars)

	2006			2005			2004
Cash provided by (used in)
Operating activities
Net loss for the year	$	(9,413	)	$	(3,773	)	$	(5,193	)
Items not involving cash
Gain on sale of subsidiary		—			(180	)		—
Gain on sale of marketable securities		(118	)		—			—
Loss on sale of investment		400			—			—
Depreciation, depletion and accretion		1,513			606			718
Stock-based compensation		260			410			714
Write down of property and equipment		3,061			—			1,235
Write down of investment		157			112			2,100
Changes in non-cash working capital		798			1,022			(529	)
		(3,342	)		(1,803	)		(955	)
Investing activities
Property and equipment		(4,737	)		(4,839	)		(1,706	)
Proceeds from sale of property and equipment and investment		2,000			—			155
Proceeds on sale of subsidiary		—			180			—
Proceeds on sale of marketable securities		210			—			—
Restricted cash		(2,229	)		356			(32	)
Redemption of short-term investments		1,500			—			—
Marketable securities		—			(268	)		—
Investments		—			104			—
		(3,256	)		(4,467	)		(1,583	)
Financing activities
Exercise of warrants and options		222			—			—
Issuance of common shares, net		3,497			4,187			7,519
		3,719			4,187			7,519
Change in cash and cash equivalents		(2,879	)		(2,083	)		4,981
Cash and cash equivalents, beginning of year		7,567			9,650			4,669
Cash and cash equivalents, end of year	$	4,688		$	7,567		$	9,650
Supplemental cash flow information:
Interest received	$	305		$	943		$	411
Interest paid		64			—			—

See accompanying notes to consolidated financial statements.

F-5

TRANSATLANTIC PETROLEUM CORP.

Notes to Consolidated Financial Statements

Years ended December 31, 2006, 2005 and 2004

(Tabular amounts in 000’s of U.S. Dollars unless otherwise noted)

1. Going concern

These financial statements have been prepared on the basis of accounting principles applicable to a going concern, which assumes that TransAtlantic Petroleum Corp. (the “Company”) will realize its assets and discharge its liabilities in the normal course of operations.

At December 31, 2006, the Company had cash and cash equivalents of $4.69 million, no long term debt and a working capital balance of $2.2 million. During the year ended December 31, 2006, the Company incurred a net loss of $9.4 million (2005 – $3.77 million) and utilized funds from operations totaling $3.34 million (2005 – $1.80 million).

The Company estimates that it does not have sufficient funds to continue in operation past March 2008. Subsequent to December 31, 2006, the Company has drilled the SGU #96 well for costs totaling approximately $4.1 million. Although the Company completed this well in June 2007, the Company will require significant immediate funding to continue its exploration, development and operating activities. In April 2007, the Company entered into a U.S. $3.0 million short-term standby bridge loan from Quest Capital Corp. (“Quest”) (see note 10). The Company mortgaged certain of its assets, including the South Gillock property, and pledged 100% of the common stock of its wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. At closing, the Company paid Quest a loan fee totaling 132,353 shares of its common stock at a deemed price of $0.68 per share. In addition, the Company paid Quest an amount equal to 5% of the principal drawn down, payable in our common shares using a formula based on a discount to the five-day volume weighted average trading price. The Company drew down $1.0 million on the loan on April 16 and issued 64,766 shares to Quest at a deemed issue price of $0.77 per share. The Company drew down $1.5 million on the loan on May 9 and issued 102,174 shares to Quest at a deemed issue price of $0.73 per share. The Company drew down $500,000 on the loan on June 6 and issued 65,074 shares to Quest at a deemed issue price of $0.38 per share. On August 10 the Company and Quest increased the loan facility to $4.0 million, and the Company drew down the additional $1.0 million and issued 139,456 shares to Quest at a deemed issue price of $0.58 per share. On November 13, 2007, the Company paid down $2.0 million in principal on the loan in connection with the sale of the Company’s South Gillock property and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008. The outstanding principal balance bears interest at an effective annual rate of 16.27%.

On August 10, 2007, the Company and Quest amended their standby bridge loan agreement to increase the loan facility from $3.0 million to $4.0 million. The Company drew down the additional $1.0 million on August 10 and issued 139,456 shares to Quest at a deemed issue price of $0.58 per share.

On August 27, 2007, the Company announced that it has reached an agreement to farmout 50% of its interest in the Tselfat exploration permit to Sphere Petroleum QSC. In exchange for an option to acquire 50% of the Company’s interest in the Tselfat permit, Sphere will fund the costs to acquire a 110 square kilometer 3D seismic survey to be shot over the Haricha field and northern portion of the Bou Draa field in early 2008 and will also fund the cost of additional geological studies. Upon its exercise of the option, Sphere will (i) fund the drilling and testing of an exploratory well; and (ii) replace the Company’s bank guarantee deposited with the Moroccan government. The Company will remain as operator of the permit through this exploration phase which extends to May 2009.

On September 27, 2007, the Company announced that it received final government approval of the three production licenses in Romania which were awarded to the Company in 2006. In October 2007, the Company announced the farmout of one of its licenses in Turkey, Block 4175. In October 2007, the Company sold its Jarvis Dome property for $250,000.

On November 7, 2007, the Company announced that it converted a portion of its Guercif - Beni Znassen Reconnaissance License into two exploration permits covering a total of 3,893 square kilometers (962,000 acres) in the Guercif area in northeastern Morocco. Pursuant to a participation agreement between the Company (30%), Stratic Energy Corporation (“Stratic”) (20%) and Sphere Petroleum QSC (“Sphere”) (50%), Sphere will bear the entire cost of the initial three-year work program to earn its 50% interest in the two Guercif exploration permits. The Company’s interests and the interests of Sphere and Stratic are subject to the interest in the Guercif exploration permits held by the national oil company of Morocco, Office National des Hydrocarbures et des Mines, who is carried during the exploration phase but pays its 25% share of costs in the development phase. The Company will continue as operator of the Guercif exploration permits during the initial three-year period. The Guercif exploration permits are for an eight-year term divided into three periods. The initial three-year work program will include the re-entry of an existing well and the acquisition of 300 kilometers of 2D seismic. In addition, Sphere has posted the required bank guarantee for the initial work program with the Moroccan government and will reimburse the Company and Stratic for their back costs.

On November 12, 2007, the Company announced that it sold the South Gillock and State Kohfeldt Units, as well as the shallow rights over the South Gillock Unit, for $4.0 million, and the buyer has assumed the plugging and abandonment liability associated with the units.

In connection with the sale, the Company paid down $2.0 million in principal on its short-term standby bridge loan and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008.

Management and the Board of Directors continue to explore funding alternatives. Management considers the going concern assumption to be appropriate for these financial statements. If the going concern assumption were not appropriate for these financial statements, then adjustments would be necessary to the carrying value of assets and liabilities, reported expenses and the balance sheet classifications used.

2. 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 the Company and its wholly owned subsidiaries.

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) 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 or 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 or market of unproved properties.

F-6

The cash flows are estimated using the future product prices and costs and are discounted using a risk-free rate. The adoption of the new guideline had no impact on the Company’s financial statements.

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. The Company expenses pre-acquisition and reconnaissance activities. 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.

Depreciation of furniture, fixtures and other assets 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) 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.

F-7

(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, 2006, restricted cash includes: $961,000 in respect of the settlement of Nigerian liabilities (see note 11), $3.35 million in certificates of deposit supporting guarantees of the Morocco work programs (see note 12) and $26,000 relates to the certificate of deposit that is a collateral for the Amegy letter of credit in favor of the Oklahoma Tax Commission.

(j) Marketable securities and investments

Marketable securities are stated at the lower of cost or market on a portfolio basis. Other long-term investments were carried at the lower of cost or estimated net realizable value.

3. Investments

(a) Marketable securities

The Company sold its shares in Transco Resources and Tuscany Energy during the year ended December 31, 2006. The Company recognized a $118,000 gain on the sale of these securities.

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

	Number Of Shares December 31,			Cost Basis December 31,					Market Value December 31,
Security (all Common in 000’s)	2006	2005	2004	2006	2005		2004		2006	2005		2004
Transco Resources	—	100	100	—	$	27	$	27	—	$	111	$	22
Tuscany Energy	—	325	—	—		65		—	—		128		—
American Natural Energy Corp. (b)	—	—	176	—		—		35	—		—		21
	—	425	276	—	$	92	$	62	—	$	239	$	43

(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 $268,000 or $0.12 per share. These shares were carried at the closing stock price of $0.07 per share, or $157,000, as of December 31, 2005. Based upon an analysis of ANEC’s financial position, the Company determined it appropriate to reserve $157,000 against the investment as at December 31, 2006.

On December 22, 2006, the Company sold a property in the U.S. and all of the ANEC 8% convertible debentures it held for $2.0 million in cash. The debentures, the value of which the Company had previously written down to $900,000, had matured and were in default. At the time of the sale, a director of the Company was also a director of ANEC. Of the proceeds received and

F-8

as per the sales agreement, $500,000 was allocated to the debentures resulting in a loss on sale of investments totaling $400,000. The remaining $1.5 million was allocated to property and equipment.

4. Property and equipment

2006	Cost		Accumulated depreciation and depletion		Net book value
Crude oil and natural gas properties
United States	$	11,164	$	6,877	$	4,287
Romania		1,572		—		1,572
Furniture, fixtures and other assets		238		238		—
Balance, December 31, 2006	$	12,974	$	7,115	$	5,859
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) United States:

On April 15, 2005, the Company completed the purchase of the South Gillock property 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 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
Common shares		350
Warrants		133
Acquisition costs		59
	$	3,542
Assets acquired:
Property and equipment	$	3,892
Asset retirement obligations		(350	)
	$	3,542

(b) Nigeria:

Effective June 20, 2005, the Company sold its Bahamian subsidiary which owned a 30% interest in certain properties, offshore Nigeria. In consideration, the Company received $540,000 prior to disposal costs of $220,000 (including legal, consulting and other deal-related costs) a subsequent cash payment of $240,000 and contingent compensation of up to a maximum of $16 million. A bonus equivalent to 3.87% of the contingent compensation (up to a maximum of $600,000) 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) in 2005. Of the $1.5 million reserved at December 31, 2005, $961,000 remained in escrow as of December 31, 2006 to address any remaining claims relating to the Company’s prior operations in Nigeria (see note 11).

(c) Morocco:

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 remaining work commitment is estimated to cost

F-9

$120,000 and is required to be completed by June 2007. The license expired at the end of June 2007, and the Company is currently in ongoing discussions with the government to convert the license into an exploration permit.

In May 2006 the Company was awarded an exploration permit in Morocco. To retain the permit beyond the initial three-year term, the Company is required to shoot a 3D survey and drill an exploratory well.

The Company posted $3.35 million in certificates of deposit pursuant to a guarantee of the work programs in Morocco and this amount plus accrued interest on the deposits is included in restricted cash at December 31, 2006. This amount reflects a $300,000 reduction to the certificates of deposit in August 2006 for cash expenditures in Morocco.

(d) Romania:

The Company capitalized $1.6 million of expenditures related to seismic surveys completed at the end of the year in Romania.

(e) Other countries:

Throughout 2006, the Company continued to evaluate and expand its initiatives in Morocco, Romania, Turkey and the U.K. North Sea. Approximately, $2.3 million was incurred and expensed towards the pre-acquisition, reconnaissance, evaluation and development of the Company’s international oil and gas activities including technical, professional and administrative costs.

(f) Ceiling test:

Based upon a ceiling test at December 31, 2006, the Company recorded an impairment of $3.1 million related to its U.S. cost center. This impairment was largely due to lower reserves and prices at December 31, 2006 and an increase in the estimated asset retirement costs for the South Gillock property. The Company recorded an impairment of $1.2 million related to its United States cost center based upon a ceiling test at December 31, 2004. The impairment was largely due to dry-hole costs incurred at the Bayou Couba property. At December 31, 2006, $1.7 million (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 $25,000 (2005 – $553,000; 2004 - nil) were included in the computations of depreciation and depletion for the year. Unproved property costs of $894,000 (2005 - $362,000; 2004 - nil) and drilling wells in progress of $935,000 (2005 – nil; 2004 - nil) were excluded from depletion and depreciation.

The following table summarizes the pricing used in the December 31, 2006 ceiling test:

Year ending December 31,	Oil Price ($/BBL)		Gas Price ($/MMBTU)
2007	$	60.72	$	5.71
2008		66.07		6.97
2009		—		6.18
2010		—		5.66
Thereafter -		—		3.61

5. 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, 2006 the net present value of the Company’s total ARO is estimated to be $1.9 million (2005 - $556,000), with the undiscounted value being $2.4 million (2005 - $958,000). The majority of these obligations are not expected to begin until 2010. A discount rate of 7% was used to calculate the present value of the ARO.

	2006			2005
Beginning balance	$	556		$	155
Sale of oil and gas property (note 3(b))		(171	)		—
Revision of estimate		1,341			—
Liabilities incurred		86			350
Accretion expense		127			51
Ending balance	$	1,939		$	556

F-10

6. Share capital

(a) Authorized

Unlimited number of common shares, without par value

(b) Issued

Common shares:

(In thousands)	Number of Shares		Amount
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			3,486
Share issue costs	—			(267	)
Stock options exercised	370			389
Issued in conjunction with acquisition (note 4(a))	500			350
Unconverted shares forfeited	(63	)		—
Balance, December 31, 2005	37,659			20,476
Private placement of common stock	4,500			2,493
Share issue costs	—			(214	)
Stock options exercised	280			252
Stock warrants exercised	118			157
Balance, December 31, 2006	42,557		$	23,164

Warrants:

(In thousands)	Number of Warrants		Amount
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 pursuant to private placement	2,500			762
Issued in conjunction with acquisition (note 4(a))	500			133
Issue costs	375			(63	)
Balance, December 31, 2005	11,010			3,502
Expired	(7,635	)		(2,670	)
Exercised	(118	)		(33	)
Issued pursuant to private placement	4,500			1,333
Issue costs	219			(115	)
Balance, December 31, 2006	7,976		$	2,017

F-11

(c) December 2006 private placement

The Company issued 4,500,000 Units at $0.85 per Unit for gross proceeds of $3.8 million. Each Unit consisted of one common share and one common share purchase warrant. Each warrant entitles the holder to acquire one common share at a price of $1.05 through December 4, 2008. If the volume weighted average closing price of the Company’s common shares exceeds $1.55 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 a commission of $249,000 and issued 219,375 finders warrants with an estimated fair value of $60,000 exercisable on the same terms as the purchase warrants. In addition to the finder’s fee, approximately $80,000 of legal, consulting 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 17, 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 a commission of $330,000 and issued 375,000 broker warrants with an estimated fair value of $83,000 exercisable on the same terms as the purchase warrants.

(e) January 2004 private placement

The Company issued 7,635,000 Units at $1.00 per Unit for gross proceeds of $7,635,000. Each Unit consisted of one common share and one common share purchase warrant. Each warrant entitled the holder to acquire one common share at a price of $1.50 through January 30, 2006. All of the warrants expired unexercised in January 2006.

(f) Option grants

In 2006, the Company granted 205,000, 25,000, 100,000 and 25,000 stock purchase options on April 5, April 17, May 23 and August 16, respectively. All of the options were granted pursuant to the Company’s Amended and Restated Stock Option Plan with the following terms: i) immediate vesting; ii) five year term; iii) exercisable at $1.10, $1.12, $1.17 and $1.20 per share, respectively. Based upon these terms, a Black-Scholes pricing model derives a fair value for the grants of approximately $260,000 recognized as stock-based compensation expense.

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

Option Value Inputs	2006		2005		2004
Risk free interest rate	4.7	%	5.3	%	5.3	%
Expected option life	5 Years		5 Years		5 Years
Volatility in the price of the Company’s shares	74-77	%	80	%	81	%

(g) Per share amounts

Basic per common share amounts were calculated using a weighted average number of common shares outstanding for 2006 of 38,181,808 (2005 – 33,023,412; 2004 – 30,908,065).

(h) Contributed surplus

	2006			2005
Beginning balance	$	1,508		$	1,302
Increase from stock based compensation		260			410
Transfer to share capital on option exercise		(154	)		(204	)
Warrants expired		2,670			—
Ending balance	$	4,284		$	1,508

F-12

(i) Stock option plan

The Company’s Amended and Restated Stock Option Plan had 1.98 million common shares reserved for issuance as at December 31, 2006. All options presently issued under the plan have a five-year expiry. Details of the Company’s plan as at December 31, 2006 and 2005 are presented below.

	2006				2005
(Shares in thousands)	Number of options		Weighted average exercise price		Number of options		Weighted average exercise price
Outstanding at beginning of year	2,540		$	0.76	2,543		$	0.70
Granted	355			1.13	720			0.87
Expired	(335	)		0.72	(353	)		0.83
Exercised	(280	)		0.63	(370	)		0.50
Outstanding at end of year	2,280		$	0.87	2,540		$	0.76
Exercisable at end of year	2,280		$	0.87	2,540		$	0.76

The following table summarizes information about stock options as at December 31, 2006 (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)
$	0.70	$	1.05	1,925	2.90	$	0.83	1,925	$	0.83
	1.06		1.20	355	4.33	$	1.13	355	$	1.13
				2,280	3.12	$	0.87	2,280	$	0.87

7. 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:

(In thousands)	2006			2005			2004
Statutory tax rate		34.5	%		37.62	%		38.62	%
Expected income tax reduction	$	(3,247	)	$	(1,419	)	$	(2,006	)
Increase (decrease) resulting from
Stock-based compensation		76			154			276
Change in enacted tax rates		(163	)		—			588
Expiration of tax deductions		1,045			—			—
Change in valuation allowance		1,868			1,265			1,142
Other		421			—			—
	$	—		$	—		$	—

F-13

The components of the net future income tax asset at December 31, 2006 and 2005 is as follows:

(In thousands)	2006			2005
Future income tax liabilities
Property and equipment in excess of tax values	$	(212	)	$	—
Future income tax assets
Property and equipment	$	—		$	46
Operating loss carry-forwards		9,945			7,679
Capital loss carry-forwards		845			576
Share issue costs		255			208
Investments		54			396
Valuation allowance		(10,887	)		(8,905	)
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 U.S. 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 $859,000 which expire commencing in 2007 and non-capital tax losses in the U.S. of approximately $23.5 million which expire commencing in 2008. The Company has capital tax losses in Canada of approximately $5.0 million which have no expiry date.

8. Segment information

As at December 31, 2006, 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:

2006	Identifiable assets			Net Revenues		Net Loss
United States	$	4,709		$	1,604	$	6,631
Morocco		3,414			—		859
Romania		1,894			—		605
Corporate assets and other		5,375			9		1,318
	$	15,392		$	1,613	$	9,413
2005
United States	$	11,094		$	1,400	$	2,922
Morocco		644			9		67
Corporate assets and other		7,189			—		784
	$	18,927		$	1,409	$	3,773
2004
United States	$	3,880		$	744	$	2,288
Canada		(134	)		—		2,367
Nigeria		198			4,364		538
Corporate assets and other		12,106			—		—
	$	16,048		$	5,108	$	5,193

9. Financial instruments

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

10. Related party transactions

(a) In 2005, the Company made investments (in unrelated parties) in loan syndications through Quest Capital Corp. in the amount of $1.5 million. The investments matured in March 2006 and all principal and interest on the investments was paid to the Company. As of December 31, 2006, the

F-14

Company has recorded $77,000 in interest from these investments (2005 - $395,000). The Company and Quest Capital Corp. have two directors in common.

(b) At December 31, 2006, a director of the Company was also a director of ANEC (see note 3(b)). During 2006 and 2005, the Company received or made the following payments to (from) ANEC:

(in thousands)	2006			2005			2004
Receipts from ANEC:
Proceeds from oil & gas sales	$	403		$	702		$	796
Interest on debentures		60			240			240
Payments to ANEC:
Drilling advances		—			(423	)		(1,418	)
Joint lease operations expenses		(118	)		(356	)		(207	)
	$	345		$	163		$	(589	)

(c) In December 2006, Quest Capital Corp. provided services in conjunction with the Company’s private placement. The merchant bank was paid approximately $22,000. The Company and Quest Capital Corp. have two directors in common.

(d) In September 2005, the Company completed the purchase of 2,237,136 shares of ANEC pursuant to ANEC’s private placement dated August 16, 2005. The purchase price was $268,456 or $0.12 per share; the value of this investment was reduced to $0.07 per share at year end 2005. At the time of the sale, a director of the Company was also a director of ANEC.

(e) Christopher H. Lloyd, our former 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; we participated in the syndication and the loan has been repaid.

11. 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 claims relating to operations in Nigeria over the past 10 years. The remaining escrow fund amount at December 31, 2006 is $961,000. Pursuant to an agreement reached in 2007, $406,000 of the remaining escrow amount has been allocated for final payment of liabilities with respect to years 1998 through 2004.

12. Commitments

(a) In May 2006 the Company was awarded the Tselfat exploration permit in Morocco. To retain the license past the initial three-year term, the Company is required to shoot a 3D survey and drill an exploratory well. The Company posted a $3.0 million bank guarantee in support of this work commitment. The bank guarantee is reduced annually based on work performed. In the event the Company fails to perform the work commitment, the bank guarantee (or the remaining portion thereof) will be forfeited. The Company also has a $120,000 work commitment in 2007 with respect to its Guercif—Beni Znassen reconnaissance license in Morocco, which is supported by a similar bank guarantee.

(b) On December 13, 2005, the Company amended the lease term for its office space in Dallas, Texas. The lease expires on January 31, 2011. The Company is committed to the following aggregate annual amounts:

2006	$	74
2007		80
2008		81
2009		83
2010		85
2011		7
	$	410

F-15

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 center’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, 2004, 2005 and 2006, the Company recognized a U.S. GAAP ceiling test write down of $246, $nil and $1,311 respectively (all impairment amounts are in thousands of dollars before and after tax). Depletion expense for the years ended December 31, 2004 , 2005 and 2006 for U.S. GAAP is reduced by $131, $51, and $35 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. The FASB issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R), which replaced SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123), and superseded APB Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25). SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest. We adopted SFAS No. 123R as of January 1, 2006, and there was no material impact.

(f) Additional disclosures

Additional disclosures required under U.S. GAAP:

	December 31, 2006	December 31, 2005
Components of accounts receivable
Taxes receivable	309	—
Trade	113	780
	422	780
Components of accounts payable and accrued liabilities
Trade	1,826	924
Accrued liabilities	164	—
	1,990	924

F-16

(g) Recently Issued United States Accounting Standards

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Interpretation requires that we recognize in the financial statements, the impact of a tax position, if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. The provisions of FIN 48 are effective beginning January 1, 2007 with the cumulative effect of the change in accounting principle recorded as an adjustment to the opening balance of deficit. We adopted FIN 48 as of January 1, 2007 and there was no material impact.

In February 2006, the FASB issued FAS 155, accounting for certain Hybrid Financial Instruments, an amendment of FASB statements No. 133 and 140. This statement permits fair value measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Earlier adoption is permitted as of the beginning of an entity’s fiscal year, provided that no interim period financial statements have been issued for the financial year. We adopted FAS 155 as of January 1, 2007 and there was no material impact.

In September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” (“FAS 157”), which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, and is applicable beginning in the first quarter of 2008. We are currently evaluating the impact that FAS 157 will have on our consolidated financial statements.

In February 2007, the FASB issued FAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities— Including an amendment of FASB Statement No. 115”, (“FAS 159”) which permits entities to choose to measure many financial instruments and certain other items at fair value at specified election dates. A business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This statement is expected to expand the use of fair value measurement. FAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, and is applicable beginning in the first quarter of 2008. We are currently evaluating the impact that FAS 159 will have on our consolidated financial statements.

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 than share and per share amounts)	2006			2005			2004
Net loss under Canadian GAAP	$	9,413		$	3,773		$	5,193
Additional write-down of property and equipment(c)		1,311			—			246
Depletion and depreciation(c)		(35	)		(51	)		(131	)
Marketable securities(b)		19			—			(19	)
Net loss under U.S. GAAP		10,708			3,722			5,289
Marketable securities(b)		(128	)		147			(278	)
Comprehensive net loss under U.S. GAAP		10,836			3,575			5,567
Basic and diluted net loss per share under U.S. GAAP		0.28			0.11			0.17
Shares used in the computation of basic and diluted net loss per share		38,181,808			33,023,412			30,908,065

F-17

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

	December 31, 2006						December 31, 2005						December 31, 2004
(Thousands of U.S. dollars)	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Current assets(b)	$	5,194		$	5,194		$	9,947		$	10,094		$	11,978		$	11,978
Restricted cash		4,339			4,339			2,110			2,110			2,466			2,466
Property and equipment(c)		5,859			4,377			5,813			5,607			704			447
Long-term investments		—			—			1,057			1,057			900			900
		15,392			13,910			18,927			18,868			16,048			15,791
Current liabilities		2,951			2,951			2,435			2,435			1,180			1,180
Asset retirement obligations		1,939			1,939			556			556			155			155
Share capital(d)		23,164			41,567			20,476			38,879			16,518			34,921
Warrants		2,017			2,017			3,502			3,502			2,670			2,670
Contributed surplus		4,284			4,284			1,508			1,508			1,302			1,302
Deficit(b)(c)(d)		(18,963	)		(38,848	)		(9,550	)		(28,140	)		(5,777	)		(24,418	)
Accumulated other comprehensive income (loss)(b)		—			—			—			128			—			(19	)
		15,392			13,910			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, 2006			December 31, 2005			December 31, 2004
(Thousands of U.S. dollars)	Canadian GAAP	U.S. GAAP		Canadian GAAP	U.S. GAAP		Canadian GAAP	U.S. GAAP
Deficit, beginning of year	9,550	28,140		5,777	24,418		584	19,129
Net loss	9,413	10,708		3,773	3,722		5,193	5,289
Deficit, end of year	18,963	38,848		9,550	28,140		5,777	24,418
Accumulated other comprehensive income (loss), beginning of year	—	128		—	(19	)	—	259
Marketable securities	—	(128	)	—	147		—	(278	)
Accumulated other comprehensive income (loss), end of year	—	—		—	128		—	(19	)

F-18

Interim Consolidated Financial Statements of

TRANSATLANTIC PETROLEUM CORP.

Three and Six Months Ended June 30, 2007 and 2006

UNAUDITED

Interim Consolidated Balance Sheets

(Unaudited)

(Thousands of U.S. Dollars)

	June 30, 2007			Dec. 31, 2006
Assets
Current assets
Cash and cash equivalents	$	624		$	4,688
Accounts receivable		478			422
Prepaid and other current assets		240			84
		1,342			5,194
Restricted cash (notes 3, 11 and 12)		3,675			4,339
Property and equipment (note 4)		9,729			5,859
	$	14,746		$	15,392
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	1,317		$	1,990
Loan payable (note 6)		3,000			—
Settlement provision (note 11)		240			961
		4,557			2,951
Asset retirement obligations (note 5)		2,037			1,939
Shareholders’ equity
Share capital (note 7)		23,715			23,164
Warrants (note 7)		1,877			2,017
Contributed surplus (note 7)		4,618			4,284
Deficit		(22,058	)		(18,963	)
		8,152			10,502
Going concern (note 1)
Subsequent events (notes 1, 10 and 13)
Commitments (note 12)
	$	14,746		$	15,392

See accompanying notes to consolidated financial statements.

Approved by the Board of Directors:

“Brian Bayley”	Director
“Michael Winn”	Director

F-19

TRANSATLANTIC PETROLEUM CORP.

Interim Consolidated Statements of Operations, Comprehensive Loss and Deficit

(Unaudited)

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

	Six Months						Three Months
	Ended June 30,
	2007			2006			2007			2006
Revenues
Oil and gas sales	$	430		$	1,375		$	208		$	611
Royalties		(88	)		(374	)		(42	)		(166	)
Oil and gas sales, net of royalties		342			1,001			166			445
Expenses
Lease operating expenses and other production costs		482			1,013			201			480
Depreciation, depletion and accretion		351			549			204			284
General and administrative		1,374			1,474			475			872
International oil and gas activities (note 4)		1,342			910			933			398
Settlement provision (note 11)		(313	)		—			(313	)		—
Foreign exchange (gain) loss		(1	)		(102	)		32			(99	)
		3,235			3,844			1,532			1,935
Interest and financing expense		399			—			399			—
Interest income		(197	)		(284	)		(129	)		(59	)
Net loss and comprehensive loss for the period		3,095			2,559			1,636			1,431
Deficit, beginning of period		18,963			9,550			20,422			10,678
Deficit, end of period	$	22,058		$	12,109		$	22,058		$	12,109
Net loss per share - basic and diluted (note 7)	$	0.07		$	0.07		$	0.04		$	0.04

See accompanying notes to consolidated financial statements.

F-20

TRANSATLANTIC PETROLEUM CORP.

Interim Consolidated Statements of Cash Flows

(Unaudited)

(Thousands of U.S. Dollars)

	Six Months						Three Months
	Ended June 30,
	2007			2006			2007			2006
Cash provided by (used in)
Operating activities
Net loss for the period	$	(3,095	)	$	(2,559	)	$	(1,636	)	$	(1,431	)
Items not involving cash
Depreciation, depletion and accretion		351			549			204			284
Non-cash financing expense		286			—			286			—
Stock-based compensation		295			225			49			225
		(2,163	)		(1,785	)		(1,097	)		(922	)
Changes in non-cash working capital		(2,095	)		(92	)		(1,130	)		(853	)
		(4,258	)		(1,877	)		(2,227	)		(1,775	)
Investing activities
Property and equipment		(4,123	)		(1,870	)		(554	)		(1,489	)
Changes in accounts payable relating to property and equipment		489			65			(1,939	)		65
Redemption of short-term investments		—			1,500			—			—
Restricted cash		664			(2,496	)		700			(1,946	)
		(2,970	)		(2,801	)		(1,793	)		(3,370	)
Financing activities
Exercise of warrants and options		164			159			—			145
Loan proceeds (note 6)		3,000			—			3,000			—
		3,164			159			3,000			145
Change in cash and cash equivalents		(4,064	)		(4,519	)		(1,020	)		(5,000	)
Cash and cash equivalents, beginning of period		4,688			7,567			1,644			8,048
Cash and cash equivalents, end of period	$	624		$	3,048		$	624		$	3,048
Supplemental cash flow information
Interest received	$	197		$	284		$	129		$	59
Interest paid		113			—			77			—

See accompanying notes to consolidated financial statements.

F-21

TRANSATLANTIC PETROLEUM CORP.

Notes to Consolidated Financial Statements - Unaudited

Three and six months ended June 30, 2007 and 2006

(Tabular amounts in 000’s of U.S. Dollars unless otherwise noted)

1. Going Concern

These financial statements have been prepared on the basis of accounting principles applicable to a going concern, which assumes that TransAtlantic Petroleum Corp. (the “Company”) will realize its assets and discharge its liabilities in the normal course of operations.

At June 30, 2007, the Company had cash and cash equivalents of $624,000, $3.0 million in current debt, no long term debt and a working capital deficit of $3.2 million. The Company continued to incur losses during the six months ended June 30, 2007 of $3.1 million. At December 31, 2006, the Company had cash and cash equivalents of $4.7 million, no current or long term debt and a working capital balance of $2.2 million. During the year ended December 31, 2006, the Company incurred a net loss of $9.4 million.

The Company estimates that it does not have sufficient funds to continue in operation past March 2008. Subsequent to December 31, 2006, the Company has drilled the SGU #96 well for costs totaling approximately $4.1 million. Although the Company completed this well in June 2007, the Company will require significant immediate funding to continue its exploration, development and operating activities. In April 2007, the Company entered into a U.S. $3.0 million short-term standby bridge loan from Quest Capital Corp. (“Quest”) (see note 10). The Company mortgaged certain of its assets, including the South Gillock property, and pledged 100% of the common stock of its wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. At closing, the Company paid Quest a loan fee totaling 132,353 shares of its common stock at a deemed price of $0.68 per share. In addition, the Company paid Quest an amount equal to 5% of the principal drawn down, payable in our common shares using a formula based on a discount to the five-day volume weighted average trading price. The Company drew down $1.0 million on the loan on April 16 and issued 64,766 shares to Quest at a deemed issue price of $0.77 per share. The Company drew down $1.5 million on the loan on May 9 and issued 102,174 shares to Quest at a deemed issue price of $0.73 per share. The Company drew down $500,000 on the loan on June 6 and issued 65,074 shares to Quest at a deemed issue price of $0.38 per share. On August 10 the Company and Quest increased the loan facility to $4.0 million, and the Company drew down the additional $1.0 million and issued 139,456 shares to Quest at a deemed issue price of $0.58 per share. On November 13, 2007, the Company paid down $2.0 million in principal on the loan in connection with the sale of the Company’s South Gillock property and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008. The outstanding principal balance bears interest at an effective annual rate of 16.27%.

Management and the Board of Directors continue to explore funding alternatives. Management considers the going concern basis to be appropriate for these financial statements. If the going concern basis were not appropriate for these financial statements, then adjustments would be necessary to the carrying value of assets and liabilities, reported expenses and the balance sheet classifications used.

F-22

2. Basis of presentation

The accompanying interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include the accounts of the Company and its wholly-owned subsidiaries.

The interim consolidated financial statements of the Company have been prepared by managements following the same accounting policies and methods of computation as the audited consolidated financial statements for the fiscal year ended December 31, 2006, except as indicated below. Readers are referred to the significant accounting policies as outlined in the notes to the consolidated financial statements for the year ended December 31, 2006. These interim consolidated financial statements contain disclosures which are incremental and should be read in conjunction with the annual consolidated financial statements for the year ended December 31, 2006. These unaudited interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the results of the interim periods presented.

(a) Changes in Accounting Policy

On January 1, 2007, the Company adopted CICA Handbook Section 1530, Comprehensive Income. Comprehensive Income is the change in the Company’s net assets that results from transactions, events and circumstances from sources other than the company’s shareholders and includes items that would not normally be included in net earnings such as unrealized gains or losses on available-for-sale investments. There were no such components to be recognized in the comprehensive income for the six month period ended June 30, 2007.

On January 1, 2007, the Company adopted CICA Handbook Section 3855, Financial Instruments – Recognition and Measurement. In accordance with this new standard the Company now classifies all financial instruments as either held-to-maturity, available-for-sale, held for trading, loans and receivables, or other financial liabilities. This new standard did not affect the Company’s interim consolidated financial statements.

On January 1, 2007, the Company adopted CICA Handbook Section 3865, Hedges. This new standard specifies the criteria under which hedge accounting can be applied and how hedge accounting can be executed. The Company does not have any hedging relationships. This new standard did not affect the Company’s interim consolidated financial statements.

These standards have been adopted retroactively without restatement. The preparation of financial statements in conformity with Canadian 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.

Two new Canadian accounting standards have been issued which will require additional disclosure in the Company’s financial statements commencing January 1, 2008 about the Company’s financial instruments as well as its capital and how it is managed.

3. 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 June 30, 2007, restricted cash includes: $240,000 in respect of the settlement of Nigerian liabilities (see note 11), $3.4 million in certificates of deposit supporting guarantees of the Morocco work programs (see note 12) and $27,000 relates to the certificate of deposit that is a collateral for the Amegy letter of credit in favor of the Oklahoma Tax Commission.

F-23

4. Property and equipment

2007	Cost		Accumulated depreciation and depletion		Net book value
Crude oil and natural gas properties
United States	$	15,314	$	7,157	$	8,157
Romania		1,572		—		1,572
Furniture, fixtures and other assets		238		238		—
Balance, June 30, 2007	$	17,124	$	7,395	$	9,729
2006
Crude oil and natural gas properties
United States	$	11,164	$	6,877	$	4,287
Romania		1,572		—		1,572
Furniture, fixtures and other assets		238		238		—
Balance, December 31, 2006	$	12,974	$	7,115	$	5,859

(a) United States:

During the first and second quarters 2007, the Company drilled the SGU #96 well on its South Gillock property and capitalized approximately $3.8 million additional costs (2006 - $300,000) associated with this project. The Company’s financial position at the end of the second quarter 2007 has been impacted by expenditures on the SGU #96 well; the Company has incurred costs to date of approximately $4.1 million. The Company has completed the well and it is currently producing. At June 30, 2007, $1.8 million (2006 - $1.7 million) of asset retirement costs are included in property and equipment. No overhead costs were capitalized and future development costs of $25,000 (2006 - $25,000), are included in the computations of depreciation and depletion for the six months ended June 30, 2007. Unproved property costs of $762,000 (2006 - $894,000) were excluded from the depletion and depreciation calculation, as were $828,000 in development costs (2006 - $935,000) related to a non-operated well on the Oswego property. The Oswego well is currently being tested.

(b) Morocco:

As part of the Company’s June 2005 award of a reconnaissance license in Morocco, the Company committed to a work program involving the reprocessing of seismic and other technical work over the property. The 2007 work commitment has been completed and the Company’s $120,000 portion of that commitment has been fulfilled. The existing bank guarantee is pending release and the Company is negotiating to convert portions of the license into an exploration permit.

In May 2006, the Company was awarded an exploration permit in Morocco. As its work commitment during the initial three-year term, the Company is required to shoot a 3D survey and drill an exploratory well.

The Company posted $3.4 million in certificates of deposit pursuant to a guarantee of the work programs in Morocco (see note 12) and this amount (which includes accrued interest on the deposits) is included in restricted cash at June 30, 2007.

(c) Romania:

The Company capitalized $1.6 million of expenditures related to seismic surveys completed at the end of 2006 in Romania. No further seismic costs have been incurred as of June 30, 2007.

F-24

(d) Other countries:

During the six months ended June 30, 2007, the Company continued to evaluate and expand its initiatives in Morocco, Romania, Turkey and the U.K. North Sea. Approximately $1.3 million of costs were incurred and expensed towards the pre-acquisition, reconnaissance, evaluation and development of the Company’s international oil and gas activities, including those conducted in Morocco and Romania, including technical, professional and administrative costs during the six months ended June 30, 2007(2006 - $910,000) .

5. 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 June 30, 2007 the net present value of the Company’s total ARO is estimated to be $2.0 million (December 31, 2006 - $1.9 million), with the undiscounted value being $2.4 million (December 31, 2006 - $2.4 million). Payments to settle the obligations are expected to occur continuously over the next four years, with the majority of obligations expected to occur in 2010. An inflation rate of 2% was assumed and a discount rate of 7% was used to calculate the present value of the ARO.

	Six months ended June 30, 2007		Six months ended June 30, 2006
Beginning balance	$	1,939	$	$556
Liabilities incurred		26		—
Accretion expense		72		28
Ending balance	$	2,037	$	584

6. Loan payable

On April 16, 2007, the Company entered into a $3.0 million short-term standby bridge loan agreement with Quest. The Company mortgaged certain of its assets, including the South Gillock property, and pledged 100% of the common stock of its subsidiary TransAtlantic Petroleum (USA) Corp. as security. At closing, the Company paid Quest a loan fee totaling 132,353 shares of the Company’s common shares at a deemed price of $0.68 per share. In addition, the Company is required to pay Quest an amount equal to 5% of the principal drawn down, payable in the Company’s common shares using a formula based on a discount to the five-day volume weighted average trading price. The Company drew down $1.0 million on the loan on April 16 and issued 64,766 shares to Quest at a deemed issue price of $0.77 per share. The Company drew down $1.5 million on the loan on May 9 and issued 102,174 shares to Quest at a deemed issue price of $0.73 per share. The Company drew down $500,000 on the loan on June 6 and issued 65,074 shares to Quest at a deemed issue price of $0.38 per share. The financing fees paid to Quest during the period have been charged to interest expense. Interest is paid monthly in cash. On August 10, 2007, the Company and Quest amended the agreement to increase the loan facility to $4.0 million under the same terms as the original agreement. The Company drew down the additional $1.0 million on August 10 and issued 139,456 shares to Quest at a deemed issue price of $0.58 per share. The loan bears interest at an effective annual rate of 12.68% and must be repaid by November 30, 2007.

F-25

7. Share capital

(a) Authorized

Unlimited number of common shares, without par value

(b) Issued

Common shares:

(In thousands)	Number of Shares	Amount
Balance, December 31, 2006	42,557	$	23,164
Stock issued in connection with loan	364		286
Stock options exercised	185		232
Stock warrants exercised	25		33
Balance, June 30, 2007	43,131	$	23,715

Warrants:

(In thousands)	Number of Shares		Amount
Balance, December 31, 2006	7,976			2,017
Exercised	(25	)		(7	)
Expired	(500	)		(133	)
Balance, June 30, 2007	7,451		$	1,877

(c) Option plan

The Company has an Amended and Restated Stock Option Plan (the “Plan”) under which 827,000 common shares were reserved for issuance and 3,410,000 million share purchase options at a weighted average strike price of $0.93 per share were issued and outstanding at June 30, 2007. All options presently issued under the Plan have a five-year term from date of grant.

The Company granted 1,355,000 stock purchase options on January 10, 2007. All of the options were granted pursuant to the Plan with a five-year term exercisable at $1.00 per share. The options were issued on two different vesting schedules. As to 405,000 of the options issued, 50% vested immediately and 50% will vest in one year. As to 950,000 of the options issued, 1/3 vested immediately, 1/3 will vest in one year and 1/3 will vest in two years. Based upon these terms, a Black-Scholes pricing model derives a fair value for the grants of approximately $295,000 recognized as stock-based compensation expense for the six months ended June 30, 2007 (2006 - $225,000).

The estimated fair value of share options issued during the first quarter 2007 was determined using the Black-Scholes pricing model with the following assumptions:

Option Value Inputs	2007
Risk free interest rate	4.2	%
Dividend yield	0	%
Expected option life	5 Years
Volatility in the price of the Company’s shares	71	%

F-26

(d) Per share amounts

Basic per common share amounts were calculated using a weighted average number of common shares outstanding for the six and three months ended June 30, 2007 of 42,830,381 and 43,008,951 (2006 – 38,181,808). 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.

(e) Contributed surplus

Balance, December 31, 2006	$	4,284
Increase from stock based compensation		295
Transfer to share capital on option exercise		(94	)
Warrants expired		133
Balance, June 30, 2007	$	4,618

8. Segment information

As of June 30, 2007, the Company and its subsidiaries operate in one industry segment, composed of three reportable geographic segments, involving 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:

	Identifiable assets (liabilities)		Net Revenues				Net loss
June 30, 2007			Six months		Three Months		Six months		Three months
United States	$	8,765	$	342	$	166	$	1,316	$	617
Morocco		3,527		—		—		277		200
Romania		1,932		—		—		663		613
Corporate assets and other		522		—		—		839		206
	$	14,746	$	342	$	166	$	3,095	$	1,636

9. Financial instruments

The fair value of the Company’s financial instruments at June 30, 2007 comprised of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, loan payable and settlement provision approximate their fair values.

10. Related party transactions

In April 2007, the Company and Quest Capital Corp. (“Quest”) entered into a loan agreement which was amended in August 2007 and November 2007 (note 6). Quest is a shareholder of the Company, and the Company and Quest have two directors in common. Transactions with Quest were conducted at their exchange value.

11. 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 account to address claims relating to prior operations in Nigeria. Pursuant to an agreement reached in 2007, a net amount of $306,000 of the escrow amount was allocated and recently paid with respect to years

F-27

1998 through 2004. In April 2007, $415,000 out of the escrow account was released to the Company. Accordingly in the second quarter 2007, the Company recorded $102,000 of interest income (on amounts held in escrow since 2005) and a reduction in the settlement provision of $313,000. The remaining potential liability to the Company includes taxes owed for the period January through June 2005, and the Company expects the remaining escrow amount of $240,000 to be sufficient to cover any potential liabilities.

12. Commitments

(a) In May 2006, the Company was awarded the Tselfat exploration permit in Morocco. To retain the license past the initial three-year term, the Company is required to shoot a 3D survey and drill an exploratory well. The Company posted a $3.0 million bank guarantee in support of this work commitment. The bank guarantee is reduced annually in the third quarter based on work performed. In the event the Company fails to perform the work commitment, the bank guarantee (or the remaining portion thereof) will be forfeited. The Company also had a $120,000 work commitment in 2007 (which has now been completed) with respect to its Guercif–Beni Znassen reconnaissance license in Morocco, which is supported by a similar bank guarantee.

(b) On December 13, 2005, the Company amended the lease term for its office space in Dallas, Texas. The lease expires on January 31, 2011. The Company is committed to the following aggregate annual amounts:

2007 July through December	$	40
2008		81
2009		83
2010		85
2011		7
	$	296

13. Subsequent Events

On August 10, 2007, the Company and Quest amended their standby bridge loan agreement to increase the loan facility from $3.0 million to $4.0 million. The Company drew down the additional $1.0 million on August 10 and issued 139,456 shares to Quest at a deemed issue price of $0.58 per share.

On August 27, 2007, the Company announced that it has reached an agreement to farmout 50% of its interest in the Tselfat exploration permit to Sphere Petroleum QSC. In exchange for an option to acquire 50% of the Company’s interest in the Tselfat permit, Sphere will fund the costs to acquire a 110 square kilometer 3D seismic survey to be shot over the Haricha field and northern portion of the Bou Draa field in early 2008 and will also fund the cost of additional geological studies. It is estimated the 3D survey and the studies will cost approximately $4.5 million over the next year. Upon its exercise of the option, Sphere will (i) fund the drilling and testing of an exploratory well; and (ii) replace the Company’s bank guarantee deposited with the Moroccan government. The exploratory well will be drilled to a depth of at least 2,000 meters (6,500 feet) to test a previously undrilled subthrust prospect. The Company will remain as operator of the permit through this exploration phase which extends to May 2009.

On September 27, 2007, the Company announced that it received final government approval of the three production licenses in Romania which were awarded to the Company in 2006. In October 2007, the Company announced the farmout of one of its licenses in Turkey, Block 4175. In October 2007, the Company sold its Jarvis Dome property for $250,000.

On November 7, 2007, the Company announced that it converted a portion of its Guercif - Beni Znassen Reconnaissance License into two exploration permits covering a total of 3,893 square kilometers (962,000 acres) in the Guercif area in northeastern Morocco. Pursuant to a participation agreement between the Company (30%), Stratic Energy Corporation (“Stratic”) (20%) and Sphere Petroleum QSC (“Sphere”) (50%), Sphere will bear the entire cost of the initial three-year work program to earn its 50% interest in the two Guercif exploration permits. The Company’s interests and the interests of Sphere and Stratic are subject to the interest in the Guercif exploration permits held by the national oil company of Morocco, Office National des Hydrocarbures et des Mines, who is carried during the exploration phase but pays its 25% share of costs in the development phase. The Company will continue as operator of the Guercif exploration permits during the initial three-year period. The Guercif exploration permits are for an eight-year term divided into three periods. The initial three-year work program is estimated to cost more than U.S. $3 million and will include the re-entry of an existing well and the acquisition of 300 kilometers of 2D seismic. In addition, Sphere has posted the required bank guarantee for the initial work program with the Moroccan government and will reimburse the Company and Stratic for their back costs.

On November 12, 2007, the Company announced that it sold the South Gillock and State Kohfeldt Units, as well as the shallow rights over the South Gillock Unit, for $4.0 million, and the buyer has assumed the plugging and abandonment liability associated with the units.

In connection with the sale, the Company paid down $2.0 million in principal on its short-term standby bridge loan and extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008.

14. 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 center’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 period-end. There was no material difference arising out of the differences in prices. At June 30, 2007 and 2006, the Company recognized a U.S. GAAP ceiling test write down of $2,880 and $nil respectively (all impairment amounts are in thousands of dollars before and after tax). Depletion expense for the six months ended June 30, 2007 and 2006 for U.S. GAAP is reduced by $111 and $16 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. The FASB issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R), which replaced SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123), and superseded APB Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25). SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest. We adopted SFAS No. 123R as of January 1, 2006, and there was no material impact.

(f) Income Taxes

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Interpretation requires that we recognize in the financial statements, the impact of a tax position, if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. The provisions of FIN 48 are effective beginning January 1, 2007 with the cumulative effect of the change in accounting principle recorded as an adjustment to the opening balance of deficit. We adopted FIN 48 as of January 1, 2007 and there was no material impact.

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

	Six months ended June 30,
(Thousands of U.S. dollars other than share and per share amounts)	2007			2006
Net loss under Canadian GAAP	$	3,095		$	2,559
Additional write-down of property and equipment(c)		2,880			—
Depletion and depreciation(c)		(111	)		(16	)
Net loss under U.S. GAAP		5,864			2,543
Marketable securities(b)		—			(110	)
Comprehensive net loss under U.S. GAAP		5,864			2,433
Basic and diluted net loss per share under U.S. GAAP		0.14			0.07
Shares used in the computation of basic and diluted net loss per share		42,830,381			38,181,808

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

	June 30, 2007						December 31, 2006
(Thousands of U.S. dollars)	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Current assets(b)	$	1,342		$	1,342		$	5,194		$	5,194
Restricted cash		3,675			3,675			4,339			4,339
Property and equipment(c)		9,729			5,478			5,859			4,377
		14,746			10,495			15,392			13,910
Current liabilities		4,557			4,557			2,951			2,951
Asset retirement obligations		2,037			2,037			1,939			1,939
Share capital(d)		23,715			42,118			23,164			41,567
Warrants		1,877			1,877			2,017			2,017
Contributed surplus		4,618			4,618			4,284			4,284
Deficit(b)(c)(d)		(22,058	)		(44,712	)		(18,963	)		(38,848	)
		14,746			10,495			15,392			13,910

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:

	June 30, 2007		December 31, 2006
(Thousands of U.S. dollars)	Canadian GAAP	U.S. GAAP	Canadian GAAP	U.S. GAAP
Deficit, beginning of year	18,963	38,848	9,550	28,140
Net loss	3,095	5,864	9,413	10,708
Deficit, end of year	22,058	44,712	18,963	38,848
Accumulated other comprehensive income (loss), beginning of year	—	—	—	128
Marketable securities	—	—	—	(128	)
Accumulated other comprehensive income (loss), end of year	—	—	—	—

F-28

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/ Hilda Kouvelis
	Hilda Kouvelis Chief Financial Officer

Date: November 13, 2007

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 2, 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*	Management Agreement dated effective April 1, 2006 by and between TransAtlantic Worldwide, Ltd. and Charles Management, Inc.
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
4.6*	Warrant Indenture dated December 1, 2006 by and between TransAtlantic Petroleum Corp. and Computershare Trust Company of Canada
4.7*	Credit Agreement dated April 16, 2007 by and between TransAtlantic Petroleum Corp. and Quest Capital Corp.
4.8*	First Amending Agreement dated August 10, 2007 by and between TransAtlantic Petroleum Corp. and Quest Capital Corp.
4.9	Second Amending Agreement dated November 9, 2007 by and between TransAtlantic Petroleum Corp. and Quest Capital Corp.
15.1	Consent of KPMG LLP
15.2	Consent of Netherland, Sewell & Associates, Inc.

* Previously filed

EX-4.9

Exhibit 4.9

SECOND AMENDING AGREEMENT

THIS AGREEMENT is made and dated for reference November 9, 2007

BETWEEN:

TRANSATLANTIC PETROLEUM CORP.,

as Borrower

AND:

QUEST CAPITAL CORP.,

as Lender

WHEREAS:

A. The parties hereto entered into a credit agreement made as of April 16, 2007 (the “Original Credit Agreement”) wherein the Lender agreed to establish the Facility in favour of the Borrower;

B. The parties amended the Original Credit Agreement pursuant to a First Amending Agreement dated August 10, 2007 (the Original Credit Agreement as so amended, the “Credit Agreement”);

C. The parties hereto have agreed to further amend the Credit Agreement in order to, among other things:

a. extend the date for repayment of the Outstanding Balance in full;

b. provide for partial repayment of the Outstanding Balance in the amount of U.S. $2,000,000 (the “Partial Repayment”); and

c. permit the guarantor under the Credit Agreement, TransAtlantic Petroleum (USA) Corp. (the “Guarantor”), to dispose of certain oil and gas properties of located in the state of Texas pursuant to that certain purchase and sale agreement dated November 1^st, 2007 between Denbury Onshore, LLC and the Guarantor on the condition that the Partial Repayment is made to the Lender from the proceeds of the disposition. (the “Disposition”).

NOW THEREFORE THIS AGREEMENT WITNESSES THAT in consideration of the premises and of other good and valuable consideration (the receipt whereof is hereby acknowledged), the parties hereto agree as follows:

1. Unless otherwise defined herein or unless the context otherwise requires, defined words and terms used in the Credit Agreement shall have the same meanings when used herein.

2. The Credit Agreement shall be and is hereby modified by replacing “November 30, 2007” in paragraph 4(a)(i) with “March 31, 2008”.

3. As consideration for the provision by the Lender of the extension contemplated herein, the Borrower shall make a non-refundable payment to the Lender of U.S $40,000.00 (the “Extension Fee”).

4. Effective as at the date hereof, the Borrower shall repay the Partial Repayment and such Partial Repayment will be applied against the Outstanding Balance, thereby permanently reducing the Outstanding Balance commensurate with such payment.

5. The Lender gives its consent to the Disposition subject to the terms and conditions contained herein.

6. Upon receipt by the Lender of (i) the irrevocable payment of the Extension Fee, (ii) the irrevocable payment of the Partial Repayment, (iii) a duly executed replacement promissory note in the amount of U.S. $2,000,000 (in exchange for the return of all prior existing promissory notes), and (iv) a duly executed version of this agreement and all documentation ancillary hereto, the Lender will release and discharge that certain Deed of Trust, Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement dated April 16, 2007 from the Guarantor to A. Frank Klam, Trustee and Quest Capital Corp.

7. Notwithstanding the date of execution hereof, this agreement shall not become effective, and the Credit Agreement and Security shall govern the relationship between the parties in respect of the Facility until such time that the Lender is satisfied that, inter alia, (i) the representations and warranties of the Borrower contained in the Credit Agreement are true and correct in all material respects, (ii) the Borrower has complied with all covenants required to be complied with by it under the Credit Agreement, (iii) the Lender has received irrevocable payment in full of the Extension Fee, and (iv) the Lender has received irrevocable payment in full of the Partial Repayment.

8. The Credit Agreement, together with all terms, covenants and conditions thereof as hereby supplemented and amended, will be and continue to be in full force and effect but these presents are executed under the express reserve of the liens and encumbrances created by, and of all other rights subsisting in favour of the Lender under or by virtue of, the Security and without novation of any kind or derogation from the rank and priority thereof, except as specifically contemplated herein.

9. Except as specifically contemplated herein, this agreement will not create any merger or novation or alter or prejudice any rights which the Lender may have under the Credit Agreement or any of the Security, and will not create any merger or novation or alter or prejudice the rights of the Lender as regards any surety or subsequent encumbrancer or any person not a party hereto liable to pay any amount of indebtedness or liability of the Borrower to the Lender or having an interest in the property, assets or undertaking of the Borrower or of any other person that is subject to the Security, all of which rights are hereby expressly reserved.

10. This agreement and everything herein contained will ensure to the benefit of and be binding on the Borrower and the Lender and their respective successors and assigns.

- 2 -

11. This agreement may be executed in any number of counterparts, each of which shall be deemed to be an original and all of which taken together shall be deemed to constitute one and the same instrument, and it shall not be necessary in making proof of this agreement to produce or account for more than one such counterpart. Delivery of an executed signature page of this agreement by facsimile transmission or by e-mail in pdf format shall be effective as delivery of a manually executed counterpart hereof.

12. Subject to satisfaction or waiver of the conditions precedent set forth in paragraph 7 hereof, the amendments to the Credit Agreement set forth herein shall be and be deemed to be effective as of and from November 9, 2007.

- 3 -

IN WITNESS WHEREOF the parties hereto have executed this agreement as of the date first above written.

The Borrower:		The Lender:
TRANSATLANTIC PETROLEUM CORP.		QUEST CAPITAL CORP.
Per:	/s/ Jeffrey S. Mecom	Per:	/s/ Ken Gordon
	Authorized Signatory		Authorized Signatory
		Per:	/s/ Murray Sinclair
			Authorized Signatory

TransAtlantic Petroleum (USA) Corp. hereby consents and agrees to the terms of this second amending agreement, acknowledges and confirms each representative and warranty applicable to it, acknowledges that its guarantee and all other Security granted by it to the Lender in support of its obligations thereunder and hereunder remain in full force and effect, except as expressly provided for herein, and undertakes and agrees to take all such actions as may be required of it to give effect to and cause the performance of the terms and conditions of this first amending agreement and the Security.

TRANSATLANTIC PETROLEUM (USA) CORP.
Per:	/s/ Jeffrey S. Mecom
	Authorized Signatory

- 4 -

EX-15.1

Exhibit 15.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of TransAtlantic Petroleum Corp.

We consent to the inclusion in this Form 20-F/A Amendment No. 1 of:

- our auditors’ report dated April 2, 2007, except for note 13 which is as of July 20, 2007, and note 1, which is as of November 13, 2007, on the consolidated balance sheets of TransAtlantic Petroleum Corp. (“the Company”) as at December 31, 2006 and 2005 and the consolidated statements of loss and deficit and cash flows for each of the years in the three-year period ended December 31, 2006;

- our Comments by Auditors for US Readers on Canada-US Reporting Differences, dated April 2, 2007, except for note 13 which is as of July 20, 2007, and note 1, which is as of November 13, 2007;

- and reference to our firm under the heading “Statement of Experts” in the Form 20-F/A Amendment No. 1;

each of which is contained in this Form 20-F/A Amendment No. 1 of the Company for the fiscal year ended December 31, 2006.

“KPMG LLP”

Calgary, Canada

November 13, 2007

EX-15.2

Exhibit 15.2

	CHAIRMAN EMERITUS CLARENCE M. NETHERLAND CHAIRMAN & CEO	EXECUTIVE COMMITTEE G LANCE BINDER Ÿ DALLAS DANNY D. SIMMONS Ÿ HOUSTON
WORLDWIDE PETROLEUM CONSULTANTS ENGINEERING Ÿ GEOLOGY Ÿ GEOPHYSICS Ÿ PETROPHYSICS	FREDERIC D. SEWAL PRESIDENT & COO C.H. (SCOTT) REES III	P. SCOTT FROST Ÿ DALLAS DAN PAUL SMITH Ÿ DALLAS JOSEPH J. SPELLMAN Ÿ DALLAS THOMAS J. TELLA II Ÿ DALLAS

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the reference to our firm on this Form 20-F Registration Statement of TransAtlantic Petroleum (USA) Corp., and to the incorporation by reference of information relating to our proved reserves as of December 31, 2004, December 31, 2005, and December 31, 2006, in certain oil and gas properties located in Bayou Couba Field, St. Charles Parish, Louisiana, and East and South Gillock Fields, Galveston County, Texas.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Danny D. Simmons, P.E.
	Danny D. Simmons, P.E. Executive Vice President

Houston, Texas

November 13, 2007

4500 THANKSGIVING TOWER Ÿ 1601 ELM STREET Ÿ DALLAS, TEXAS 75201-4754 Ÿ PH.: 214-969-5401 Ÿ FAX: 214-969-5411	nsai@nsai-petro.com
1221 LAMAR STREET, SUITE 1200 Ÿ HOUSTON, TEXAS 77010-3072 Ÿ PH: 713-654-4950 Ÿ FAX: 713-654-4951	netherlandsewell.com