Edgar Filing: TRANSATLANTIC PETROLEUM CORP.

Form 20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

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

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

For the fiscal year ended December 31, 2007

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

For the transition period from to

Commission file number: 000-31643

¨	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

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)

Jeffrey S. Mecom

Telephone: (214)-220-4323

Email: jeff@tapcor.com

5910 N. Central Expressway, Suite 1755, Dallas, Texas 75206

(Name, Telephone, E-mail and/or Facsimile Number and Address of Company Contact Person)

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 Shares 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 each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report – 43,270,762 common shares as of December 31, 2007.

Indicate by check mark if 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 x 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporter company¨

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP

International Financing Reporting Standards as issued by the International Accounting Standards Board

Other

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. Item 17 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 x 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	8
Item 4A.	Unresolved Staff Comments	23
Item 5.	Operating and Financial Review and Prospects	23
Item 6.	Directors, Senior Management and Employees	30
Item 7.	Major Shareholders and Related Party Transactions	37
Item 8.	Financial Information	38
Item 9.	The Offer and Listing	39
Item 10.	Additional Information	40
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 12.	Description of Securities Other than Equity Securities	48

	Part II.

Item 13.	Defaults, Dividend Arrearages and Delinquencies	49
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	49
Item 15.	Controls and Procedures	49
Item 16.	[Reserved]	49
Item 16A.	Audit Committee Financial Expert	49
Item 16B.	Code of Ethics	49
Item 16C.	Principal Accountant Fees and Services	49
Item 16D.	Exemptions from the Listing Standards for Audit Committees	50
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	50

	Part III.

Item 17.	Financial Statements	50
Item 18.	Financial Statements	50
Item 19.	Exhibits	50

PART I.

Item 1.

Identity of Directors, Senior Management and Advisers

Not Applicable.

Item 2.

Offer Statistics and Expected Timetable

Not applicable.

Item 3.

Key Information

A.	Selected Financial Data

The selected consolidated financial data presented in the table below for the five fiscal years ended December 31, 2007 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, 2007, 2006 and 2005 was derived from our financial statements, which have been audited by KPMG LLP, Chartered Accountants, as indicated in their audit report which is included elsewhere in this annual report.

Preparing selected financial data for the year ended December 31, 2003 under U.S. generally accepted accounting principles (“GAAP”) 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 year ended December 31, 2003 is not included in this annual report.

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)


	Year Ended December 31,
	2007			2006			2005			2004			2003
Revenue	$	653		$	1,613		$	1,409		$	5,108		$	8,494
Loss from continuing operations		(4,539	)		(4,673	)		(2,658	)		(3,787	)		(1,010	)
Gain (loss) from discontinued operations		(3,398	)		(4,740	)		(1,115	)		(1,406	)		426
Net loss		(7,937	)		(9,413	)		(3,773	)		(5,193	)		(584	)
Net loss per share basic and diluted continuing operations		(0.11	)		(0.12	)		(0.08	)		(0.12	)		(0.04	)
Net gain (loss) per share basic and diluted discontinued operations		(0.08	)		(0.12	)		(0.03	)		(0.05	)		0.02
Net loss per share basic and diluted		(0.18	)		(0.25	)		(0.11	)		(0.17	)		(0.02	)
Cash dividends per share	$	—		$	—		$	—		$	—		$	—
Weighted average shares (000’s)		43,037			38,182			33,023			30,908			23,831
Ending shares outstanding (000’s)		43,271			42,557			37,659			31,852			23,831
Total assets	$	6,679		$	15,392		$	18,927		$	16,048		$	12,391
Long term liabilities		—			1,939			556			155			132
Shareholders’ equity		3,642			10,502			15,936			14,713			11,672
Capital expenditures		4,126			4,737			4,839			1,706			1,409

Selected Financial Data Presented According to U.S. GAAP

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


	Year Ended December 31,
	2007			2006			2005			2004
Revenue	$	653		$	1,613		$	1,409		$	5,108
Income (loss) from continuing operations		(4,539	)		(4,692	)		(2,658	)		(3,768	)
Income (loss) from discontinued operations		(1,916	)		(6,016	)		(1,064	)		(1,521	)
Comprehensive net income (loss)		(6,455	)		(10,836	)		(3,575	)		(5,567	)
Net income (loss) per share basic and diluted from continuing operations		(0.11	)		(0.12	)		(0.08	)		(0.12	)
Net income (loss) per share basic and diluted from discontinued operations		(0.04	)		(0.16	)		(0.03	)		(0.05	)
Net income (loss) per share basic and diluted		(0.15	)		(0.28	)		(0.11	)		(0.17	)
Cash dividends per share	$	—		$	—		$	—		$	—
Weighted average shares (000’s)		43,037			38,182			33,023			30,908
Ending shares outstanding (000’s)		43,271			42,557			37,659			31,852
Total assets	$	6,679		$	13,910		$	18,868		$	15,791
Long term liabilities		—			1,939			556			155
Shareholders’ equity		3,642			9,020			15,877			14,456
Capital expenditures		4,126			4,737			4,839			1,706

B.	Capitalization and Indebtedness

Not Applicable.

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 annual report. The risk factors described below are considered to be the most significant or material ones, but they are not the only risks faced by us.

We may not have sufficient capital to fund our international development activities beyond June 30, 2008.

We entered into a credit agreement with Riata Management, LLC (“Riata”) in May 2008 and must repay the outstanding principal balance of $2 million by June 30, 2008. (see Item 5.B. – “Liquidity and Capital Resources”). We expect to repay the loan with proceeds from the second stage of our recently announced private placement with Riata. If we are unable to close the private placement, which is subject to disinterested shareholder approval, we may be unable to pay off the Riata loan and may not have sufficient capital to fund our international development activities beyond June 30, 2008.

We will have substantial capital requirements that we may be unable to finance on acceptable terms, or at all, which 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 United States, Romania, Morocco and Turkey;

•

success in finding and commercially producing reserves; and

•

prices of natural gas and oil.

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 shareholders. 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 identify liabilities associated with properties or obtain protection from sellers against such liabilities, 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 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. If we establish reserves, 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, labor issues, war or terrorism in or affecting oil producing countries; 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 reserves, our 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 exploration 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 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 (“OML 109”), a 215,000 acre concession located offshore Nigeria, 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 million short-term loan with Riata. We must repay this loan by June 30, 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 may result from increased drilling activities and 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.

Undeveloped resources are uncertain.

We have no established reserves and estimate that we will not have any production for 2008. 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. There is no certainty that we will discover resources or that, if discovered, resources will be economically viable or technically feasible to produce.

The value of our common shares might be adversely affected by matters not related to our own operating performance, which could also subject us to potential securities class action litigation.

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, including the following:

•

general economic conditions in Canada, the United States, Romania, Morocco, Turkey 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.

Although it is not entirely free from doubt, we believe that it is more likely than not that we constitute a passive foreign investment company (a “PFIC”) for U.S. federal income tax purposes. Unless U.S. holders of our common shares make certain elections under U.S. federal income tax rules, they may be subject to certain adverse U.S. federal income tax consequences.

Although it is not entirely free from doubt, we believe that it is more likely than not that we constitute a PFIC for U.S. federal income tax purposes. Consequently, certain adverse U.S. federal income tax consequences may result to U.S. holders of our common shares. Under the PFIC rules, a U.S. holder who disposes, or is deemed to dispose, of our common shares at a gain, or who receives or is deemed to receive certain distributions with respect to our common shares, generally will be required to treat such gain or distributions as ordinary income and pay an interest charge on the tax imposed. Certain elections may be used to reduce or eliminate the adverse impact of the PFIC rules for holders of our common shares (“QEF elections” and “mark-to-market” elections), but these elections may accelerate the recognition of taxable income and may result in the recognition of ordinary income in excess of amounts distributed to you. In addition, if we are a PFIC, our distributions will not qualify for the reduced rate of U.S. federal income tax that applies to qualified dividends paid to non-corporate U.S. taxpayers. The PFIC rules are extremely complex, and prospective U.S. investors are urged to consult their own tax advisers regarding the potential consequences to them of our being classified as a PFIC. See Item 10.E. “Taxation — Passive Foreign Investment Company Considerations.”

We might not be able to obtain necessary permits, approvals or agreements 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 that will be necessary 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 granted to us. Further, we may be required to enter into agreements with private surface owners to obtain access to, and agreements for the location of, surface facilities. In addition, because many of the laws governing oil and gas operations in the international 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;

•

reduced 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 equipment; and

•

declines in natural gas and oil prices.

Our future drilling activities might not be successful, and drilling success rates 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.

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 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 petroleum 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 material 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 our licenses or leases. Failure to obtain an extension of the license or lease, or to 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. – “Business Overview – Material Effects of Governmental Regulations” and Item 4.D. – “Property, Plant and Equipment.”

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 effect 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 Chief Executive Officer, and Dr. David Campbell, our International Exploration Manager. The loss of the services of either of these individuals could have a material adverse effect on our operations. We do not maintain key person insurance on either of these individuals.

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.”

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) (the “Business Act”) on June 10, 1997. We filed articles of amalgamation on January 1, 1999 under the Business Act 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. By articles of amendment and registration of restated articles dated January 17, 2008, we created a new class of preferred shares, unlimited in number and issuable in one or more series.

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 primary 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 2005, 2006 and 2007, we focused on acquiring high-impact international properties, evaluating and acquiring lower-risk cash flow opportunities in the United States and disposing of our Nigerian property. The Nigerian property was sold in June 2005, and we retained a net profits interest of up to $16 million based on future exploration success. 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 participated as a non-operator in four other properties in East Texas, Oklahoma and Lousiana. In 2006, we sold our non-operated working interest in the Bayou Couba property in Louisiana. In 2007, we determined to exit our U.S. operations and focus on the development of our international properties. To that end, we acquired three additional exploration licenses in Turkey, converted a portion of our Moroccan reconnaissance license into two exploration permits, sold our operated South Texas and East Texas properties, and held out our remaining non-operated U.S. properties for sale. We relinquished our two U.K. North Sea licenses in December 2007.

On March 28, 2008, we announced that we had entered into a strategic relationship with Riata. The arrangements with Riata include an equity investment into us, replacing Sphere Petroleum QSC (“Sphere”) as the farm-in partner in both of our Moroccan properties, providing a short-term credit facility to us and providing technical and management expertise to assist us in successfully developing and expanding our international portfolio of projects.

Morocco

In June 2005, we were awarded the Guercif - Beni Znassen reconnaissance license covering 13,750 square kilometers (3.4 million acres) in northeastern Morocco. We operated and held a 60% interest in the reconnaissance license, with Stratic Energy Corporation (“Stratic”) holding a 40% interest in the project. We reprocessed 2D seismic, flew an aeromagnetic/aerogravity survey over the block and conducted geochemical studies in an effort to identify prospective areas. Effective January 2, 2008, we converted a portion of the 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, Stratic and Sphere, Sphere agreed to bear the entire cost of the initial three-year work program to earn a 50% interest in the two Guercif exploration permits. Our interests and the interests of Sphere and Stratic are subject to the 25% interest in the Guercif exploration permits held by the national oil company of Morocco, which is carried during the exploration phase but pays its share of costs in the development phase. In addition, Sphere posted the required $2 million bank guarantee for the initial work program with the Moroccan government and agreed to reimburse us and Stratic for our respective back costs. In April 2008, Sphere assigned all of its interests in the Guercif participation agreement to Riata, who assumed all of the obligations of Sphere with regard to the Guercif participation agreement.

In May 2006, we were awarded the Tselfat exploration permit covering 900 square kilometers (222,345 acres) in northern Morocco. The Tselfat exploration license contains three abandoned fields, Haricha, Tselfat and a portion of the Bou Draa field, which were discovered in 1954, 1918 and 1934, respectively. We posted a $2 million bank guarantee against a work program commitment that 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 plan to evaluate whatever remaining resources we can commercially recover 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 agreed to fund the costs of a 3D seismic survey over the Haricha field and northern portion of the Bou Draa field and also fund the cost of additional geological studies. It is estimated the 3D seismic survey and the studies will be conducted in 2008 at an estimated cost of $6.5 million. If it exercises its

option, Sphere would be committed to (i) fund the drilling and testing of an exploratory well; and (ii) replace our bank guarantee deposited with the Moroccan government. In April 2008, Sphere assigned all of its interests in the Tselfat option and farmout agreement to Riata, who assumed all of the obligations of Sphere with regard to the Tselfat option and farmout agreement.

Romania

In February 2006, we were awarded three production licenses in Romania and received final approval of the petroleum agreements covering each of the licenses in September 2007. The three licenses, Izvoru, Vanatori and Marsa, each cover approximately five square kilometers (1,200 acres) and are located within 100 kilometers of Romania’s capital, Bucharest, in an area known as the Moesian platform. All three fields produced oil and gas but were not fully developed. The licenses were awarded to us based upon our performing certain work programs, such as shooting seismic and drilling or reentering wells, on each of the respective fields over the next three years. The original estimated cost for the work program commitments for the three fields total approximately $9 million. 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 conducted engineering studies which have been merged with the seismic results to provide a field development plan. Subject to closing the second stage of the Riata private placement or accessing other sources of capital, we plan to commence drilling operations in the third quarter of 2008.

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 Iraqi border. The three licenses together cover a total of 660 square kilometers (162,762 acres) and are for a term of four years. The licenses were awarded to us based upon our carrying out certain work programs on each of the respective areas involving technical studies, reprocessing of data and contingent plans for drilling wells. In October 2007, we announced that we had agreed to an option to the farmout of one of our licenses in Turkey, Block 4175; however, the option was not exercised. In March 2008, we announced that we had farmed out a 75% interest in the two licenses near Bismil to an oil and gas exploration company in Turkey, who will also become the operator of the licenses.

In July 2007, we were awarded three additional exploration licenses in southeastern Turkey near the Iranian and Iraqi borders. The three new licenses have four-year terms and cover a total of 1,354 square kilometers (334,618 acres). The licenses were awarded to us based upon a work program of detailed fieldwork. We are the operator and 100% working interest owner of the licenses.

United States

In April 2005, we acquired the South Gillock and State Kohfeldt Units located in Galveston County, Texas. We conducted an extensive workover program in late 2005 and early 2006 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. We commenced drilling a well on the South Gillock property in February 2007. This well was drilled to a depth of 9,860 feet to test portions of the upper and middle Frio formations; the well was completed in the Big Gas Sand formation, but production could not be maintained. In November 2007, we sold all of our interest in the South Gillock and State Kohfeldt Units, as well as the shallow rights over the South Gillock Unit, for $4 million, while maintaining certain deep rights over a portion of the unit.

In late 2006, we participated for our 20% non-operated working interest in a well being drilled on our Oswego property in Dewey County, Oklahoma. The well was completed in multiple zones and is currently producing a small amount of oil and natural gas. 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 judgment 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 leased an additional 630 acres, re-entered and recompleted one of the wells as a stripper oil well and re-entered and sidetracked the second well in the Pecan Gap formation. This well was tied into a gas pipeline in December 2006, and we sold our interest in the Jarvis Dome property in October 2007.

In 2005, we participated for a 20% non-operated working interest in two wells drilled in Panola County, Texas. One of the wells was tied into a pipeline, and the other well was temporarily abandoned as non-commercial. We sold our interest in the Panola County property in December 2007.

In December 2006, we sold our interests in the Bayou Couba property located in St. Charles Parish, Lousiana and in debentures we held of American Natural Energy Corporation, the operator of the Bayou Couba property, for $2 million.

U.K. North Sea

In September 2005, 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 under-explored area of the North Sea between the larger producing areas of the Southern Gas Basin and Central North Sea. We relinquished the licenses in December 2007 after failing to find a partner for a farmout of the property.

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.

Corporate

In December 2006, we completed a private placement resulting in gross proceeds of $3.83 million. We issued a total of 4.5 million Units at a price of $0.85 per Unit and issued warrants to acquire 219,375 common shares as finders’ fees. Each Unit consisted of one common share and one warrant entitling the holder to purchase one common share at $1.05. Each warrant is for a term of two years and will expire December 4, 2008 but may be accelerated if the weighted average closing price of our common shares on the Toronto Stock Exchange (the “TSX”) exceeds $1.55 for 20 consecutive trading days.

In April 2007, we entered into a $3 million bridge loan from Quest Capital Corp. (“Quest”). In August 2007, we increased the loan facility to $4 million, and drew down the additional $1 million under the same terms as the original agreement. In November 2007, we paid down $2 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 million to March 31, 2008. In March 2008, we extended the maturity date to April 30, 2008 in order to facilitate the transactions with Riata.

In May 2007, our shareholders approved the creation of a new class of preferred shares, unlimited in number and issuable in one or more series.

On March 28, 2008, we announced that we had entered into a strategic relationship with Riata. The arrangements with Riata include an equity investment in us, replacing Sphere as the farm-in partner in both of our Moroccan properties, providing a short-term credit facility to us to repay the Quest bridge loan and providing technical and management expertise to assist us in successfully developing and expanding our international portfolio of projects.

Riata will invest in us in a two-stage non-brokered private placement. In the first stage of the private placement, which closed on April 8, 2008, we issued 10 million common shares to an entity associated with Riata at Cdn $0.30 per share generating gross proceeds of Cdn $3 million to us and net proceeds of Cdn $2.9 million, and we appointed N. Malone Mitchell, 3^rd, the President of Riata, to our Board of Directors. In the second stage, which is subject to disinterested shareholder approval, we will issue 25 million common shares to Riata or certain associated persons at Cdn $0.36 per share generating gross proceeds of Cdn $9 million. If shareholder approval is obtained, the second stage of the private placement is expected to close following our annual and special shareholder meeting scheduled for May 20, 2008 (the “Shareholder Meeting”). Riata will also nominate a second director to the Board of Directors at the Shareholder Meeting which will expand the Board of Directors to six directors. Following the closing of the second stage of the private placement, we will have 78,270,762 common shares outstanding, of which Riata and its associated persons will own 44.7%. The net proceeds of both stages of the private placement will be used to fund drilling activities in Romania, to repay the Riata short-term loan as described below and for general corporate purposes.

Upon closing of the initial stage of the private placement, Riata loaned us $2 million, which we used to repay the $2 million loan due to Quest. The Riata loan bears interest at 12% and is secured by guarantees from our first and second tier subsidiaries. Interest and principal are due on June 30, 2008; provided, that if we repay the Riata loan out of the proceeds from the second stage of the private placement before June 15, 2008, interest on the loan will be waived.

In addition, Riata replaced Sphere in both the Tselfat and Guercif permits in Morocco. Sphere assigned to Riata all of Sphere’s rights and interests under both agreements in exchange for Riata assuming all of Sphere’s obligations under the Tselfat and Guercif permits. The addition of Riata in both permits is subject to government approvals.

Principal Capital Expenditures and Divestitures. The following table sets forth our principal capital expenditures and divestitures during year to date 2008 and during 2007, 2006 and 2005:

Principal Capital Expenditures and Divestitures

(In thousands of U.S. dollars)


Expenditure Type	2008⁽¹⁾		2007			2006			2005
Property acquisition	$	—	$	—		$	—		$	3,892
Drilling (leasing, exploration and development)		—		4,126			4,737			947
Facilities and equipment		—		—			—			—
Divestiture of property and equipment		—		(4,264	)		(1,500	)		—

Total Capital Expenditures and Divestitures	$	—	$	(138	)	$	3,237		$	4,839

(1)	From January 1, 2008 to May 9, 2008.

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; and

•

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

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. 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. All of our production to date is from U.S. properties, as disclosed in later sections of this annual report.

Principal Markets. At December 31, 2007, we operated in one reportable segment, the exploration for, and the development and production of, crude oil and natural gas. Identifiable assets, revenue and net loss for our continuing operations in each of our geographic areas are as follows (in thousands of U.S. dollars):


2007	Identifiable Assets (Liabilities)		Revenue⁽¹⁾		Net Loss
United States	$	190	$	—	$	4,182
Morocco		2,196		—		712
Romania		1,881		—		811
Corporate assets		2,412		—		2,232

	$	6,679	$	—	$	7,937


2006
United States	$	4,709	$	—	$	4,740
Morocco		3,414		—		859
Romania		1,894		—		605
Corporate assets		5,375		—		3,209

	$	15,392	$	—	$	9,413


2005
United States	$	11,094	$	—	$	2,922
Morocco		644		—		67
Corporate assets		7,189		—		784

	$	18,927	$	—	$	3,773

(1)	As a result of the decision to sell our U.S. operations in 2007, we reclassified our U.S. properties and any associated revenues and expenses as “discontinued operations.” For further discussion of our discontinued operations, see Item 5.A. – “U.S. Discontinued Operations.”

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

Marketing Channels. We estimate that we will not have any crude oil or natural gas production in 2008. Crude oil production from our U.S. properties was sold under market sensitive or spot price contracts. Natural gas production from these properties was 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 received 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 were 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 and 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 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 our 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. 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.

At December 31, 2007, 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
TransAtlantic Turkey, Ltd.	100	%	Bahamas
TransAtlantic Worldwide Romania SRL	100	%	Romania

We own two other subsidiary corporations, which on a consolidated basis constitute less than 10% of our assets and operating revenue. TransAtlantic Maroc, Ltd. and TransAtlantic Turkey, Ltd. are owned 99.9% by TransAtlantic Worldwide, Ltd. and 0.01% by TransAtlantic Petroleum (USA) Corp. TransAtlantic Worldwide Romania SRL is 100% owned by TransAtlantic Worldwide Ltd.

D.	Property, Plant and Equipment

Morocco

Guercif. In June 2005, we were awarded the Guercif - Beni Znassen reconnaissance license covering 13,750 square kilometers (3.4 million acres) onshore in northeastern Morocco. Effective January 2, 2008, 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 agreed to 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 25% interest in the Guercif exploration permits held by the national oil company of Morocco, Office National des Hydrocarbures et des Mines (“ONHYM”), which is carried during the exploration phase but pays its 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, which runs through January 2011, is estimated to cost approximately $4.5 million and will include the re-entry of an existing well and the acquisition of 300 kilometers of 2D seismic. In addition, Sphere posted the required bank guarantee for the initial work program with the Moroccan government and agreed to reimburse us and Stratic for our respective back costs. On April 8, 2008, Sphere assigned all of its interests in the Guercif participation agreement to Riata in exchange for Riata’s assumption of all of Sphere’s obligations under that agreement. The assignment is subject to government approval.

Under the Guercif participation agreement, Riata will fund 100% of the cost of the initial three-year work program for a 50% interest in the two recently formed Guercif exploration permits. Riata will also fund back costs to us. We will retain a 30% interest and operate the Guercif permits.

Tselfat. 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. While historical production estimates are difficult, historical data suggests cumulative production of approximately 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.

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 agreed to fund the costs to acquire a 3D seismic survey over the Haricha field and northern portion of the Bou Draa field and fund the cost of additional geological studies. On April 8, 2008, Sphere assigned all of its interests in the Tselfat farmout agreement and option agreement to Riata in exchange for Riata’s assumption of all of Sphere’s obligations under those agreements. The assignments are subject to government approval.

Under the Tselfat option and farmout agreement, Riata will fund 100% of the costs of an ongoing evaluation work program, which includes a $4.3 million 3D seismic survey being shot over a portion of the Tselfat permit and additional geological studies. The Tselfat 3D survey commenced in late January and should be completed in May 2008. Riata will have the option to acquire a 50% interest in the Tselfat permit if it commits to fund 100% of the costs of an exploration well on the permit. We will retain a 50% interest and operate the Tselfat permits.

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 2D seismic, 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 kilometer 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. Further opportunities may exist in sub-thrust reservoirs in Jurassic age sandstones.

The Tselfat field was discovered in 1918 by wells drilled on a surface anticline with hydrocarbon seeps. More than 90 shallow wells were drilled and produced less than 500,000 bbls of oil recorded production from Jurassic carbonate reservoirs.

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.

There has been no production on the Guercif exploration permits. There are currently no reserves associated with our Moroccan properties.

Proposed Work Program

Since the award of the Tselfat exploration permit in May 2006, we have been collecting, collating, digitizing and reviewing all of the existing well, production, seismic and other data. We have reprocessed some of the 2D seismic that exists over the block. In addition, we are currently shooting a 3D survey over the Bou Draa and Haricha fields, which is excpected to be completed in the second quarter of 2008. Subject to confirmation of prospectivity from the 3D survey, this will be followed by an exploratory well to evaluate untested Jurassic formations in a sub-thrust structure. 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.

Under the Guercif exploration permits that became effective in January 2008, we plan to re-enter, log and test a well previously drilled in the area, acquire 300 kilometers of 2D seismic and reprocess and reinterpret an aerogravity and magnetic survey.

Commercial Terms

As to Tselfat, 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 involves shooting a 3D seismic survey over an area of at least 50 square kilometers, which we are currently shooting, and drilling a well to a depth exceeding 2,000 meters. We posted a $3 million bank guarantee in support of the program, of which $1 million has been returned to us.

As to Guercif, pursuant to a petroleum agreement (and the companion association contract) dated November 2, 2007, we committed to a work program during the initial three-year period that will involve re-entering, logging and testing a well previously drilled in the area, acquiring 300 kilometers of 2D seismic and reprocessing and reinterpreting an aerogravity and magnetic survey. Sphere posted a $2 million bank guarantee in support of the program. On April 8, 2008, Sphere assigned all of its interests in the Guercif participation agreement to Riata in exchange for Riata’s assumption of all of Sphere’s obligations under that agreement. The assignment is subject to government approval.

During the exploration phase of each exploration permit, we and our partners will operate and bear 100% of the costs to earn a 75% interest. 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 an exploitation concession, we and our partners and ONHYM will each pay our respective share of costs. Upon conversion to an exploitation concession, we pay a discovery bonus to ONHYM, and when certain sustained daily production levels are reached, we pay one-time production bonuses. At Tselfat, the discovery bonus is $500,000 and the production bonuses are as follows: 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. At Guercif, the discovery bonus is $500,000 and the production bonuses are as follows: 10,000 Bbls/d - $500,000; 20,000 Bbls/d - $750,000; 30,000 Bbls/d - $1 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 Mmbbls 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, surface rentals of $2.85 per acre are paid annually by us.

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 our commitment to perform certain work programs on each of the respective fields over the next three years, including shooting seismic and drilling or re-entering wells. There is no current production from any of the fields. The committed work programs for the three fields are estimated to cost approximately $9 million. We are the operator and 100% working interest owner of the fields. The petroleum agreements covering each license were finalized in September 2007, and the three year-term commenced when the agreements were finalized.

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 that produced 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 penetrated by four wells in the Izvoru field but not developed. The initial work program will include the drilling of two new wells in the Izvoru field. We shot a 25 square kilometer 3D seismic survey over the Izvoru field in late 2006. The seismic results were merged with engineering studies to provide a field development plan.

The 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 age 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 2D 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 of crude oil and 7.4 Euro per 1,000 cubic metres 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 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 stipulated requirements. 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.

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 our commitment to perform certain work programs for each of the respective areas. We are currently the operator of the licenses. Following a commercial discovery, each exploration license can be converted to production leases which bear a 12.5% royalty. The work programs are estimated to cost approximately $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 (Block 4173 and Block 4174) are located near Bismil on the Tigris River. These licenses are adjacent to two producing oil fields (Molla and Karakilise). Our primary target is an under explored Palaeozoic play at a depth of approximately 9,800 feet. The work program involves conducting geochemical studies and reprocessing existing 2D seismic data, and based on these results additional 2D seismic may be shot or a well drilled. On March 31, 2008, we announced that we had farmed out our 100% working interest in Blocks 4173 and 4174 to an oil and gas exploration company with operations in Turkey. In exchange for a 75% interest in the exploration licenses, the Turkish company will drill an exploration well before the end of 2008 to test the Bedinan Ordivician formation (approximately 3,700 meters) on one of the licenses. We will retain a 25% interest and will be carried through the costs of testing the well. In addition, the Turkish company paid $150,000 to us to pay for the reprocessing of 2D seismic over the licenses and completing our ongoing geochemical studies. The Turkish company will also become the operator of Blocks 4173 and 4174. Transfer of the interests in the licenses is subject to government regulatory approval.

The third license (Block 4175) is located near Cizre about 60 kilometers from the Iraqi 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. We agreed to a farmout of this license in October 2007, and announced on March 31, 2008 that the holder of the option on Block 4175 determined not to exercise the option. We plan to carry on with our planned geochemical sampling and analysis.

In July 2007, we were awarded three additional onshore exploration licenses (Block 4268, Block 4269 and Block 4270), 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 are the operator and 100% working interest owner of the licenses. There are no reserves associated with our Turkish properties.

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 covert 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.

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 believed there were remaining gas reserves in the gas cap of the South Gillock Unit and its acquisition was premised on this belief. After the acquisition, we 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. Casing failure in the SGU #83 well in December 2006 caused production to decline to its initial 60 Boe/d level. We drilled the SGU #96 well in 2007. This well was drilled to a depth of 9,860 feet to test portions of the upper and middle Frio formations; the well was completed in the Big Gas Sand formation, but production could not be maintained.

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. The deep rights option expired in November 2007, except for a 672-acre tract on which we have a term assignment expiring in June 2008. We are in negotiations to extend the deep rights option for an additional two years.

In November 2007, we sold all of our interest in the South Gillock and State Kohfeldt Units, as well as the shallow rights over the South Gillock Unit, for $4 million, and the buyer assumed all of the plugging and abandonment liability associated with the units.

In Oklahoma, we have 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 a small amount of oil and natural gas. In the McClain County property, we filed a lawsuit to clear up some title issues prior to developing or selling the property. Unless extended, most of the leases associated with these two properties will expire in 2008. There are currently no reserves associated with either of these properties.

Nigeria

We originally acquired an interest in OML 109 in 1992. 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, Inc. (then known as Canadian Occidental Petroleum Ltd.). 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.

In June 2005, we sold our Bahamian subsidiary which owned the interest in OML 109. As part of the transaction, we received $780,000 of cash 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.

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 Nigeria over the past 10 years and the balance of approximately $720,000 was returned to us. As of December 31, 2006, the balance of the escrow fund was $961,000. Pursuant to an agreement reached in 2007, $415,000 of the escrow account was released to us and a net amount of $306,000 was allocated and recently paid out of the escrow account for final payment of liabilities with respect to years 1998 through 2004. The balance of the escrow fund at December 31, 2007 is $240,000. The remaining potential liability to us is for taxes owed for the period from January through June 2005, and we expect the remaining escrow amount to be sufficient to cover any potential liabilities.

Property and Equipment

(In thousands of U.S. dollars)


2007	Cost		Accumulated Depreciation and Depletion		Net Book Value
Crude oil and natural gas properties
United States	$	—	$	—	$	—
Romania		1,572		—		1,572
Furniture, fixtures and other assets		238		238		—

Balance, December 31, 2007	$	1,810	$	238	$	1,572


2006
Crude oil and natural gas properties
United States (reclassified as assets held for sale)	$	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


	Cost		Accumulated Depreciation and Depletion		Net Book Value

2005
Crude oil and natural gas properties
United States (reclassified as assets held for sale)	$	11,308	$	5,521	$	5,787
Furniture, fixtures and other assets		238		212		26

Balance, December 31, 2005	$	11,546	$	5,733	$	5,813

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

In the United States, 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 annual report 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.

At December 31, 2007, we had no oil and gas reserves and no related future net revenue. Our reserves at December 31, 2006 and 2005 were all attributable to two properties: the South Gillock property in South Texas and the Jarvis Dome property in East Texas. We sold all of our interest in the South Gillock property in November 2007 and sold all of our interest in the Jarvis Dome property in October 2007. We have a non-operated 20% working interest in one well on our Oswego property in Oklahoma, and no reserves are attributed to that property or to any of our international properties.

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 and 2005. We had no proved reserves as of December 31, 2007. All of our reserves were located in the United States. Oil is expressed in Mbbls, and natural gas is expressed in Mmcf.

Proved Reserves⁽¹⁾


	Gross⁽²⁾		Net⁽²⁾
	Oil⁽³⁾	Natural Gas	Oil⁽³⁾	Natural Gas
Proved Developed Producing⁽⁴⁾⁽⁵⁾	39.3	1,094.7	31.1	847.9
Proved Developed Non-Producing⁽⁴⁾⁽⁶⁾	23.6	139.6	17.0	107.9

	62.9	1,234.3	48.1	955.8
Proved Undeveloped⁽⁷⁾	0.0	505.3	0.0	391.3

2005 Total:	62.9	1,739.6	48.1	1,347.1


	Gross⁽²⁾		Net⁽²⁾
	Oil⁽³⁾	Natural Gas	Oil⁽³⁾	Natural Gas
Proved Developed Producing⁽⁴⁾⁽⁵⁾	8.9	483.3	7.2	374.0
Proved Developed Non-Producing⁽⁴⁾⁽⁶⁾	0.0	139.3	0.0	107.8

	8.9	622.6	7.2	481.8
Proved Undeveloped⁽⁷⁾	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 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)	“Oil” volumes include condensate (light oil) and medium crude oil.

(4)	“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.

(5)

“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.

(6)	“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.

(7)

“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.

The following table sets forth the number of wells in which we held a working interest as of December 31, 2007:


	Oil		Natural Gas
	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾
Oklahoma
Producing	0	0	1	0.2
Non-producing	0	0	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).

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, 2007, 2006 and 2005:


	Net Production
Year	Oil⁽¹⁾	Natural Gas
2007	6,079	41,409
2006	8,975	129,867
2005	16,903	93,661

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

Costs Incurred

The following table summarizes the capital expenditures made by us on oil and natural gas properties for the year ended December 31, 2007.


(In Thousands of U.S. Dollars)	Property Acquisition Costs	Exploration Costs	Development Costs
	Unproved Properties
United States	$ 106.4	—	$4,032.4

Properties with No Attributed Reserves

The following table sets out our undeveloped land position effective December 31, 2007:


	Undeveloped (acres)
	Gross⁽¹⁾	Net⁽²⁾
United States	3,212	1,953
Morocco	1,184,345	510,945

Romania	3,600	3,600

Turkey	502,290	502,290

Total	1,693,447	1,018,788

Notes:

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

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

Substantially all of our net undeveloped acreage in the United States will expire in 2008.

Abandonment and Reclamation Costs

We sold our interests in the Jarvis Dome property and South Gillock property (consisting of the South Gillock and State Kohfeldt Units) in October and November 2007, respectively, and the Bayou Couba property in December 2006. We have no further liability for abandonment or reclamation costs as to those properties. We have reserved $8,000 for estimated abandonment and reclamation costs regarding its one producing well in Oklahoma, in which we own a 16% net revenue interest.

Item 4A.

Unresolved Staff Comments

Not applicable.

Item 5.

Operating and Financial Review and Prospects

A.	Operating Results

The following discussion for the three fiscal years ended December 31, 2007 should be read in conjunction with our consolidated financial statements and notes thereto.

Summary

In 2007, we determined to focus on the development of our international properties and exit our U.S. operations. To that end, we:

•

converted our Moroccan reconnaissance license into two exploration permits;

•

agreed to the farmout of all of our exploration permits in Morocco;

•

received final government approval of our Romanian licenses;

•

acquired three additional exploration licenses in Turkey;

•

farmed out one of our licenses in Turkey; and

•

sold our operated South Texas and East Texas properties.

As a result of the decision to sell our U.S. operations in 2007, we reclassified our U.S. properties as “discontinued operations.” Accordingly, revenues and expenses associated with our U.S. cost center in 2007 and comparative periods are reflected as components of “loss from discontinued operations.”

Consolidated net revenues for the year ended December 31, 2007 were $653,000, which represents a decrease from the $1.6 million reported for 2006 and the $1.4 million reported for 2005. The decrease in revenue is primarily due to lower production at South Gillock and the sale of the South Gillock and Jarvis Dome properties in the fourth quarter. The consolidated net loss for 2007 was $8.0 million or $0.18 loss per share (basic), compared to consolidated net loss of $9.4 million or $0.25 loss per share (basic) for 2006 and a consolidated net loss of $3.8 million or $0.11 loss per share (basic) for 2005. The decrease in the loss for 2007 as compared to 2006 is a result of exiting unprofitable operations in the United States. The increase in the loss for 2006 as compared to 2005 is primarily due to $2.3 million expensed in connection with our expansion of foreign activities in 2006 and an impairment of $3.1 million of which $2.7 million related to U.S. exploration and the balance to the value of year-end reserves resulting from lower reserves and a lower year-end natural gas price.

We incurred $4.1 million in capital expenditures in 2007 compared to $4.7 million in 2006 and $4.8 million in 2005. At December 31, 2007, we had a working capital deficit of $202,000 and significant capital expenditures projected for 2008. Subsequent to December 31, 2007, we announced the formation of a strategic relationship with Riata that provides an equity investment in us, replacing Sphere as the farm-in partner in both of our Moroccan properties, providing a short-term credit facility to us and providing technical and management expertise to assist us in successfully developing and expanding our international portfolio of projects. We will continue to evaluate options for additional sources of funding to develop our portfolio of properties, including farmout arrangements, the sale of certain non-core properties, and financings.

International Operations

We continued to evaluate and expand our initiatives in Morocco, Romania and Turkey during 2007. Approximately $2.3 million of costs were incurred and expensed during 2007 and 2006 from the pre-acquisition, reconnaissance, evaluation and development activities related to our international oil and gas properties. The following table outlines our expenditures by country for 2007, 2006 and 2005:


	Year Ended December 31,
(In thousands of U.S. dollars)	2007		2006		2005
Morocco - Three Exploration Permits	$	811	$	874	$	75
U.K. North Sea - Two Exploration Licenses		746		553		—
Romania - Three Production Licenses		239		605		—
Turkey - Six Exploration Licenses		204		222		96
Other Unallocated		312		25		269

Total	$	2,312	$	2,279	$	440

In addition to these costs, we also capitalized $1.6 million of expenditures related to the seismic surveys completed at the end of 2006 in Romania. These surveys included a 3D seismic survey at the Izvoru license and 2D seismic surveys at the Vanatori and Marsa licenses.

Morocco. 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 agreed to fund the costs to acquire a 3D seismic survey over the Haricha field and northern portion of the Bou Draa field and fund the cost of additional geological studies. The 3D seismic survey and the studies will be conducted in 2008 at an estimated cost of $6.5 million. If it exercises its option, Sphere would be committed to (i) fund the drilling and testing of an exploratory well; and (ii) replace our bank guarantee deposited with the Moroccan government. On April 9, 2008, we announced that Sphere assigned all of its interests in the Tselfat option and farmout agreement to Riata, who assumed all of the obligations of Sphere with regard to that agreement.

Effective January 2008, we converted a portion of our Guercif - Beni Znassen reconnaissance license into two exploration permits. Pursuant to a participation agreement between us (30%), Stratic (20%) and Sphere (50%), Sphere agreed to bear the entire cost of the initial three-year work program to earn its 50% interest in the two Guercif exploration permits. Our interest and the interests of Sphere and Stratic are subject to the 25% interest in the Guercif exploration permits held by the national oil company of Morocco, which is carried during the exploration phase but pays its share of costs in the development phase. In addition, Sphere posted the required $2.0 million bank guarantee for the initial work program with the Moroccan government and agreed to reimburse us and Stratic for our respective back costs. On April 9, 2008, we announced that Sphere assigned all of its interests in the Guercif participation agreement to Riata, who assumed all of the obligations of Sphere with regard to the Guercif exploration permits.

Romania. In September 2007 we received final government approval of our three Romanian licenses. In 2006 we capitalized $1.6 million of expenditures related to the seismic surveys completed in Romania. These surveys included a 3D seismic survey at the Izvoru license and 2D seismic surveys at the Vanatori and Marsa licenses. We will have until 2010 to complete work programs for each of the licenses.

Turkey. We have six exploration licenses and have remaining work commitments which total approximately $945,000 on the licenses, three of which extend through June 2009 and three of which extend through July 2010. We spent $218,000 on these work programs in 2007. In October 2007, we agreed to the farmout of one of our licenses in Turkey, Block 4175, but the farmout partner has since relinquished its option on this license. On March 31, 2008, we announced that we had entered into a farmout agreement on two other licenses in Turkey, Blocks 4173 and 4174.

U.K. North Sea. We were unable to farmout or develop our U.K. North Sea property and relinquished our rights to that property in December 2007.

U.S. Operations

Revenue and Production. We recognized net oil and gas sales of $653,000 for 2007, a decrease from 2006 sales of $1.6 million and 2005 sales of $1.4 million, which is primarily the result of decreased production at South Gillock and the sale of the South Gillock and Jarvis Dome properties in the fourth quarter of 2007. During 2007, we had production from two operated fields in Texas (South Gillock and Jarvis Dome) as well as from our non-operated interest in Dewey County, Oklahoma. We sold 13,000 Boe in 2007 compared to 36,300 Boe for 2006 and 30,962 Boe for 2005.

Operating and Depreciation, Depletion and Accretion Expenses. Lease operating expenses decreased to $1.2 million for 2007 as compared to $1.8 million incurred in 2006 and $1.9 million incurred in 2005. Depreciation, depletion and accretion (“DDA”) decreased to $2.2 million for 2007 as compared to $4.6 million for 2006, with both periods including a write-down of our oil and gas properties. The decreases in lease operating expenses and DDA are due to the sale of our South Gillock and Jarvis Dome properties and to a higher impairment charge in 2006. An impairment of $1.9 million on U.S. properties was recorded for 2007. The impairment charge reflected the write-down of the remaining U.S. properties to their sales value.

Exploration. At South Gillock, we incurred costs of $3.8 million in drilling the SGU #96 well in 2007. We also participated in the Riseley well on our Oswego property in Oklahoma, incurring costs of $250,000 for our 20% participation in this well. In 2006, we incurred costs of $1.9 million in drilling and reworking operations at our Jarvis Dome property in East Texas and $710,000 for our participation in the Riseley well in Oklahoma. In November 2007, we sold for $4.0 million our operated interest in the South Gillock property and, in October 2007, we sold for $250,000 our operated interest in the Jarvis Dome property.

U.S. Discontinued Operations

We recorded a loss from discontinued operations of $3.4 million for 2007, as compared to a loss from discontinued operations of $4.7 million in 2006 and $1.1 million in 2005. The results of discontinued operations are classified separately net of applicable income taxes. Loss from discontinued operations includes the following amounts:


	Year Ended December 31,
	2007		2006		2005
Revenues, oil and gas sales – net	$	653	$	1,613	$	1,409
Expenses:
Lease operating expenses		1,167		1,779		1,918
Depletion, depreciation and accretion		351		1,513		606
Interest expense		307		—		—
Financing expense - shares issued		359		—		—
Write-down of assets		1,867		3,061		—
Loss from discontinued operations	$	3,398	$	4,740	$	1,115

General and Administrative and Other Expenses. General and administrative costs of $2.7 million in 2007 were slightly higher than the $2.4 million and $2.3 million reported for 2006 and 2005, respectively. These costs included $554,000 of stock-based compensation expense in 2007 compared to $260,000 in 2006 as a result of a greater number of options granted in 2007 versus 2006.

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 our prior operations in Nigeria. At December 31, 2006, the balance of the escrow fund was $961,000. Pursuant to an agreement reached in 2007, $415,000 of the escrow account was released to us and a net amount of $306,000 was allocated and recently paid out of the escrow account for final payment of liabilities with respect to fiscal years 1998 through 2004. The balance of the escrow fund at December 31, 2007 was $240,000. 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

Our financial statements have been prepared on the basis of accounting principles applicable to a going concern, which assumes that we will realize our assets and discharge our liabilities in the normal course of operations.

Given the capital-intensive nature of oil and gas exploration as well as the uncertainty of economic success from our existing projects, significant additional capital will be required to fund our existing and additional projects. Accordingly, we will evaluate additional financings to meet our capital needs. 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 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.

In April 2007, we entered into a $3 million short-term standby bridge loan from Quest. In August 2007, the loan facility was increased to $4 million, and we drew down the additional $1 million under the same terms as the original agreement. In November 2007, we paid down $2 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 million to March 31, 2008. The loan was then paid in its entirety in April 2008.

As of December 31, 2007, we had cash and short-term investments of $2.2 million, $2.0 million in current debt, no long-term debt and a working capital deficit of $202,000. As of December 31, 2006, we had no debt, 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. As of December 31, 2007, we had $2.3 million in restricted cash, of which $2.0 million will be released to us at various times once certain work commitments in Morocco are met.

On March 28, 2008, we entered into an investment agreement (the “Investment Agreement”) with Riata pursuant to which Riata will invest in us in a two-stage non-brokered private placement. In the first stage of the private placement, which closed on April 8, 2008, we issued 10 million common shares to an entity associated with Riata at Cdn $0.30 per share generating gross proceeds of Cdn $3 million to us and net proceeds of Cdn $2.9 million. On March 28, 2008, we and Quest extended the maturity date of the Quest loan to April 30, 2008 in order to facilitate the transactions with Riata.

On April 8, 2008, we entered into a $2 million short-term loan agreement with Riata. We used the proceeds of that loan to repay the $2 million loan due to Quest. The Riata loan bears interest at 12% and is secured by guarantees from our first and second tier subsidiaries. Interest and principal are due on June 30, 2008; provided, that if we repay the Riata loan out of the proceeds from the second stage of the private placement before June 15, 2008, interest on the loan will be waived.

In the second stage of the private placement, which is subject to disinterested shareholder approval, we will issue 25 million common shares to Riata or certain associated persons at Cdn $0.36 per share generating gross proceeds of Cdn $9 million. If shareholder approval is obtained, this second stage is expected to close following the Shareholder Meeting. Following the closing of the second stage of the private placement, we will have 78,270,762 shares outstanding, of which Riata and its associated persons will own 44.7%. The net proceeds of both stages of the private placements will be used to fund drilling activities in Romania, to repay the Riata short-term loan as described below and for general corporate purposes.

Changes in cash, short-term investments and working capital

The decrease in cash and short-term investments for 2007 was $2.5 million compared to the decrease of $2.9 million for fiscal 2006 and $2.1 million in 2005. The significant decrease in cash during 2007 was primarily due to cash used in operations of $6 million and the investment in oil and gas properties of $4.1 million in the United States. We received proceeds from a short-term loan of $4 million in 2007. We also received $4 million in November 2007 for proceeds from the sale of our operated interest in the South Gillock property in Galveston County, Texas. We used $2 million of these proceeds to partially repay the short-term loan. Working capital decreased approximately $2.4 million in 2007 as a result of a decrease in cash and short-term investment of $2.5 million, an increase in loan payables of approximately $2 million and a decrease in payables of $1.2 million.

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 $100,000 at December 31, 2007. We held $200,000 and $2 million in Canadian dollars at December 31, 2006 and December 31, 2005, respectively. We convert from U.S. dollars to other currencies as needed. An increase in value of the local currencies relative to the U.S. dollar will have a negative effect as our expenses incurred would, in turn, increase in U.S. dollars. 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.

Asset Retirement Obligations

We have estimated the net present value of asset retirement obligations of $8,000 as of December 31, 2007 for the abandonment and reclamation of oil and gas properties in the United States. In connection with the sale of our Jarvis Dome and South Gillock properties in the third quarter of 2007, the buyers of the properties assumed these abandonment and reclamation liabilities.

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. 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 prices to fall.

E.	Off-Balance Sheet Arrangements

As at December 31, 2007, we had no off-balance sheet arrangements.

F.	Contractual Obligations

The following table sets forth our contractual obligations at December 31, 2007.

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	$	377	$	113	$	253	$	11	$	—
Debt		2,000		2,000		—		—		—
Total	$	2,377	$	2,113	$	253	$	11	$	—

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

We have work program commitments of $3 million under our Tselfat exploration permit in Morocco that are supported by a fully-funded bank guarantee totaling $2 million. 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 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.

G.	Forward-Looking Statements

Certain statements in this annual report, 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 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.D.—”Risk Factors,” and in other documents that we file with or furnish to the SEC 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, except as required by law.

Item 6.

Directors, Senior Management and Employees

A.	Directors and Senior Management


Name	Position Held	Age
Michael D. Winn	Director	46
Brian B. Bayley	Director	55
Alan C. Moon	Director	62
N. Malone Mitchell, 3^rd	Director	46
Scott C. Larsen	President and Chief Executive Officer, Director	56
Hilda Kouvelis	Vice President and Chief Financial Officer	45
Dr. David Campbell	International Exploration Manager	55
Jeffrey S. Mecom	Vice President and Corporate Secretary	42

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
Iron Creek Capital Corp.		TSX Venture Exchange
Lake Shore Gold Corp.		TSX
Lara Exploration Ltd.		TSX Venture Exchange
Reservoir Capital Corp.		TSX Venture Exchange
Sanu Resources Ltd.		TSX Venture Exchange
Sprott Resource Corp.		TSX

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, a publicly traded mortgage investment corporation. 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 Ltd., Mr. Bayley was President and Chief Executive Officer 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
Columbian Mines Corporation		TSX Venture Exchange
Cypress Hills Resource Corp.		TSX Venture Exchange
Esperanza Silver Corp.		TSX Venture Exchange
Eurasian Minerals Inc.		TSX Venture Exchange
Gleichen Resources Ltd.		TSX Venture Exchange
Greystar Resources Ltd.		TSX
Kirkland Lake Gold Inc.		TSX
Midway Gold Corp.		TSX Venture Exchange
PetroFalcon Corp.		TSX
Pretium Capital Corp.		TSX Venture Exchange
Quest Capital Corp.		TSX
Rocky Mountain Resources Corp.		TSX Venture Exchange
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 investment firm, since he formed that company in 1997. Prior to that, Mr. Moon was President and Chief Operating Officer 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
Enervest Diversified Income Trust		TSX
Lake Shore Gold Corp.		TSX Venture Exchange
Maxy Gold Corp.		TSX Venture Exchange
Superior Diamonds Inc.		TSX Venture Exchange

N. Malone Mitchell, 3^rd has served as a director since April 2008. Mr. Mitchell has served as the President of Riata, an Oklahoma city-based private oil and natural gas exploration and production company, since he formed that company in 2005. In 2006, Mr. Mitchell served as President and Chief Operating Officer of Sandridge Energy, Inc., previously known as Riata Energy, Inc. Prior to 2006, Mr. Mitchell served as President, Chief Executive Officer and Chairman of Riata Energy, Inc., which he founded and built into one of the largest privately held energy companies in the United States.

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 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.

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 graduation he joined Esso Expro UK as a seismic interpreter and later spent the majority of his professional career with ARCO both in the U.K. 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.

Hilda D. Kouvelis has served as our Chief Financial Officer since January 2007 and as a Vice President since May 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.

Jeffrey S. Mecom has served as our Corporate Secretary since May 2006 and as a Vice President since May 2007. Before joining us, Mr. Mecom served as Vice President, Legal and Corporate Secretary with Aleris International, Inc., a NYSE-listed international metals recycling and processing company, where he was employed from 1995 until 2005. Prior to that he served as in-house counsel to a Dallas-based independent energy company and lectured at the Estonian Business School in Tallinn, Estonia. 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.

Pursuant to the Investment Agreement, Mr. Mitchell, President of Riata, was designated by Riata and appointed by us as a director in connection with the closing of the first stage of the private placement. To the best of our knowledge, there are no arrangements or understandings with major shareholders, customers, suppliers or others, pursuant to which any other person referred to above was selected as a director or member of senior management. None of our directors, officers or employees has any family relationship with one another.

B.	Compensation

The following table sets forth all annual and long-term compensation for services in all capacities in 2007 for our directors and officers as of December 31, 2007.


	Salary		Bonus		Other Annual Compensation			Options Granted
	Salary		Bonus		Other Annual Compensation			Number of Common Shares Underlying Options	Exercise Price		Expiry Date
Scott C. Larsen, President, Chief Executive Officer and Director	$	240,000	$	120,000		-0-		400,000 250,000	$ $	1.00 0.31	January 10, 2012 December 4, 2012
Hilda Kouvelis Vice President and Chief Financial Officer	$	147,000	$	10,000		-0-		75,000	$	1.00	January 10, 2012
Jeffrey S. Mecom Vice President and Corporate Secretary	$	120,000	$	15,000		-0-		125,000 100,000	$ $	1.00 0.31	January 10, 2012 December 4, 2012
Michael D. Winn Director		-0-		-0-	$	60,000	⁽¹⁾	35,000	$	0.31	December 4, 2012
Brian B. Bayley Director		-0-		-0-	$	12,000	⁽¹⁾	35,000	$	0.31	December 4, 2012
Alan C. Moon Director		-0-		-0-	$	12,000	⁽¹⁾	35,000	$	0.31	December 4, 2012

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

No stock options were exercised in 2007 by any of our officers or directors.

C.	Board Practices

Term of Office. At the end of 2007, we had four directors. The terms of all four expire at the Shareholder Meeting:


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

We entered into an employment agreement with Mr. Larsen, our President and Chief Executive Officer, effective July 1, 2005. The agreement expires upon the death, disability, resignation or other termination of employment of Mr. Larsen. This agreement provides for an annual base salary to Mr. Larsen as approved by our Board of Directors, 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) (the “Option Plan”) and other benefits made available to our executives resident in the United States. 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” or (2) by Mr. Larsen within sixty days of an event that constitutes “constructive dismissal,” 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” 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.

For purposes of the employment agreement, termination for “cause” is deemed to exist if: (i) we determine in good faith and following a reasonable investigation that Mr. Larsen has committed fraud, theft or embezzlement from us; (ii) Mr. Larsen pleads guilty or nolo contendere to or is convicted of any felony or other crime involving moral turpitude, fraud, theft or embezzlement; (iii) Mr. Larsen substantially fails to perform his duties according to the terms of his employment (other than any such failure resulting from Mr. Larsen’s disability) after we have given Mr. Larsen written notice setting forth the nature of the failure to perform the duties and a reasonable opportunity to correct it; (iv) a breach of any of the non-solicitation or confidentiality provisions of the employment agreement (provided that we act in good faith in determining that such a breach constitutes “cause”) or a material breach of any other provision of the employment agreement; or (v) Mr. Larsen has engaged in on-the-job conduct that materially violates our code of conduct or other policies, as determined in our sole discretion. Mr. Larsen’s resignation in advance of an anticipated termination for “cause” also constitutes a termination for “cause.”

the occurrence of any of the aforesaid events with the consent of Mr. Larsen or termination of the employment of Mr. Larsen for just cause, death or disability; or (iv) having the positions of Chief Executive Officer and President held by two different individuals so long as Mr. Larsen occupies one or the other position.

A “change of control” is defined in the employment agreement as the occurrence of any of: (i) the purchase or acquisition of our common shares and/or securities convertible into our common shares or carrying the right to acquire our common shares (“Convertible Securities”) as a result of which a person, group of persons or persons acting jointly or in concert, or any affiliates or associates of any such person, group of persons or any of such persons acting jointly or in concert (collectively, the “Holders”) beneficially own or exercise control or direction over our common shares and/or Convertible Securities such that, assuming the conversion of the Convertible Securities beneficially owned by the Holders thereof, the Holders would have the right to cast more than 50% of the votes attached to all of our common shares; provided that, the acquisition of our common shares or Convertible Securities pursuant to the issuance of securities by us which results in a Holder beneficially owning or exercising control or direction over 50% of the votes attached to all of our common shares (assuming conversion of the Convertible Securities beneficially owned by Holders thereof) which is approved by our Board of Directors prior to the issuance of securities shall not constitute a “change of control;” or (ii) approval by the shareholders of: (A) an amalgamation, arrangement, merger or other consolidation or combination of us with another entity as a result of which our shareholders immediately prior to the transaction will not, immediately after the transaction, own securities of the successor or continuing entity which would entitle them to cast more than 50% of the votes attaching to all of the voting securities of the successor or continuing entity, (B) a liquidation, dissolution or winding-up of us, (C) the sale, lease or other disposition of all or substantially all of our assets, (D) the election at a meeting of our shareholders of a number of directors, who were not included in the slate for election as directors approved by the prior Board of Directors, and would represent a majority of the Board of Directors, or (E) the appointment of a number of directors which would represent a majority of the Board of Directors and which were nominated by any holder of our voting shares or by any group of holders of our voting shares acting jointly or in concert and not approved by the prior Board of Directors.

We entered into substantially similar employment agreements with Jeffrey Mecom, our Vice President and Secretary, and Hilda Kouvelis, our Vice President and Chief Financial Officer, effective January 1, 2008 and May 1, 2008, respectively. Mr. Mecom’s employment agreement provides for an annual base salary of $150,000, and Ms. Kouvelis’ employment agreement provides for an annual base salary of $160,000. Both agreements provide for termination amounts equal to one half of the annual base salary plus $7,500.

Our Board of Directors currently has three committees: an Audit Committee, Compensation Committee and Corporate Governance Committee. Michael D. Winn, Brian B. Bayley and Alan C. Moon comprise the Audit Committee, the Compensation Committee and the Corporate Governance Committee and are independent in accordance with U.S. and Canadian securities laws.

Audit Committee. The Audit Committee operates under the Audit Committee Terms of Reference, which governs the Audit Committee’s duties and conduct. The Audit Committee monitors and oversees the quality of our financial reporting and systems, our external auditors and our risk management procedures. The Audit Committee also reviews our financial reporting in connection with our annual audit and the adequacy and effectiveness of our internal controls and procedures, recommends to the Board of Directors the appointment of our external auditors, determines the independence of our external auditors, and reviews and recommends to the Board of Directors for approval our audited annual financial statements, unaudited interim financial statements and management’s discussion and other public disclosures related to our financial statements. To maintain the effectiveness and integrity of our financial controls, the Audit Committee monitors internal control and management information systems. In addition, the Audit Committee has been designated by the Board of Directors to serve as the Reserves Committee and reviews our procedures relating to disclosure of our oil and gas activities, the appointment of our independent reserves engineers, and reviews, approves and recommends to the Board of Directors for approval the reserve reports, the report of our independent reserve engineers and related reports.

Compensation Committee. The Compensation Committee operates under the Compensation Committee Charter, which governs the Compensation Committee’s duties and conduct. The Compensation Committee establishes and reviews our compensation policies and reviews our senior management’s performance. The Compensation Committee makes recommendations to the full Board of Directors for approval of granting stock options under the Option Plan and with respect to salaries and bonuses for executive officers and directors. Our

compensation philosophy is aimed at attracting and retaining quality and experienced personnel, which is critical to our success. Employee compensation, including executive officer compensation, is comprised of three elements: base salary, short-term incentive compensation (being cash bonuses) and long-term incentive compensation (being stock options). Since our focus has been in international oil and gas exploration, consideration is given to the factors such as time overseas, the risk inherent in certain international operations and the greater degree of time and effort international transactions may require. The Compensation Committee views the totality of our performance in its evaluation of compensation for executive officers.

Copies of the Audit Committee Terms of Reference and the Compensation Committee Charter can be obtained on our web site at www.tapcor.com.

D.	Employees

As of December 31, 2007, we employed six people full time. The persons employed are the Chief Executive Officer, the Chief Financial Officer, and four persons in legal, geology and administration. Five employees are located in Dallas, Texas, and one employee is located in Rabat, Morocco. 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 2007.

E.	Share Ownership

The following table sets forth the number of common shares beneficially owned by our directors and officers as of April 30, 2008:


Shareholder	Number of Common Shares Beneficially Owned⁽¹⁾		Percentage of Outstanding Common Shares Beneficially Owned⁽¹⁾
Scott C. Larsen, President, Chief Executive Officer and Director	1,002,153	⁽²⁾	1.9	%
Hilda Kouvelis Vice President and Chief Financial Officer	170,000	⁽³⁾	*
Jeffrey S. Mecom Corporate Secretary and Vice President	208,333	⁽⁴⁾	*
Michael D. Winn Director	930,000	⁽⁵⁾	1.7	%
Brian B. Bayley Director	393,334	⁽⁶⁾	*
Alan C. Moon Director	461,947	⁽⁷⁾	*
N. Malone Mitchell, 3^rd Director	10,000,000	⁽⁸⁾	18.8	%

*	Less than 1% of the outstanding common shares.

(1)

Beneficial ownership as reported in the above table has been determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The number of common shares shown as beneficially owned includes shares of common shares subject to options exercisable within 60 days after April 30, 2008. The percentages indicated are based on 53,270,762 common shares outstanding on April 30, 2008. Common shares subject to options exercisable within 60 days after April 30, 2008 are deemed outstanding for computing the percentage of the person or entity holding such securities but are not outstanding for computing the percentage of any other person or entity.

(2)	Includes 750,000 common shares subject to stock options.

(3)	Includes 150,000 common shares subject to stock options.

(4)	Includes 183,333 common shares subject to stock options.

(5)	Includes 735,000 common shares subject to stock options.

(6)	Includes 243,334 common shares subject to stock options.

(7)	Includes 343,334 common shares subject to stock options.

(8)

Represents shares held by Dalea Partners, LP (“Dalea Partners”). Dalea Management, LLC (“Dalea Management”) is the general partner of Dalea Partners. Mr. Mitchell is a partner of Dalea Partners and a manager of Dalea Management. Dalea Partners, Dalea Management and Mr. Mitchell share voting and investment power over the shares held by Dalea Partners and may be deemed to beneficially own these shares.

The following table sets forth the number of common shares subject to options held by our directors and officers as of May 8, 2008:


	Number of Common Shares Underlying Options	Exercise Price of Options		Expiry Date of Options
Scott C. Larsen, President, Chief Executive Officer and Director	80,000 75,000 75,000 100,000 70,000 400,000 250,000	$ $ $ $ $ $ $	0.75 0.90 0.75 0.90 1.10 1.00 0.31	6/13/2008 3/9/2009 12/17/2009 10/11/2010 4/5/2011 1/10/2012 12/4/2012
Hilda Kouvelis Vice President and Chief Financial Officer	25,000 50,000 75,000	$ $ $	0.90 1.10 1.00	10/11/2010 4/5/2011 1/10/2012
Jeffrey S. Mecom Corporate Secretary and Vice President	25,000 125,000 100,000	$ $ $	1.12 1.00 0.31	4/17/2011 1/10/2012 12/4/2012
Michael D. Winn Director	150,000 350,000 100,000 150,000 35,000	$ $ $ $ $	0.89 0.75 0.90 1.00 0.31	6/7/2009 12/17/2009 10/11/2010 1/10/2012 12/4/2012
Brian B. Bayley Director	40,000 75,000 35,000 25,000 50,000 35,000	$ $ $ $ $ $	0.75 0.90 0.75 0.90 1.00 0.31	6/13/2008 3/9/2009 12/17/2009 10/11/2010 1/10/2012 12/4/2012
Alan C. Moon Director	150,000 100,000 25,000 50,000 35,000	$ $ $ $ $	0.90 0.75 0.90 1.00 0.31	3/9/2009 12/17/2009 10/11/2010 1/10/2012 12/4/2012

Our officers or directors do not have different voting rights than any other shareholders.

For a description of the Option Plan, please see Part II, Item 10.C. – “Material Contracts and Agreements.”

Item 7.

Major Shareholders and Related Party Transactions

A.	Major Shareholders

As of May 8, 2008, 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 Common Shares Beneficially Owned		Percentage of Outstanding Common Shares Beneficially Owned
The Rule Family Trust	4,106,176		7.7	%
Dalea Partners, LP	10,000,000	⁽¹⁾	18.8	%

(1)

Dalea Management is the general partner of Dalea Partners. Mr. Mitchell is a partner of Dalea Partners and a manager of Dalea Management. Dalea Partners, Dalea Management and Mr. Mitchell share voting and investment power over the shares held by Dalea Partners and may be deemed to beneficially own these shares.

Our major shareholders do not have different voting rights than any other shareholders. As of May 8, 2008, our shareholders list showed 53,270,762 common shares outstanding with 217 registered shareholders in Canada holding 32,334,695 common shares and 22 registered holders in the United States holding 20,908,954 common shares. We are not controlled, directly or indirectly, by any corporation, foreign government or other person. The only significant change in the percentage ownership held by major shareholders during the past three years was the acquisition of 10,000,000 common shares by Dalea Partners, LP, an associated person of Riata, on April 8, 2008.

B.	Related Party Transactions

Except as follows, none of our associates, 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, 2007, or in any proposed transaction involving us.

In April 2007, we entered into a U.S. $3 million short-term loan from Quest. We mortgaged certain of our assets, including the South Gillock property, and pledged 100% of the common shares of our wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. On August 10, 2007, we and Quest increased the loan facility to $4 million. On November 13, 2007, we paid down $2 million in principal on the loan in connection with the sale of our South Gillock property, and we and Quest extended the maturity date on the outstanding principal balance of $2 million to March 31, 2008. We and Quest further extended the maturity date to April 30, 2008 in order to facilitate the transactions with Riata. We paid off the Quest loan on April 8, 2008. Brian B. Bayley, one of our directors, is Co-Chairman of Quest and abstained from decision-making relating to the credit agreement. Michael D. Winn, another of our directors, was also a director of Quest until December 31, 2007. Mr. Winn abstained from decision-making relating to the credit agreement while he was a director of Quest.

Board of Directors upon closing of the first stage of the private placement. In the second stage of the private placement, which is subject to disinterested shareholder approval, we will issue 25 million common shares to Riata or certain associated persons at Cdn $0.36 per share generating gross proceeds of Cdn $9 million. If shareholder approval is obtained, the second stage of the private placement is expected to close following the Shareholder Meeting. Riata will also nominate a second director to the Board of Directors at the Shareholder Meeting which will expand the Board of Directors to six directors. Following the closing of the second stage of the private placement, we will have 78,270,762 common shares outstanding, of which Riata and its associated persons will own 44.7%. The net proceeds of both stages of the private placement will be used to fund drilling activities in Romania, to repay the Riata short-term loan as described below and for general corporate purposes.

On April 8, 2008, Riata loaned us $2 million, which we used to repay the $2 million loan due to Quest. The new Riata loan bears interest at 12% and is secured by guarantees from our first and second tier subsidiaries. Interest and principal are due on June 30, 2008; provided, that if we repay the Riata loan out of the proceeds from the second stage of the private placement before June 15, 2008, interest on the loan will be waived.

On April 8, 2008, Sphere assigned all of its interests in the Guercif participation agreement and the Tselfat farmout and option agreement to Riata in exchange for Riata’s assumption of all of Sphere’s obligations under those agreements. The assignments are subject to government approval.

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 annual report, 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 shares 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

For a discussion of our private placement with Riata and related transactions occurring after December 31, 2007, see Item 7.B. – “Related Party Transactions.”

On March 31, 2008, we announced that we had farmed out our 100% working interest in Blocks 4173 and 4174, two of our exploration licenses in southeastern Turkey, to an oil and gas company with operations in Turkey. In exchange for a 75% interest in the exploration licenses, the Turkish company will drill an exploration well on one of the licenses. We will retain a 25% interest and will be carried through the costs of testing the well. The Turkish company will also become the operator of Blocks 4173 and 4174. Transfer of the interests in the licenses is subject to government regulatory approval.

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 common shares are traded in Canada on the TSX under the symbol “TNP”. Effective January 2, 2008, our common shares trade in Canadian dollars. Prior to that, our common shares traded in U.S. dollars under the symbol “TNP.U”. As of April 30, 2008, we had 53,270,762 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 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, 2003 through December 31, 2007 on the TSX are as follows:


	High($US)		Low($US)
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
January 1, 2007 through December 31, 2007	$	0.99	$	0.25

The high and low prices for our common shares for each quarter from January 1, 2006 through March 31, 2008 on the TSX are as follows:


	High($US)		Low($US)
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
October 1, 2007 through December 31, 2007	$	0.33	$	0.255

	High ($CDN)		Low ($CDN)
January 1, 2008 through March 31, 2008	$	0.37	$	0.26

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)
November 1, 2007 through November 30, 2007	$	0.33	$	0.27
December 1, 2007 through December 31, 2007	$	0.33	$	0.265

	High ($CDN)		Low ($CDN)
January 1, 2008 through January 31, 2008	$	0.37	$	0.27
February 1, 2008 through February 29, 2008	$	0.285	$	0.26


	High ($CDN)		Low ($CDN)
March 1, 2008 through March 31, 2008	$	0.33	$	0.26
April 1, 2008 through April 30, 2008	$	0.69	$	0.29

D.	Selling Shareholders

Not Applicable.

E.	Dilution

Not Applicable.

F.	Expenses of the Issue

Not Applicable.

Item 10.

Additional Information

A.	Share Capital

Not Applicable.

B.	Articles of Incorporation and Bylaws

The Business Act 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 Business Act, our articles nor our bylaws require an independent quorum to enable the directors to vote compensation to themselves or any of their members.

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

We have one class of common shares, without any special rights or restrictions. We are also authorized to issue preferred shares in series, none of which have been issued. 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. 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, subject to any preferences accorded to holders of preferred shares. 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 bylaws, 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, subject to any preferences accorded to holders of preferred shares. 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.

The preferred shares are issuable in series and each series of preferred shares will have such designations, rights, privileges, restrictions and conditions as our Board of Directors may from time to time determine before issuance. The holders of each series of preferred shares will be entitled, in priority to holders of common shares, to be paid ratably with holders of each other series of preferred shares the amount of accumulated dividends, if any, specified as being payable preferentially to the holders of such series and, upon liquidation, dissolution or winding up of our company, in priority to holders of common shares, to be paid ratably with holders of each other series of preferred shares the amount, if any, specified as being payable preferentially to holders of such series. Like common shares, all preferred shares must be fully paid for prior to issue.

Under the Business Act, the amendment of certain rights attaching to the common shares or the preferred shares requires the shareholders in certain circumstances voting as separate classes or series 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 Business 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 shareholders 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 shares carrying voting rights at the meeting. 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 Act 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 Act, an annual shareholder meeting shall be held not later than 15 months after the holding of the last preceding annual meeting. The Board of Directors 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 Act on the right of a non-resident to hold shares in a corporation incorporated under the Business Act.

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

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

C.	Material Contracts and Agreements

Employment Agreements. We entered into an employment agreement with Mr. Larsen, our President and Chief Executive Officer, effective July 1, 2005. The agreement expires upon the death, disability, resignation or other termination of employment of Mr. Larsen. This agreement provides for an annual base salary to Mr. Larsen as approved by our Board of Directors, initially at the rate of $240,000 per year. The agreement also provides for Mr. Larsen’s participation in the Option Plan and other benefits made available to our executives resident in the United States. 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” or (2) by Mr. Larsen within sixty days of an event that constitutes “constructive dismissal”, 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” 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.

A “constructive dismissal” is defined in the employment agreement as the occurrence of a material diminution in title and/or duties, responsibilities or authority or the implementation of a requirement that Mr. Larsen relocate from his present city of residence, not including: (i) a change consistent with our splitting a position into one or more positions in conjunction with a corporate reorganization based on the demands of such position so long as there is no reduction in his annual salary or other remuneration or responsibilities taken as a whole; (ii) a change in Mr. Larsen’s position, duties or title with any of our subsidiaries, affiliates or associates; or (iii) the occurrence of any of the aforesaid events with the consent of Mr. Larsen or termination of the employment of Mr. Larsen for just cause, death or disability; or (iv) having the positions of Chief Executive Officer and President held by two different individuals so long as Mr. Larsen occupies one or the other position.

Participating Interest Agreement. On July 11, 2005, we entered into an agreement with Mr. Larsen (the “Participating Interest Agreement”) 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”). Under the Participating Interest Agreement, Mr. Larsen will receive 3.87% of any Compensation we receive we receive, subject to certain terms and conditions, but provided that in no event will Mr. Larsen receive more than $600,000 of the Compensation.

Amended and Restated Stock Option Plan (2006). Our only equity compensation plan is the Option Plan, which was approved and adopted by our shareholders on May 4, 2006. 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 of Directors at the time the option is granted. Our Board of Directors 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 of Directors 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 TSX, 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 TSX 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 of Directors 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 5% 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 of our insiders within a one-year period cannot exceed 5% of the Outstanding Issue. In addition, (1) the maximum aggregate number of common shares which can be reserved for issuance to insiders is limited to 10% of the Outstanding Issue and (2) the maximum aggregate number of common shares which can be issued to insiders, within a one-year period, is limited to 10% of the Outstanding Issue.

Stock options granted under the Option Plan are not assignable. We do not provide financial assistance to facilitate the purchase of common shares on exercise of stock options. The Option Plan is a fixed maximum percentage plan pursuant to which the maximum number of our common shares which can be reserved for issuance pursuant to stock options is equal to 10% of the number of issued and outstanding common shares on the date of grant of any stock option. Since the Option Plan is a fixed percentage plan rather than a fixed number plan, the Option Plan allows the reloading of common shares authorized for issuance upon the exercise or cancellation of stock options granted under the Option Plan up to the 10% maximum percentage amount. Because our Option Plan is a fixed maximum percentage plan, it must be approved every three years by both our Board of Directors 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 of Directors and our shareholders. The Option Plan sets forth the types of amendments that can be made by our Board of Directors 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 million 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 on the TSX 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.

Investment Agreement. On March 28, 2008, TransAtlantic entered into the Investment Agreement with Riata pursuant to which Riata will invest in us in a two-stage non-brokered private placement. In the first stage of the private placement, which closed on April 8, 2008, we issued 10 million common shares to an entity associated with Riata at Cdn $0.30 per share generating gross proceeds of Cdn $3 million to us and net proceeds of Cdn $2.9 million, and N. Malone Mitchell, 3^rd, the President of Riata, was appointed to our Board of Directors.

In the second stage of the private placement, which is subject to disinterested shareholder approval, we will issue 25 million common shares to Riata or certain associated persons at Cdn $0.36 per share generating gross proceeds of Cdn $9 million. If shareholder approval is obtained, this second stage is expected to close following the Shareholder Meeting. Riata will also nominate a second director to our Board of Directors at the Shareholder Meeting which will expand the Board of Directors to six directors. Following the closing of the second stage of the private placement, we will have 78,270,762 shares outstanding, of which Riata and its associated persons will own 44.7%.

The net proceeds of both stages of the private placements will be used to fund drilling activities in Romania, to repay the Riata short-term loan as described below and for general corporate purposes.

Credit Agreement. In April 2007, we entered into a $3 million short-term loan from Quest. We mortgaged certain of our assets, including the South Gillock property, and pledged 100% of the common shares of our wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. On August 10, 2007, we and Quest increased the loan facility to $4 million, and we drew down the additional $1 million on the loan. On November 13, 2007, we paid down $2 million in principal on the loan in connection with the sale of our South Gillock property, and we and Quest extended the maturity date on the outstanding principal balance of $2 million to March 31, 2008. We and Quest further extended the maturity date to April 30, 2008 in order to facilitate the transactions with Riata. We paid off the Quest loan on April 8, 2008.

On April 8, 2008, we entered into a $2 million short-term loan agreement with Riata. We used the proceeds of that loan to repay the $2 million loan due to Quest. The new Riata loan bears interest at 12% and is secured by guarantees from our first and second tier subsidiaries. Interest and principal are due on June 30, 2008; provided, that if we repay the Riata loan out of the proceeds from the second stage of the private placement before June 15, 2008, interest on the loan will be waived.

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 non-resident holders of our common shares. However, any such remittance to a non-corporate resident of the United States may be subject to a 15% withholding tax pursuant to Article XI of the reciprocal tax treaty between Canada and the United States.

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

E.	Taxation

The following paragraphs set forth certain U.S. and Canadian federal income tax considerations in connection with the payment of dividends on and purchase or sale of our shares of common shares. 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 shares.

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 U.S. Treasury regulations and rulings and judicial decisions as of the date hereof, all of which are subject to change, possibly with retroactive effect. 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 U.S. 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 shares in carrying on a business in Canada.

The payment of cash dividends and stock dividends on the shares of our common shares 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% for a holder that was entitled to the benefits of the Convention.

Neither Canada nor any province thereof currently imposes any estate taxes or succession duties. Provided a holder of shares of our common shares 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 shares, the disposition (or deemed disposition arising on death) of such shares of common shares will not be subject to the capital gains provisions of the Tax Act. Even if a holder exceeds the 25% ownership threshold, a holder would be exempt from Canadian taxation on such a capital gain pursuant to the Convention, provided that the holder is entitled to the benefits of the Convention and we do not derive our value principally from real property in Canada.

United States Federal Income Tax Considerations. The following discussion is addressed to U.S. holders. As used in this section, the term “U.S. holder” means a holder of our common shares that is for U.S. 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 U.S. 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 U.S. persons (as defined in the Code) have the authority to control all substantial decisions of the trust, or a trust that was in existence on August 20, 1996, and validly elected to continue to be treated as a U.S. person. This discussion deals only with the holders that hold their common shares as capital assets within the meaning of Section 1221 of the Code. The discussion does not address all aspects of U.S. federal income taxation that may be relevant to U.S. holders in light of their particular circumstances, nor does it address the U.S. federal income tax consequences to U.S. 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 shares 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 shares other than as a capital asset. In addition, this discussion is based on the assumption that we will not be classified as a controlled foreign corporation for U.S. federal income tax purposes. If this assumption ever turns out to be incorrect, the U.S. federal income tax consequences to certain of our U.S. holders will be significantly different from those set forth herein.

Dividends. Subject to the discussion of the “passive foreign investment company” rules below, a U.S. holder owning shares of common shares must generally treat the gross amount of dividends paid by us to the extent of our current and accumulated earnings and profits without reduction for the amount of Canadian withholding tax, as dividend income for U.S. 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 shares (but not below zero), then as capital gain. The dividends generally will not be eligible for the “dividends received” deduction allowed to U.S. 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 U.S. 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 gross income bears to our total worldwide gross income.

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%. Notwithstanding the foregoing, if we constitute a “passive foreign investment company,” as discussed below, we will not meet the definition of “qualified foreign corporation.” As a consequence, dividends paid by us will not be eligible to be taxed at the preferential rates.

Sale or Exchange of Common Shares. Subject to the discussion of the “passive foreign investment company” rules below, the sale of a share of our common shares generally results in the recognition of gain or loss to the U.S. holder in an amount equal to the difference between the amount realized and the U.S. 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 U.S. holder on the sale or other disposition of our common shares will generally be treated as U.S. source income.

Foreign Tax Credit. Subject to the limitations set forth in the Code, as modified by the Convention, a U.S. 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 shares. Holders of our common shares and prospective U.S. holders of our common shares 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. U.S. holders of our common shares and prospective U.S. holders of our common shares should consult their own tax advisors to determine whether and to what extent they would be entitled to such credit.

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 shares that are paid within the United States (and, in some cases, outside the United States) to certain U.S. holders. Certain U.S. holders may be subject to backup withholding at the rate of 28% on dividends paid and/or the proceeds of a sale or exchange of our common shares. Generally, backup withholding will apply to a U.S. holder only when the U.S. holder fails to furnish us with or to certify to us the U.S. holder’s proper U.S. tax identification number, we are informed by the Internal Revenue Service of the United States (the “IRS”) that the U.S. holder has failed to report payments of interest and dividends properly or the U.S. holder otherwise fails to establish an exemption from backup withholding. U.S. holders should consult their own tax advisors regarding the qualification for exemption from backup withholding and information reporting and the procedure for obtaining any applicable exemption.

Passive Foreign Investment Company Considerations. Special rules apply to U.S. 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.

Although it is not entirely free from doubt, we believe that it is more likely than not that we will be classified as a PFIC for the current taxable year and may continue to be classified as such for future taxable years. U.S. holders and prospective U.S. holders are urged to consult with their own tax advisors with respect to the application of the PFIC rules to them.

If we constitute a PFIC, a U.S. 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 shares, unless such U.S. holder timely makes one of two elections. First, if a U.S. holder makes a timely election to treat us as a qualified electing fund (“QEF”) with respect to such holder’s interest in common shares, the electing U.S. holder will 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 U.S. 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 U.S. federal income tax return for such taxable year. However, Treasury regulations provide that a U.S. 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. Because we believe it is likely that we constitute a PFIC, we intend to comply with all

record-keeping, reporting and other requirements so that U.S. holders, at their option, may maintain a QEF election with respect to us. However, if meeting those record-keeping and reporting requirements becomes onerous, or we no longer believe we constitute a PFIC, we may decide, in our sole discretion, that such compliance is impractical, and will notify U.S. holders accordingly.

As an alternative to the QEF election, U.S. holders may elect to mark their common shares to its market value (a “mark-to-market election”). If a valid mark-to-market election is made, the electing U.S. holder generally will recognize ordinary income for the taxable year in an amount equal to the excess, if any, of the fair market value of the holder’s common shares as of the close of such taxable year over the U.S. holder’s adjusted tax basis in the common shares. In addition, the U.S. holder generally will be allowed a deduction for the lesser of (1) the excess, if any, of the U.S. holder’s adjusted tax basis in the common shares over the fair market value of the common shares as of the close of the taxable year, or (2) the excess, if any of (A) the mark-to-market gains for the common shares included in gross income by the U.S. holder for prior taxable years, over (B) the mark-to-market losses for common shares that were allowed as deductions for prior taxable years.

If we constitute a PFIC, a U.S. holder who beneficially owns shares of our common shares will be required to file an annual return on IRS Form 8621 with the IRS that describes any distributions received from us and any gain realized by that U.S. holder on the disposition of the holder’s shares of our common stock.

The PFIC rules are complex. Accordingly, U.S. holders and prospective U.S. holders of our common shares 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 shares.

F.	Dividends and Paying Agents

Not Applicable.

G.	Statement of Experts

Not Applicable.

H.	Documents on Display

Documents concerning us which are referred to in this annual report may be inspected in our offices at 5910 N. Central Expressway, Suite 1755, Dallas, Texas 75206 during normal business hours. Copies of our continuous disclosure documents may also be viewed at www.sedar.com and on the SEC website at www.sec.gov.

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 equity securities in one company as a result of a previous business transaction. We have revalued these securities at their estimable market value of $0.

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 crude oil, foreign currency exchange rates, or interest rates will cause the value of a financial instrument to decrease or become more costly to settle. As of December 31, 2007, we were 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 crude 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 crude oil and natural gas prices include the level of global demand for crude oil, the foreign supply of crude 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 crude oil and natural gas prices with any degree of certainty. Sustained weakness in crude oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of crude oil and natural gas reserves that we can produce economically. In the event that we establish crude oil and natural gas reserves, any reduction in those reserves, including reductions due to price fluctuations, could have an adverse affect on our ability to obtain capital for our development activities. Similarly, any improvements in crude oil and natural gas prices could have a favorable impact on our financial condition, results of operations and capital resources. Based on year-end 2007 production levels, if 2007 average natural gas prices were to change by $0.50 per Mcf, the impact on our earnings and cash flow would have been approximately $21,000; if the 2007 average oil prices were to change by $1.00 per bbl, the impact on our earnings and cash flow would have been approximately $6,000.

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 2007 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 $65,000 (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 and our fixed-rate short-term loan. At December 31, 2007, we had approximately $4 million invested in money market funds and certificates of deposit which bear interest at floating rates. If average interest rates for 2007 were to change by one full percentage point, the net impact on our earnings and cash flow for 2007 would have been approximately $68,000.

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


	Estimated 2007 impact on:
Sensitivities	Earnings		Cash Flow
Natural gas – U.S. $0.50/Mcf change	$	20,705	$	20,705
Crude oil – U.S. $1.00/bbl change	$	6,079	$	6,079
Foreign exchange – 10% change in the F/X Canadian to U.S. $	$	64,984	$	64,984
Interest rate - 1% change (money markets only)	$	67,615	$	67,615

Item 12.

Description of Securities Other than Equity Securities

Not applicable.

PART II.

Item 13.

Defaults, Dividend Arrearages and Delinquencies

None.

Item 14.

Material Modifications to the Rights of Security Holders and Use of Proceeds

None.

Item 15.

Controls and Procedures

As required by Rule 13a-15 under the Exchange Act, our management carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2007, the end of the period covered by this report. This evaluation was carried out under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed on our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

During our most recently completed fiscal year ended December 31, 2007, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.

Item 16.

[Reserved]

Item 16A.

Audit Committee Financial Expert

Our Audit Committee is comprised of Brian Bayley, Alan Moon and Michael Winn, all of whom are financially literate. Our Board of Directors has determined that each of the members of the Audit Committee is independent, as defined in the listing standards of the American Stock Exchange, and that Mr. Bayley is an “audit committee financial expert,” in accordance with SEC rules.

Item 16B.

Code of Ethics

We have adopted a code of ethics that applies to our Chief Executive Officer and Chief Financial Officer, as well as to all other employees. The full text of our code of ethics is available on our website at www.tapcor.com.

Item 16C.

Principal Accountant Fees and Services

KPMG LLP has been our external auditors since 1993. Our Audit Committee must approve all audit and non-audit related fees. The Audit Committee has pre-approved certain tax fees and other fees from time to time.


Principal Accountant Services (in Cdn $)	Fiscal year ending December 31, 2007		Fiscal year ending December 31, 2006
Audit Fees⁽¹⁾	$	129,235	$	105,000
Audit Related Fees⁽²⁾	$	123,850	$	77,750
Tax Fees⁽³⁾	$	22,737	$	13,385
All Other Fees⁽⁴⁾	$	—	$	—

⁽¹⁾	“Audit Fees” include fees necessary to perform the annual audit of our consolidated financial statements.

⁽²⁾	“Audit Related Fees” include fees necessary to perform quarterly reviews of our consolidated interim financial statements. Audit Related Fees also include audit or other attest services required by legislation or regulation, such as consents and reviews of securities filings.

⁽³⁾	“Tax Fees” include fees for all tax services, including tax compliance, tax planning and tax advice.

⁽⁴⁾	“All Other Fees” include fees for all other non-audit services.

Item 16D.

Exemptions from the Listing Standards for Audit Committees

None.

Item 16E.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

PART III.

Item 17.

Financial Statements


Management’s Report		F-1
Report of Independent Registered Public Accounting Firm		F-2
Comments by Auditors for US Readers on Canada – US Reporting Differences		F-3
Consolidated Balance Sheets as at December 31, 2007 and December 31, 2006		F-4
Consolidated Statements of Operations, Comprehensive Loss and Deficit for the Years Ended December 31, 2007 and December 31, 2006		F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007 and December 31, 2006		F-6
Notes to Consolidated Financial Statements		F-7

Item 18.

Financial Statements

Not Applicable.

Item 19.

Exhibits

See Exhibit Index.

Consolidated Financial Statements of

TRANSATLANTIC PETROLEUM CORP.

Years ended December 31, 2007 and 2006

MANAGEMENT’S REPORT

Management has prepared the consolidated financial statements in accordance with accounting principles generally accepted in Canada. If alternative methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise since they include certain amounts based on estimates and judgments. Management has ensured that the consolidated financial statements are presented fairly in all material respects. Management has also prepared the financial information presented in Management’s Discussion and Analysis and ensured that it is consistent with information in the consolidated financial statements.

TransAtlantic Petroleum Corp. maintains internal accounting and administrative controls designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that assets are appropriately accounted for and adequately safeguarded.

The Board of Directors is responsible for reviewing and approving the consolidated financial statements and Management’s Discussion and Analysis and, primarily through its Audit Committee, ensures that management fulfills its responsibilities for financial reporting.

The Audit Committee is appointed by the Board of Directors and is composed of non-management Directors. The Audit Committee has met with management and with the external auditors to discuss internal controls and reporting issues and to satisfy itself that management’s responsibilities are properly discharged. It reviews the consolidated financial statements and the external auditors’ report. The Audit Committee also considers, for review by the Board of Directors and approval by shareholders, the engagement or reappointment of external auditors.

KPMG LLP, the external auditor, has audited the consolidated financial statements in accordance with the auditing standards generally accepted in Canada on behalf of the shareholders. KPMG LLP has full and free access to the Audit Committee.



/s/ Scott C. Larsen				/s/ Hilda Kouvelis
Scott C. Larsen President and Chief Executive Officer				Hilda Kouvelis Vice President and Chief Financial Officer

May 14, 2008

F-1

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”) as at December 31, 2007 and 2006 and the consolidated statements of operations, comprehensive loss and deficit and cash flows for each of the years in the three-year period ended December 31, 2007. 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 consolidated 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 as at December 31, 2007 and 2006 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007 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 18 to the consolidated financial statements.

Chartered Accountants

Calgary, Canada

March 31, 2008, except for notes 1, 8, 17 and 18, which are as of May 14, 2008

F-2

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 March 31, 2008, except for notes 1, 8, 17 and 18, which are as of May 14, 2008, 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.

“KPMG LLP”

Chartered Accountants

Calgary, Canada

March 31, 2008, except for notes 1, 8, 17 and 18, which are as of May 14, 2008

F-3

TRANSATLANTIC PETROLEUM CORP.

Consolidated Balance Sheets

As at December 31, 2007 and 2006

(Thousands of U.S. Dollars)


	2007			2006
Assets
Current assets
Cash and cash equivalents	$	2,224		$	4,688
Accounts receivable		566			422
Prepaid and other current assets		45			84

		2,835			5,194
Restricted cash (notes 4, 14 and 15)		2,272			4,339
Property and equipment (note 6)		1,572			1,572
Assets held for sale (note 5)		—			4,287

	$	6,679		$	15,392

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	789		$	1,990
Loan payable (note 8)		2,000			—
Asset retirement obligations of assets held for sale (notes 5 and 7)		8			—
Settlement provision (note 14)		240			961

		3,037			2,951
Asset retirement obligations of assets held for sale (note 5)		—			1,939
Shareholders’ equity
Share capital (note 9)		23,788			23,164
Warrants (note 9)		1,108			2,017
Contributed surplus (note 9)		5,646			4,284
Deficit		(26,900	)		(18,963	)

		3,642			10,502
Going concern (note 1)
Commitments (notes 14 and 15)
Subsequent events (notes 1, 5, 8 and 17)

	$	6,679		$	15,392

See accompanying notes to consolidated financial statements.


Approved by the Board of Directors:

“Brian Bayley”		Director

“Michael Winn”		Director

F-4

TRANSATLANTIC PETROLEUM CORP.

Consolidated Statements of Operations, Comprehensive Loss and Deficit

Years ended December 31, 2007, 2006 and 2005

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


	2007			2006			2005
Expenses
General and administrative	$	2,673		$	2,441		$	2,295
International oil and gas activities (note 6)		2,312			2,279			440
Settlement provision (note 14)		(313	)		—			905
Foreign exchange loss		45			59			29
Write down of investment (note 16)		—			157			112
Gain on sale of marketable securities (note 6)		—			(118	)		–
Gain on sale of subsidiary (note 6)		—			—			(180	)
Loss on sale of investment (note 16)		—			400			—

		4,717			5,218			3,601
Interest expense and financing expense		62			—			—
Interest and other income		(240	)		(545	)		(943	)

Loss from continuing operations		4,539			4,673			2,658
Loss from discontinued operations (note 5)		3,398			4,740			1,115

Net loss and comprehensive loss for the year		7,937			9,413			3,773
Deficit, beginning of year		18,963			9,550			5,777

Deficit, end of year	$	26,900		$	18,963		$	9,550

Net loss per share (note 9)
Basic and diluted – continuing operations	$	0.11		$	0.12		$	0.08
Basic and diluted – discontinued operations	$	0.08		$	0.12		$	0.03
Basic and diluted	$	0.18		$	0.25		$	0.11

See accompanying notes to consolidated financial statements.

F-5

TRANSATLANTIC PETROLEUM CORP.

Consolidated Statements of Cash Flows

Years ended December 31, 2007, 2006 and 2005

(Thousands of U.S. Dollars)


	2007			2006			2005
Cash provided by (used in)
Operating activities
Loss from continuing operations	$	(4,539	)	$	(4,673	)	$	(2,658	)
Items not involving cash
Gain on sale of marketable securities		—			(118	)		—
Gain on sale of subsidiary		—			—			(180	)
Loss on sale of investment		—			400			—
Write-down of investment		—			157			112
Stock-based compensation		554			260			410

		(3,985	)		(3,974	)		(2,316	)
Changes in non-cash working capital (note 13)		(2,027	)		798			1,022

		(6,012	)		(3,176	)		(1,294	)

Discontinued operations held for sale
Net loss from discontinued operations (note 5)		(3,398	)		(4,740	)		(1,115	)
Items not involving cash
Non-cash financing expense		359			—			—
Write-down of assets held for sale		1,867			3,061			—
Depreciation, depletion and accretion		351			1,513			606

		(821	)		(166	)		(509	)

		(6,833	)		(3,342	)		(1,803	)
Investing activities
Cash used in discontinued operations related to investment activities		(4,126	)		(4,737	)		(4,839	)
Marketable securities		—			210			—
Proceeds on sale of subsidiary		—			—			180
Marketable securities		—			—			(268	)
Investments		—			—			104
Proceeds from sale of assets		4,264			2000			—
Redemption of short-term investments		—			1,500			—
Restricted cash		2,067			(2,229	)		356

		2,205			(3,256	)		(4,467	)
Financing activities
Exercise of warrants and options		164			222			—
Issuance of common shares, net		—			3,497			4,187
Loan proceeds (note 8)		4,000			—			—
Loan repayment (note 8)		(2,000	)		—			—

		2,164			3,719			4,187
Change in cash and cash equivalents		(2,464	)		(2,879	)		(2,083	)
Cash and cash equivalents, beginning of year		4,688			7,567			9,650

Cash and cash equivalents, end of year	$	2,224		$	4,688		$	7,567

Supplemental cash flow information
Interest received	$	240		$	305		$	943
Interest paid		349			64			—

See accompanying notes to consolidated financial statements.

F-6

TRANSATLANTIC PETROLEUM CORP.

Notes to Consolidated Financial Statements

Years ended December 31, 2007 and 2006

(Tabular amounts in Thousands 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, 2007, the Company had cash and cash equivalents of $2.2 million, $2.0 million in current debt, no long term debt and a working capital deficit of $202,000. The Company incurred losses during the year ended December 31, 2007 of approximately $7.9 million. The loan payable was due on April 30, 2008 (see note 8). In addition, the Company has commitments relating to work commitments (see notes 6 and 15).

On March 28, 2008, the Company announced the formation of a strategic relationship with Riata Management, LLC (“Riata”) and its affiliates (see note 17). The arrangements with Riata include a two-stage equity investment in the Company, replacing the current partner as the farm-in partner in both of the Company’s Moroccan properties, providing a short-term credit facility to the Company to repay the bridge loan with Quest Capital Corp. (“Quest”) and providing technical and management expertise to assist the Company in successfully developing and expanding its international portfolio of projects. The equity investments into the Company are subject to regulatory and disinterested shareholder approval.

If the second stage of the Riata transaction does not close, the Company does not have sufficient capital to fund its international development activities past June 2008.

The Company will continue to evaluate farmout arrangements, the sale of certain non-core properties, and additional financings as options for additional sources of capital.

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.

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)

Joint interest activities

Many of the Company’s exploration, development and production activities are conducted jointly with other entities and accordingly the consolidated financial statements reflect only the Company’s proportionate interest in such activities.

F-7

(b)

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. The cash flows are estimated using the future product prices and costs and are discounted using a risk-free rate.

Under the full cost method of accounting, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves in cost centers on a country-by-country basis. Costs associated with production and general corporate activities are expensed in the period incurred. 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.

(c)

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 significant difference is recognized as a gain or loss to earnings in the period in which the settlement occurs.

(d)

Revenue recognition

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

(e)

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.

(f)

Stock-based compensation

The Company uses the fair value method when stock options are granted to employees, consultants 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. Options granted to consultants, to the extent unvested, are fair valued on subsequent reporting dates. 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-8

(g)

Income taxes

The Company uses the asset and liability method of accounting for future income taxes. Under this 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.

(h)

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.

(i)

Cash and cash equivalents

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

3.	Accounting pronouncements

Pending accounting pronouncements

(a)

Capital Disclosures and Financial Instruments – Disclosures and Presentation

On December 1, 2006 three new accounting standards were issued by the Canadian Institute of Chartered Accountants (the “CICA”). These were Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments – Disclosure, and Handbook Section 3863, Financial Instruments – Presentation. These new standards became effective on January 1, 2008.

Section 1535 specifies the disclosure of (i) an entity’s objectives, policies, and processes for managing capital, (ii) quantitative data about what the entity regards as capital, (iii) whether the entity has complied with any capital requirements, and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments – Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. The Company is currently assessing the impact of these new standards upon its financial statements.

(b)

Inventories

In March 2007, Handbook Section 3031, Inventories, was adopted which aligns Canadian generally accepted accounting principles (“GAAP”) with International Financial Reporting Standards (“IFRS”) was issued by the CICA. This standard became effective on January 1, 2008. This standard will not have a material impact upon the Company’s financial statements.

(c)

International Financial Reporting Standards

In 2005, the Accounting Standards Board of Canada (“AcSB”) announced that accounting standards in Canada are to converge with IFRS. The AcSB has indicated that Canadian entities will need to begin reporting under IFRS by

F-9

the first quarter of 2011 with appropriate comparative data from the prior year. Under IFRS, the primary audience is capital markets and as a result, there is significantly more disclosure required, specifically for quarterly reporting. Further, while IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policy which must be addressed, including differences in accounting for oil and gas properties.

The Company is currently assessing the impact of these new standards on its financial statements.

Changes in accounting policies

(a)

Handbook Section 3855, Financial Instruments – Recognition and Measurement sets out the criteria for the recognition and measurement of financial instruments commencing January 1, 2007. This standard requires all financial instruments within its scope, including derivatives, to be included on the balance sheet and measured either at fair value or, in certain circumstances when fair value may not be considered most relevant, at cost or amortized cost. Changes in fair value are to be recognized in the statements of operations or other comprehensive income.

All financial assets and liabilities are recognized when the entity becomes a party to the contract creating the item. As such, any of the Company’s financial assets and liabilities at the effective date of adoption are recognized and measured in accordance with the new requirements as if these requirements had always been in effect. Any changes to the fair value of assets and liabilities prior to January 1, 2007 are recognized by adjusting opening deficit or opening accumulated other comprehensive income.

All financial instruments are classified into one of the following five categories: held-to-maturity, loans and receivables, and other financial liabilities, available-for-sale financial assets, and held-for-trading. Initial and subsequent measurement and recognition of changes in the value of financial instruments depends on their initial classification.

Held-to-maturity investments, loans and receivables, and other financial liabilities are initially measured at fair value and subsequently measured at amortized cost. Amortization of premiums or discounts and losses due to impairment are included in current period net earnings.

Available-for-sale financial assets are measured at fair value. Revaluation gains and losses are included in other comprehensive income until the asset is removed from the balance sheet.

Held-for-trading financial instruments are measured at fair value. All gains and losses are included in net earnings in the period in which they arise.

All derivative financial instruments are classified as held for trading financial instruments and are measured at fair value, even when they are part of a hedging relationship. All gains and losses are included in net earnings in the period to which they relate.

Upon adoption of these new standards, the Company designated its accounts receivable as loans and receivables, which are measured at amortized cost. Debt, accounts payable and accrued liabilities are classified as other financial liabilities which are also measured at amortized cost. The Company had no available-for-sale assets, or held-for-trading instruments.

Prior to adoption of the new standards, physical receipt and delivery contracts were not within the scope of the definition of a financial instrument. On adoption of the new standards, the Company elected to continue to account for any commodity sales contracts and other non-financial contracts on an accrual basis rather than as non-financial derivatives. The Company had no physical receipt or delivery contracts outstanding.

Derivatives embedded in other financial instruments must be separated and fair valued as separate derivatives under the new standard. The Company has not identified any embedded derivatives in any of its instruments.

(b)

Handbook Section 3865, Hedging, specifies the circumstances under which hedge accounting is permissible and how hedge accounting may be performed. On adoption of these standards, the Company did not have any agreements or contracts which are following hedge accounting.

F-10

(c)

Handbook Section 1530, Comprehensive Income, requires certain gains and losses that would otherwise be recorded as part of net earnings to be presented in “other comprehensive income or loss” until it is considered appropriate to recognize into net earnings. Comprehensive income is the change in shareholders’ equity during a period from transactions and other events from non-owner sources. This standard requires the presentation of comprehensive income, and its components in a separate financial statement that is displayed with the same prominence as the other financial statements. The Company had no “other comprehensive income or loss” transactions during the year ended December 31, 2007 and no opening or closing balances for accumulated other comprehensive income or loss.

4.	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, 2007, restricted cash includes: $240,000 in respect of the settlement of Nigerian liabilities (see note 14), $2.0 million in a certificate of deposit supporting a $2.0 million bank guarantee of the Morocco work program (see note 15) and $27,000 relating to the certificate of deposit that is a collateral for a letter of credit in favor of the Oklahoma Tax Commission.

5.	Discontinued operations and assets held for sale


	Cost		Accumulated depreciation, depletion and write-down		Net book value
2007
Crude oil and natural gas properties United States	$	11,053	$	11,053	$	—
2006
Crude oil and natural gas properties United States	$	11,164	$	6,877	$	4,287

The Company has segregated its U.S oil and gas properties as held for sale in conjunction with its plan to sell its proved and undeveloped interests in the United States. At December 31, 2007, the assets of the discontinued operations were measured at their fair value less costs to sell. The Company recorded a write-down in 2007 of approximately $1.9 million. As such, $0 net book value of property and equipment and $8,000 of asset retirement obligations have been reflected as assets held for sale as at December 31, 2007 as predominantly all of the Company’s U.S. operations have been disposed of. 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.

On November 12, 2007, the Company sold its 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 addition, the Company sold the Jarvis Dome property in October 2007 for $250,000.

Loss from discontinued operations includes the following amounts:


	Years ended December 31,
	2007		2006		2005
Revenues, oil and gas sales – net	$	653	$	1,613	$	1,409

Expenses:
Lease operating expenses		1,167		1,779		1,918
Depletion, depreciation and accretion		351		1,513		606
Interest expense		307		—		—
Financing expense - shares issued (note 9)		359		—		—
Write-down of assets		1,867		3,061		—

Loss from discontinued operations	$	3,398	$	4,740	$	1,115

F-11

6.	Property and equipment


	Cost		Accumulated depreciation and depletion		Net book value
2007
Crude oil and natural gas properties Romania	$	1,572	$	—	$	1,572
Furniture, fixtures and other assets		238		238		—

Balance, December 31, 2007	$	1,810	$	238	$	1,572

2006
Crude oil and natural gas properties Romania	$	1,572	$	—	$	1,572
Furniture, fixtures and other assets		238		238		—

Balance, December 31, 2006	$	1,810	$	238	$	1,572

(a)

Morocco:

In August 2007, the Company reached an agreement to farmout 50% of its interest in the Tselfat exploration permit to Sphere Petroleum QSC (“Sphere”). In exchange for an option to acquire 50% of the Company’s interest in the Tselfat permit, Sphere agreed to fund the costs of a 3D seismic survey over the Haricha field and northern portion of the Bou Draa field and also fund the cost of additional geological studies. The 3D seismic survey and the studies will be conducted in 2008 at an estimated cost of $6.5 million. Upon its exercise of the option, Sphere committed to (i) fund the drilling and testing of an exploratory well; and (ii) replace the Company’s bank guarantee deposited with the Moroccan government.

Effective January 2008, the Company converted a portion of its Guercif - Beni Znassen reconnaissance license into two exploration permits in the Guercif area in northeastern Morocco. Pursuant to a participation agreement between the Company (30%), Stratic Energy Corporation (“Stratic”) (20%) and Sphere (50%), Sphere agreed to bear the entire cost of the initial three-year work program to earn its 50% interest in the two Guercif exploration permits. The interests of the Company, Sphere and Stratic are subject to the 25% interest in the Guercif exploration permits held by the national oil company of Morocco, which is carried during the exploration phase but pays its share of costs in the development phase. In addition, Sphere agreed to reimburse the Company and Stratic their back costs.

(b)

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 December 31, 2007. In September 2007, the Company received final approval from the Romanian government for the three production licenses in Romania previously awarded to the Company.

(c)

Other countries:

During the year ended December 31, 2007, the Company continued to evaluate and expand its initiatives in Turkey. In August 2007, the Company was awarded three additional exploration licenses in Turkey that expire in June 2011. The Company relinquished its interest in the U.K. North Sea in December 2007.

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.

F-12

Approximately $2.3 million of costs were incurred and expensed towards the pre-acquisition, reconnaissance and evaluation of the Company’s international oil and gas activities, including those conducted in Morocco and Romania, including technical, professional and administrative costs during the year ended December 31, 2007, compared to $2.3 million and $440,000 during the years ended December 31, 2006 and 2005, respectively.

7.	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, 2007 the net present value of the Company’s total ARO is estimated to be $8,000, compared to $1.9 million at December 31, 2006, with the undiscounted value being $14,000 at December 31, 2007, compared to $2.4 million at December 31, 2006. An inflation rate of 2% was assumed and a discount rate of 7% was used to calculate the present value of the ARO. For reporting purposes, the asset retirement obligations associated with the current assets held for sale (see note 5) have been reclassified as current liabilities.


	Year ended December 31, 2007			Year ended December 31, 2006
Beginning balance, December 31, 2006	$	1,939		$	556
Liabilities incurred		26			86
Accretion expense		72			127
Revision of estimate					1,341
Liabilities sold (note 5)		(2,029	)		(171	)

Ending balance, December 31, 2007	$	8		$	1,939

8.	Loan payable

In April 2007, the Company entered into a $3.0 million short-term standby bridge loan from Quest. Upon entering the arrangement, Quest and the Company had two directors in common, and as at December 31, 2007 they had one director in common. Transactions with Quest have been conducted at their exchange value. The Company mortgaged certain of the Company’s assets, including the South Gillock property, and pledged 100% of the common shares of the Company’s wholly-owned subsidiary, TransAtlantic Petroleum (USA) Corp., as security. At closing, the Company paid Quest a loan fee totaling 132,353 common shares. In addition, the Company paid 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 issued 371,470 common shares to Quest in fees as the Company drew down on the loan. 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 Quest and the Company extended the maturity date on the outstanding principal balance of $2.0 million to March 31, 2008. Quest agreed to extend the maturity date to April 30, 2008 to facilitate the closing of the Riata loan, and the Company paid off the Quest loan on April 8, 2008.

Under its arrangement with Riata (see note 17), Riata loaned the Company $2.0 million, which was used to repay the Quest loan.

9.	Share capital

(a)

Authorized

The Company has an unlimited number of common shares and preferred shares, without par value.

F-13

(b)

Issued

Common shares:


(In thousands)	Number of Shares	Amount
Balance, December 31, 2005	37,659	$	20,476
Private placement of common shares	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
Shares issued for financing (see notes 5 and 8)	504		359
Stock options exercised	185		232
Stock warrants exercised	25		33

Balance, December 31, 2007	43,271	$	23,788

Warrants:


(In thousands)	Number of Warrants		Amount
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
Expired	(3,232	)		(902	)
Exercised	(25	)		(7	)

Balance, December 31, 2007	4,719		$	1,108

(c)

December 2006 private placement

The Company 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. 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 the issuance of the Units, the Company paid a commission of $249,000 and issued 219,375 common share purchase warrants as a finders’ fee 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)

Stock option plan

The Company granted 915,000 stock purchase options on December 4, 2007. All of the options were granted pursuant to the Amended and Restated Stock Option Plan (2006) (the “Plan”) with a five-year term exercisable at $0.31 per share. The options were issued on three different vesting schedules. 165,000 of the options issued vested immediately. As to 600,000 of the options issued, 1/3 vested immediately, 1/3 will vest in one year and 1/3 will vest in two years. As to 150,000 of the options issued, 1/3 vested immediately, 1/3 vested March 31, 2008 and 1/3 will vest December 31, 2008.

F-14

The Company also 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% vested 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 vested in two years.

Based upon these terms, a Black-Scholes pricing model derives a fair value for the grants of approximately $554,000 recognized as stock-based compensation expense for the year ended December 31, 2007 compared to $260,000 for the year ended December 31, 2006 and $410,000 for the year ended December 31, 2005. The unamortized amount at December 31, 2007 is $263,000.

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	2007		2006		2005
Risk free interest rate	4.2	%	4.7	%	5.3	%
Expected option life	5 Years		5 Years		5 Years
Volatility in the price of the Company’s shares	71-172	%	74-77	%	80	%
Forfeiture	10	%	20	%	0	%

The Plan had 42,067 common shares reserved for issuance as at December 31, 2007. All options presently issued under the Plan have a five-year expiry. Details of the Plan as at December 31, 2007 and 2006 are presented below.


	2007					2006
(Shares in thousands)	Number of options		Weighted average exercise price			Number of options		Weighted average exercise price
Outstanding at beginning of year	2,280		$	0.87		2,540		$	0.76
Granted	2,270			0.72		355			1.13
Expired	(80	)		(0.82	)	(335	)		0.72
Exercised	(185	)		(0.74	)	(280	)		0.63

Outstanding at end of year	4,285		$	0.80		2,280		$	0.87

Exercisable at end of year	2,957		$	0.83		2,280		$	0.87

The following table summarizes information about stock options as at December 31, 2007 (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		Number outstanding	Weighted- average remaining contractual life	Weighted- average exercise price		Number exercisable	Weighted - average exercise price
					(years)
$	0.31	$	0.31	915	4.93	$	0.31	415	$	0.31
$	0.75	$	0.99	1,675	1.89	$	0.84	1,675	$	0.84
$	1.00	$	1.20	1,695	3.88	$	1.03	867	$	1.05

				4,285	3.33	$	0.80	2,957	$	0.83

F-15

(e)

Per share amounts

Basic per common share amounts were calculated using a weighted average number of common shares outstanding for 2007 of 43,037,098 (2006 – 38,181,808; 2005 – 33,023,412).

(f)

Contributed surplus


	2007			2006			2005
Beginning balance	$	4,284		$	1,508		$	1,302
Increase from stock based compensation		554			260			410
Transfer to share capital on option exercise		(94	)		(154	)		(204	)
Warrants expired		902			2,670			—

Ending balance	$	5,646		$	4,284		$	1,508

10.

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)	2007			2006			2005
Statutory tax rate		32.12	%		34.5	%		37.62	%
Expected income tax reduction	$	(2,559	)	$	(3,247	)	$	(1,419	)
Increase (decrease) resulting from
Stock-based compensation		178			76			154
Change in enacted tax rates		787			(163	)		—
Expiration of tax deductions		95			1,045			—
Change in valuation allowance		1,674			1,868			1,265
Other		(175	)		421			—

	$	—		$	—		$	—

The components of the net future income tax asset at December 31, 2007 and 2006 are as follows:


(In thousands)	2007			2006
Future income tax liabilities
Property and equipment in excess of tax values	$	—		$	(212	)
Future income tax assets
Property and equipment	$	268		$	—
Operating loss carry-forwards		13,844			9,945
Capital loss carry-forwards		959			845
Share issue costs		112			255
Investments		-			54
Valuation allowance		(15,183	)		(10,887	)

Net future income tax asset	$	—		$	—

F-16

The Company and its wholly-owned subsidiaries have accumulated losses or resource-related deductions available for income tax purposes in Canada and the United States. No recognition has been given in these consolidated financial statements to the future benefits that may result from the utilization of these losses for income tax purposes. The Company has non-capital tax losses in Canada of approximately $2.9 million which expire commencing in 2008 and non-capital tax losses in the United States of approximately $32 million which expire commencing in 2008. The Company has capital tax losses in Canada of approximately $7.7 million which do not expire.

11.

Segment information

As of December 31, 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 for the Company’s continuing operations in each of its geographic areas are as follows:


December 31, 2007	Identifiable assets (liabilities)		Net Revenues		Net Loss
United States	$	190	$	—	$	3,398
Morocco		2,196		—		712
Romania		1,881		—		811
Corporate assets and other		2,412		—		3,016

	$	6,679	$	—	$	7,937


December 31, 2006	Identifiable assets (liabilities)		Net Revenues		Net Loss
United States	$	4,709	$	—	$	4,740
Morocco		3,414		—		859
Romania		1,894		—		605
Corporate assets and other		5,375		—		3,209

	$	15,392	$	—	$	9,413


December 31, 2005	Identifiable assets (liabilities)		Net Revenues		Net Loss
United States	$	11,094	$	—	$	1,115
Morocco		644		9		67
Corporate assets and other		7,189		—		2,591

	$	18,927	$	9	$	3,773

12.

Financial instruments

The fair value of the Company’s financial instruments at December 31, 2007 of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable and accrued liabilities approximate their fair values.

Interest rate risk

The Company is exposed to interest risk as a result of its fixed rate notes and its variable rate short-term cash holdings. Interest rate changes would result in gains or losses in the market value of the Company’s fixed rate debt due to differences between the current market interest rates and the rates governing these instruments.

F-17

Foreign currency risk

The Company has underlying foreign currency exposure. The Company’s currency exposures relate to transactions denominated in the Canadian dollar, British pound, European Union euro, Romanian new lei, Moroccan dirham and Turkish new lira. Foreign currency forward contracts have not been used to manage exchange rate fluctuations because the Company has had limited access to capital.

Credit risk

The Company’s accounts receivable are primarily with customers and partners in the oil and gas industry and government agencies and are subject to normal credit risks.

13.

Supplemental cash flow information

Changes in non-cash working capital are as follows:


	Year ended December 31,
	2007			2006			2005
Accounts receivable	$	(144	)	$	358		$	(298	)
Prepaid and other current assets		39			(76	)		65
Accounts payable and accrued liabilities		(1,201	)		1,066			599
Settlement provision		(721	)		(550	)		656
Change in non-cash working capital related to operating activities	$	(2,027	)	$	798		$	1,022

14.

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 fiscal years 1998 through 2004. In April 2007, $415,000 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.

15.

Commitments

(a)

The Company has work program commitments of $3.0 million under its Guercif exploration permits and $3.0 million under its Tselfat exploration permit in Morocco that are supported by fully-funded bank guarantees. Sphere posted the Guercif bank guarantee. The bank guarantees are reduced periodically based on work performed. In the event the Company fails to perform the required work commitments, the remaining amount of the bank guarantees, currently $2.0 million at each of Guercif and Tselfat, would be forfeited. The Company also had a $120,000 work commitment in 2007 with respect to its Guercif–Beni Znassen reconnaissance license in Morocco, which was supported by a similar bank guarantee. The bank guarantee for Guercif-Beni Znassen was released in August 2007 based on completion of the work.

(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. In 2008, the Company entered into a three-year lease for office space in Morocco.

The Company is committed to the following aggregate annual amounts:


(In Thousands of U.S. Dollars)
2008	$	113
2009		123
2010		130
2011		11

	$	377

F-18

16.

Related party transactions

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 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.

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

(b)

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


(in thousands)	2006			2005
Receipts from ANEC:
Proceeds from oil & gas sales	$	403		$	702
Interest on debentures		60			240
Payments to ANEC:
Drilling advances		—			(423	)
Joint lease operations expenses		(118	)		(356	)

	$	345		$	163

(c)

In December 2006, Quest Capital Corp. provided services in conjunction with the Company’s private placement. Quest Capital Corp. was paid approximately $22,000. The Company and Quest Capital Corp. had 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.

17.

Subsequent events

On March 28, 2008, the Company announced that it has entered into a strategic relationship with Riata. The arrangements with Riata include an equity investment in the Company, replacing Sphere as the farm-in partner in both of the Company’s Moroccan properties, providing a short-term credit facility to the Company to repay the Quest bridge loan and providing technical and management expertise to assist the Company in successfully developing and expanding its international portfolio of projects.

Riata will invest in the Company in a two-stage non-brokered private placement. In the first stage of the private placement, the Company issued 10 million common shares to an entity associated with Riata at Cdn $0.30 per share generating gross proceeds of Cdn $3 million to the Company and net proceeds of Cdn $2.9 million, and Riata nominated one director to the Company’s Board. In the second stage, which is subject to disinterested shareholder approval, the Company will issue 25 million common shares to Riata or certain associated persons at Cdn $0.36 per share generating gross proceeds of Cdn $9 million. If shareholder approval is obtained, the second stage of the private placement is expected to close following the Company’s annual and special shareholder meeting scheduled for May 20, 2008. Riata will also nominate a second director to the Board of Directors at such meeting which will expand the Board to six directors. Following the closing of the second stage of the private placement, the Company will have 78,270,762 shares outstanding, of which Riata and its associated persons will own 44.7%. The net proceeds of both stages of the private placement will be used to fund drilling activities in Romania, to repay the Riata short-term loan as described below and for general corporate purposes.

Upon closing of the initial stage of the private placement, Riata loaned the Company $2 million which the Company used to repay the $2 million loan due to Quest (see note 8). The new Riata loan bears interest at 12% and is secured by guarantees from the Company’s first and second tier subsidiaries. Interest and principal are due on June 30, 2008; provided, that if the Company repays the Riata loan out of the proceeds from the second stage of the private placement before June 15, 2008, interest on the loan will be waived.

On March 31, 2008, the Company announced that it has farmed out its 100% working interest in Blocks 4173 and 4174, two of its exploration licenses in southeastern Turkey, to an oil and gas company with operations in Turkey. In exchange for a 75% interest in the exploration licenses, the Turkish company will drill an exploration well before the end of 2008 to test the Bedinan Ordivician formation on one of the licenses. The Company will retain a 25% interest and will be carried through the costs of testing the well. In addition, the Turkish company will pay $150,000 which will be used by the Company to pay for the reprocessing of 2D seismic over the licenses and completing its ongoing geochemical studies. The Turkish company will also become the operator of Blocks 4173 and 4174. Transfer of the interests in the licenses is subject to government regulatory approval. In addition, the Company announced that the holder of the option on Block 4175 has determined not to exercise the option. The Company plans to continue its geochemical sampling and analysis on Block 4175.

18.

Reconciliation to Accounting Principles Generally Accepted in the United States

The Company’s consolidated financial statements are prepared in accordance with Canadian GAAP. The Company’s accounting policies do not differ materially from U.S. GAAP except for the following:

F-19

(a)

Oil and Gas Properties

Under Canadian GAAP the ceiling test is performed by comparing the carrying value of the cost centre based on the sum of the undiscounted cash flows expected from the cost centre’s use and eventual disposition. If the carrying value is unrecoverable, the cost centre is written down to its fair value using the expected present value approach of proved plus probable reserves using future prices. Under U.S. GAAP, companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and gas reserves using a discount factor of 10 percent. Prices used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable period-end. There was no material difference arising out of the differences in prices. At December 31, 2005, 2006 and 2007, the Company recognized a U.S. GAAP ceiling test write down of $0, $1,311 and $42,880 respectively (all impairment amounts are in thousands of dollars before and after tax). Depletion expense for the years ended December 31, 2005, 2006 and 2007 for U.S. GAAP is reduced by $51, $35 and $111 thousand before and after tax, respectively. In the latter part of 2007 the assets previously written down for U.S. GAAP purposes were sold for amounts exceeding the carrying value under U.S. GAAP for a gain of $4.25 million compared to the U.S. GAAP carrying amount.

(b)

Marketable Securities

Under Canadian GAAP, 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. Prior to 2007, marketable securities were stated at the lower of cost or market. In 2007, Canadian GAAP was conformed with U.S. GAAP.

(c)

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.

(d)

Stock-based Compensation

Under Canadian GAAP, the Company follows the fair value method of accounting for stock based compensation. The Financial Accounting Standards Board (“FASB”) issued 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 Accounting Principles Board 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-20

(e)

Recently Issued United States Accounting Standards

The following accounting pronouncements have also been recently issued by the FASB:

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 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 adopted SFAS No. 157 as of January 1, 2008 and there was no material impact on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities— Including an amendment of FASB Statement No. 115,” (“SFAS No. 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. SFAS No. 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 adopted SFAS No. 159 as of January 1, 2008 and there was no material impact on our consolidated financial statements.

SFAS No. 161, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No. 133”) , requires companies with derivative instruments to disclose information about how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect a company’s financial position, financial performance, and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. SFAS No. 161 is effective prospectively for periods beginning on or after November 15, 2008.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — An amendment of ARB No. 51,” (“SFAS No. 160”) requires an entity to clearly identify and report ownership interests in subsidiaries held by parties other than the parent in the consolidated statement of financial position within equity but separate from the parent’s equity. SFAS No. 160 also requires that the amount of consolidated net income attributable to the parent and to the noncontrolling interest be identified and presented on the face of the consolidated income statement; changes in a parent’s ownership interest be accounted for as equity transactions; and when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation be measured at fair value. SFAS No. 160 is effective for the Company beginning January 1, 2009.

SFAS No. 141 (Revised 2007), “Business Combinations,” (“SFAS No. 141”) requires an acquirer to recognize the assets acquired, the liabilities assumed, contractual contingencies, and contingent consideration at their fair values as of the acquisition date. This Statement also requires acquisition costs to be expensed as incurred, restructuring costs to be expensed in the period subsequent to the acquisition date, and changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date to impact tax expense. SFAS No. 141 also requires the acquirer in an acquisition achieved in stages, to recognize the identifiable assets and liabilities, as well as the noncontrolling interest in the acquiree, at the full amounts of their fair values. SFAS No. 141 is effective for the Company for business combinations completed after December 31, 2008.

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)	2007			2006			2005
Net loss from continuing operations under Canadian GAAP	$	4,539		$	4,673		$	2,658
Marketable securities (b)		—			19			—

Net loss from continuing operations under U.S. GAAP		4,539			4,692			2,658

Net loss from discontinued operations under Canadian GAAP		3,398			4,740			1,115
Additional write-down of property and equipment (a)		2,880			1,311			—
Depletion and depreciation (a)		(111	)		(35	)		(51	)
Gain on sale of discontinued operations (a)		(4,251	)		—			—

Net loss from discontinued operations under U.S. GAAP		1,916			6,016			1,064

Net loss under U.S. GAAP		6,455			10,708			3,722
Marketable securities (b)		—			(128	)		147

Comprehensive net loss under U.S. GAAP		6,455			10,836			3,575

Basic and diluted net loss per share from continuing operations under U.S. GAAP		0.11			0.12			0.08
Basic and diluted net loss per share from discontinued operations under U.S. GAAP		0.04			0.16			0.03
Basic and diluted net loss per share under U.S. GAAP		0.15			0.28			0.11

Shares used in the computation of basic and diluted net loss per share		43,037,098			38,181,808			33,023,412

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


	December 31, 2007						December 31, 2006
(Thousands of U.S. dollars)	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Current assets	$	2,835		$	2,835		$	5,194		$	5,194
Restricted cash		2,272			2,272			4,339			4,339
Property and equipment(a)		1,572			1,572			5,859			4,377
Long-term investments		—			—			—			—

		6,679			6,679			15,392			13,910

Current liabilities*		3,037			3,037			2,951			2,951
Asset retirement obligations		—			—			1,939			1,939
Share capital(c)		23,788			42,191			23,164			41,567
Warrants		1,108			1,108			2,017			2,017
Contributed surplus		5,646			5,646			4,284			4,284
Deficit(a)(c)		(26,900	)		(45,303	)		(18,963	)		(38,848	)
Accumulated other comprehensive income (loss)(b)		—			—			—			—

		6,679			6,679			15,392			13,910

*	$8,000 of current asset retirement obligations is included in current liabilities at December 31, 2007.

F-21

After differences discussed above have been adjusted for, the condensed statements of deficit and accumulated other comprehensive income (loss) under Canadian GAAP and U.S. GAAP would be:


	December 31, 2007				December 31, 2006
(Thousands of U.S. dollars)	Canadian GAAP		U.S. GAAP		Canadian GAAP		U.S. GAAP
Deficit, beginning of year (c)	$	18,963	$	38,848	$	9,550	$	28,140
Net loss (a)(b)		7,937		6,455		9,413		10,708

Deficit, end of year (c)		26,900		45,303		18,963		38,848

Accumulated other comprehensive income (loss), beginning of year		—		—		—		128
Marketable securities (b)		—		—		—		(128	)

Accumulated other comprehensive income (loss), end of year	$	—	$	—	$	—	$	—

F-22

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 annual report on its behalf.


TransAtlantic Petroleum Corp.

By:		/s/ Hilda Kouvelis
		Hilda Kouvelis
		Chief Financial Officer

Date: May 14, 2008

INDEX TO EXHIBITS


Exhibit Numbers		EXHIBITS

1.1*		Certificate and Articles of Continuance dated June 10, 1997 (incorporated by reference to Exhibit 1.1 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

1.2*		Certificate and Articles of Amendment dated December 2, 1998 (incorporated by reference to Exhibit 1.2 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

1.3*		Certificate and Articles of Amalgamation dated January 1, 1999 (incorporated by reference to Exhibit 1.3 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

1.4		Certificate of Amendment and Registration of Restated Articles dated January 17, 2008.

1.5*		By-law No. 1 dated June 2, 1997 (incorporated by reference to Exhibit 1.4 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

4.1*		Executive Employment Agreement dated effective July 1, 2005 by and between TransAtlantic Petroleum Corp. and Scott C. Larsen (incorporated by reference to Exhibit 1.5 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

4.2*		Management Agreement dated effective April 1, 2006 by and between TransAtlantic Worldwide, Ltd. and Charles Management, Inc. (incorporated by reference to Exhibit 1.6 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

4.3*		Participating Interest Agreement dated effective July 11, 2005 by and among TransAtlantic Worldwide Ltd., TransAtlantic Petroleum Corp. and Scott C. Larsen (incorporated by reference to Exhibit 1.7 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

4.4*		Amended and Restated Stock Option Plan (2006) (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

4.5*		Warrant Indenture dated December 1, 2006 by and between TransAtlantic Petroleum Corp. and Computershare Trust Company of Canada (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).

4.6		Investment Agreement dated March 28, 2008 by and between TransAtlantic Petroleum Corp. and Riata Management, LLC.**

4.7		Credit Agreement dated March 28, 2008 by and between TransAtlantic Petroleum Corp. and Riata Management, LLC.**

4.8		Executive Employment Agreement dated effective January 1, 2008 by and between TransAtlantic Petroleum Corp. and Jeffrey S. Mecom.**

4.9		Executive Employment Agreement dated effective May 1, 2008 by and between TransAtlantic Petroleum Corp. and Hilda Kouvelis.**

8.1		Subsidiaries of the Company.

12.1		Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

12.2		Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

13.1		Certification of the Chief Executive Officer and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Previously filed

**	Schedules have been omitted. The Company will furnish supplementally copies of any of the omitted schedules upon request by the U.S. Securities and Exchange Commission.