20FR12G 1 a2026270z20fr12g.txt 20FR12G -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------- FORM 20-F --------------- (MARK ONE) /X/ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 / / ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 1999 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER ___________ TRANSATLANTIC PETROLEUM CORP. (Exact name of Registrant as specified in its charter) ALBERTA, CANADA (Jurisdiction of incorporation or organization) 340 - 12TH AVENUE S.W. SUITE 1550 CALGARY, ALBERTA T2R 1L5 (Address of principal executive offices) Securities registered or to be registered pursuant to Section 12(b) of the Act: NONE Securities registered or to be registered pursuant to Section 12(g) of the Act. COMMON SHARES, WITHOUT PAR VALUE ------------------------------------------- (Title of Class) 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: 79,384,092 Common Shares as of August 31, 2000. Indicate by check mark which financial statement item the registrant has elected to follow. Item 17 /X/ Item 18 / / -------------------------------------------------------------------------------- TABLE OF CONTENTS
PAGE ---- PART I.......................................................... 4 Item 1. Description of Business 4 Item 2. Description of Property 11 Item 3. Legal Proceedings 20 Item 4. Control of Registrant 20 Item 5. Nature of Trading Market 21 Item 6. Exchange Controls and Other Limitations Affecting Security Holders 21 Item 7. Taxation 22 Item 8. Selected Consolidated Financial Data 25 Item 9. Management's Discussion and Analysis of Financial Condition and Results of Operations 27 Item 9a. Quantitative and Qualitative Disclosures About Market Risk 35 Item 10. Directors and Officers of Registrant 36 Item 11. Compensation of Directors and Officers 37 Item 12. Options to Purchase Securities from Registrant or Subsidiaries 40 Item 13. Interest of Management in Certain Transactions 41 PART II......................................................... 41 Item 14. Description of Securities to Be Registered 41 PART III........................................................ 41 Item 15. Defaults Upon Senior Securities 41 Item 16. Changes in Securities and Changes in Security for Registered Securities 41 PART IV......................................................... 42 Item 17. Financial Statements 42 Item 18. Financial Statements 42 Item 19. Financial Statements and Exhibits 43
-2- GLOSSARY
"Bbl"................... means one barrel. "Bcf"................... means one billion cubic feet. "Bcfe".................. means billion cubic feet of gas equivalent calculated on the basis that one Bbl of crude oil or natural gas liquids is equivalent to six Mcf of natural gas. "BOE"................... means barrels of oil equivalent calculated on the basis that six Mcf of natural gas is equivalent to one barrel of crude oil or natural gas liquids equivalent. "BOE/d"................. means barrels of oil equivalent per day. "Bopd".................. means barrels of oil per day. "Company"............... means TransAtlantic Petroleum Corp. and its wholly owned subsidiaries. "Development well"...... means a well drilled within or in close proximity to a discovered pool of oil or gas. "Exploratory well"...... means a well drilled either in search of a new and as yet undiscovered pool of oil or gas, or with the expectation of significantly extending the limit of a pool which is partly discovered. "Gross acres"........... means the total number of acres in which the Company or its subsidiaries own a working interest. "Gross wells"........... means the total number of wells in which the Company or its subsidiaries own a working interest. "MBbl".................. means one thousand barrels. "MBOE/d"................ means one thousand barrels of oil equivalent per day. "Mcf"................... means one thousand cubic feet. "Mcf/d"................. means one thousand cubic feet per day. "MMBbl"................. means one million barrels. "MMBOE"................. means one million barrels of oil equivalent. "MMcf".................. means one million cubic feet. "MMcf/d"................ means one million cubic feet per day. "Net acres"............. refers to Gross acres multiplied by the Company's or its subsidiaries' working interest percentage therein. "Net wells"............. refers to Gross wells multiplied by the Company's or its subsidiaries' working interest percentage therein. "NGLs".................. means natural gas liquids. "PV-10 Value"........... means the present value of proved reserves and is an estimate of the discounted pre-tax cash flows attributable to estimated net proved reserves. Pre-tax cash flow is defined as net revenues less production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. Estimated pre-tax cash flows have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of the value of the revenue and should not be construed as being the fair market value of the properties. Estimates of reserve quantities and future net cash flows have been made using oil and gas prices and operating costs held constant at prices in effect on the date of the report. "TransAtlantic"......... has the same meaning as Company. "Undeveloped land"...... refers to oil and gas properties to which no reserves are assigned.
CURRENCY REFERENCES Unless otherwise indicated, all sums of money set out in this Form 20-F are expressed in United States dollars. The consolidated financial statements of the Company were historically expressed in Canadian dollars. The U.S. dollar became the principal currency of the Company's business, beginning in January 1998. FORWARD-LOOKING STATEMENTS This Registration Statement on Form 20-F contains certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, financial condition, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: the volatility of oil and gas prices, product supply and demand, market competition, risks inherent in the Company's oil and gas operations, imprecision of reserve estimates, the Company's ability to replace and expand oil and gas reserves, the Company's ability to generate sufficient cash flow from operations to meet its current and future obligations, the Company's ability to access external sources of debt and equity capital, and other factors referenced in this Registration Statement on Form 20-F. Certain of these factors are discussed in more detail elsewhere in this Registration Statement on Form 20-F, including without limitation "Item 1. Description of Business" and "Item 9. Management's Discussion and Analysis of Financial Condition and Results of Operations." Given these uncertainties, readers are cautioned not to place -3- undue reliance on such forward-looking statements. The Company disclaims any obligation to update any such forward-looking statements to reflect future events or developments. PART I ITEM 1. DESCRIPTION OF BUSINESS. TransAtlantic Petroleum Corp. is an oil and gas exploration and production company with its primary assets located in Egypt, Nigeria and the United States. In December 1998, the Company's predecessor company, Profco Resources Ltd. ("Profco") amalgamated with GHP Exploration Corporation ("GHP"), a publicly-traded exploration and production company. The Company issued 19,003,828 shares of common stock having a fair market value of $9.1 million to the shareholders of GHP in the amalgamation in exchange for a working capital infusion of $1.9 million and exploration prospects in Egypt, Tunisia and the United States. Profco was incorporated under the laws of the Province of British Columbia in October 1985 and continued under the laws of the Province of Alberta in June 1997. In connection with the amalgamation, Profco changed its name to TransAtlantic Petroleum Corp. and the Company generally began operating under new management. The year ended December 31, 1999 was the Company's first full year of operations following the amalgamation. As of December 31, 1999, the Company's estimated proved reserves totaled 4.77 MMBbls with a PV-10 Value of $12.25 million. Approximately 93% of the Company's reserves are proved producing reserves. The corporate office of the Company is Suite 1550, 340 - 12th Avenue S.W., Calgary, Alberta, T2R lL5. The Company's international operations are conducted out of the office of its wholly owned subsidiary, TransAtlantic Petroleum (USA) Corp., located at Suite 900, 1900 West Loop South, Houston, Texas, 77027. RECENT DEVELOPMENTS In July 1999, the Company successfully completed an exploration well, the Hana-1, on its West Gharib concession, onshore Gulf of Suez, Egypt. The Company owns a 30% working interest in the concession. An appraisal well, the Hana-2, was successfully completed in September 1999. During the first half of 2000, four additional appraisal wells were successfully drilled and completed. Production from the wells is being trucked to a pipeline approximately ten kilometers away while permanent production facilities are being installed, which will be capable of handling up to 15,000 Bopd. These facilities are expected to be completed in the third quarter of 2000. For the six months ending June 30, 2000, average daily production net to the Company from its West Gharib concession was 241 Bopd. The wells are currently producing at an average of 2,473 Bopd (278 Bopd net to the Company). In June 2000, the Company and its partners acquired a 60 square kilometer 3-D survey over several prospects adjacent to the Hana field and recently completed the acquisition of a 400 square kilometer 3-D survey to delineate additional prospects in the West Gharib concession. Since December 1999, the Company has drilled five wells on the Central Sinai concession, onshore Gulf of Suez, Egypt, two of which were successful. The Company owns a 25% interest in the concession. The Company is currently evaluating options for commercializing the field, and further drilling is dependent upon determinations of commerciality and further study of the well results. The first exploration period expired on September 22, 2000. The Company and its partner extended the first exploration period by six months by conducting further operations on the concession, subject to regulatory approval. Should regulatory approval be denied, the Company and its partner will seek approval for a development lease surrounding the Lagia-6, Lagia-7 and South Lagia wells. During 1999, the Ejulebe field in Nigeria produced approximately 2.65 MMBbls at a gross daily average of approximately 7,230 Bopd. Over the final six months of 1999, the field averaged 6,100 Bopd and for the first six months of 2000, the field averaged 5,740 Bopd. The Company's arrangement with the service contractor of the field provides that the Company receives a minimum payment until the capital component of the service contract has been paid to the service contractor. At current production levels, the Company will continue to only receive its share of the minimum payment, but may realize increased cash flow in the early 2001 if oil prices remain at their current level. See "Item 2. Description of Property--Nigeria--Development and Exploration of OML-109." As of December 1999, the Company has withdrawn from further activities in Tunisia and has relinquished its acreage position there. STRATEGY TransAtlantic's strategy is to build a substantial reserve base and sustainable production revenue by: -4- - cost efficiently acquiring projects containing, or adjacent to, known hydrocarbon accumulations with significant exploration potential in proven basins. - mitigating exploration risk through participation in a balanced portfolio of exploration activity where the net risk and exposure to the Company are acceptable. - exploring in countries which have attractive fiscal regimes and governments eager to develop their petroleum industries. - taking advantage of areas where the Company has considerable knowledge and can use that knowledge swiftly to create its competitive advantage. The Company's primary mission is to participate in a portfolio of high quality, low to medium risk oil and gas exploration ventures in high graded international areas. These are areas that management believes have significant remaining reserve potential and where commercial production can be rapidly established. The medium to long term plan includes participation both as operator and non-operator in acreage within specific focal areas in Africa and other international opportunities that will be evaluated based on merit and risks. In addition, the Company plans to evaluate existing field discoveries where additional exploration potential remains. RISK FACTORS THE COMPANY HAS A HISTORY OF LOSSES. The Company incurred net losses from operations of $1,731,000, $713,000, $12,368,000, $12,686,000 and $2,888,000 for each of the years ended December 31, 1995, 1996, 1997, 1998 and 1999, respectively. In addition, for the six months ended June 30, 2000, the Company incurred a net loss from operations of $825,000. No assurance can be made that the Company will operate at a profit in the future. The likelihood of the Company's future profitability must be considered in light of the financial, business and operating risks, expenses, difficulties and delays frequently encountered in connection with the oil and gas acquisition, exploration, development and production business in which the Company is engaged.The financial statements included herein do not include any adjustments that may result from these uncertainties. BECAUSE THE COMPANY HAS HAD A LIMITED OPERATING HISTORY, OPERATING RESULTS TO DATE SHOULD NOT BE UNDULY RELIED UPON. On December 1, 1998, the Company acquired GHP Exploration Corporation in an amalgamation transaction. The resulting enterprise (formerly Profco Resources Ltd.) was renamed TransAtlantic Petroleum Corp. In addition, in September 1998, production from the Company's Nigerian operations commenced. Prior to this time, the Company was engaged in exploration and development activities in Nigeria and also owned interests in a few producing oil and gas properties in Alberta, Canada that were sold in mid-1997. TransAtlantic commenced production from the Hana Field, Egypt in late December 1999. The operating results to date provide insufficient information to make any assumptions with respect to future cash flow from operations. Accordingly, no assurance can be given that TransAtlantic will successfully operate at a profit or generate sufficient cash flow to satisfy its working capital and debt service requirements in the future. THE COMPANY MAY NOT BE ABLE TO REPLACE RESERVES OR GENERATE CASH FLOWS IF IT IS UNABLE TO RAISE CAPITAL. The Company will be required to make substantial capital expenditures to develop reserves and to discover new oil and gas reserves. If TransAtlantic's cashflow from operating activities is insufficient to fund such additional expenditures, it will be required to sell equity, issue debt or offer interests in the properties to be earned by another party or parties carrying out further exploration or development thereof. See "Item 9. Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Capital Expenditures" for a discussion of the Company's capital budget. There can be no assurance that capital will be available to TransAtlantic from any source or that, if available, it will be at prices or on terms acceptable to TransAtlantic. If TransAtlantic is unable to meet its share of costs incurred under agreements to which it is a party, its interest in the properties subject to such agreements may be reduced. OIL AND NATURAL GAS PRICES ARE VOLATILE. TransAtlantic's revenues and profitability will be substantially dependent upon prevailing prices for crude oil, natural gas and natural gas liquids. For much of the past decade, the markets for crude oil and natural gas have been extremely volatile. Such markets are expected to continue to be volatile in the foreseeable future. In general, future prices of crude oil, natural gas and natural gas liquids are -5- dependent upon numerous external factors such as various economic, political and regulatory developments and competition from other sources of energy. The unsettled nature of the energy market and the unpredictability of worldwide political developments, including, for example, actions of the Organization of Petroleum Exporting Countries ("OPEC") members, make it particularly difficult to estimate future prices of oil, gas and natural gas liquids. Any significant decline in the price of oil, gas or natural gas liquids for an extended period would have a material adverse effect on TransAtlantic's financial condition and results of operations, and would, under certain circumstances, impair access to sources of capital. Currently, TransAtlantic has not entered into any derivative or long-term contracts to fix the prices received for its share of production. THE COMPANY MAY BE UNABLE TO REPLACE RESERVES IF ITS DRILLING OPERATIONS ARE UNSUCCESSFUL OR IF IT IS UNABLE TO ACQUIRE PROVED RESERVES. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. TransAtlantic's future success depends upon its ability to find, develop and/or acquire oil and gas reserves at prices that permit profitable operations. Except to the extent that TransAtlantic conducts successful development, exploitation or exploration activities or acquires properties containing proved reserves, the proved reserves of TransAtlantic will decline. This rate of decline depends upon reservoir characteristics encountered in TransAtlantic's Egyptian and offshore Nigeria reservoirs, where the majority of its proved reserves are located. The market for acquiring proved reserves is extremely competitive, and TransAtlantic may not be able to buy reserves for development and exploitation at prices it considers to be reasonable or within its budgets. The cost of drilling, completing and operating wells may vary significantly from initial estimates. TransAtlantic's drilling operations may be unsuccessful or may be curtailed, delayed or canceled as a result of numerous factors not within TransAtlantic's control. These factors include, but are not limited to, title problems, weather conditions, compliance with governmental requirements, shortage of capital, mechanical difficulties and shortages or delays in the delivery of drilling rigs or other equipment. Accordingly, there can be no assurance that TransAtlantic's acquisition, development, or exploration activities will result in reserves added at acceptable costs. THE COMPANY'S FOCUS ON EXPLORATORY PROJECTS INCREASES THE RISKS INHERENT IN OIL AND GAS ACTIVITIES. TransAtlantic will be spending a large portion of its capital budget on exploration, primarily on international projects. Exploration activities involve substantially more risk than development or exploitation activities. Exploratory drilling is a speculative activity. Although the use of 3-D seismic data and other advanced technologies could increase the probability of success of its exploratory wells, and reduce the average finding costs through the elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data and other traditional methods, TransAtlantic may not always be able to acquire 3-D seismic data over properties in which it owns an interest. Even when fully utilized and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not conclusively allow the interpreter to know if hydrocarbons will in fact be present, or present in economic quantities, in such structures. In addition, the use of 3-D seismic data and such technologies require greater predrilling expenditures than traditional drilling strategies and TransAtlantic could incur losses as a result of such expenditures. Failure of TransAtlantic's exploration activities would have a material adverse effect on TransAtlantic's future results of operations and financial condition. Should sufficient capital not be available, the development and exploration of TransAtlantic's properties could be delayed and, accordingly, the implementation of TransAtlantic's business strategy would be adversely affected. THE COMPANY'S FOCUS ON INTERNATIONAL OPERATIONS INCREASES THE RISKS INHERENT IN OIL AND GAS ACTIVITIES. TransAtlantic currently conducts operations and has proved reserves in Nigeria and Egypt and owns some minor properties in the United States. In the future, TransAtlantic may commence operations in other countries. International crude oil and natural gas exploration, development and production activities are subject to political, economic and other uncertainties including but not limited to changes, sometimes frequent or material, in governmental energy policies or the personnel administering them, expropriation of property, cancellation or modification of contract rights, foreign exchange restrictions, currency fluctuations, royalty and tax increases, retroactive tax claims, limits on allowable levels of production, labor disputes and other risks arising out of foreign governmental sovereignty over the areas in which TransAtlantic's operations will be conducted, as well as risks of loss due to civil strife, acts of war and insurrection. See "--Government Regulation." These risks may be higher in developing countries in which TransAtlantic may conduct such activities. TransAtlantic's international operations may also be adversely affected by laws and policies of Canada or the United States affecting foreign trade, taxation and investment. Consequently, TransAtlantic's international exploration, development and production activities may be substantially affected by factors beyond TransAtlantic's control, any of which could materially adversely affect TransAtlantic's financial position or results of operations. Furthermore, in the event of a dispute arising from international operations, TransAtlantic may be subject to the exclusive jurisdiction of courts outside the U.S. or Canada or may not be successful in subjecting persons to the jurisdictions of the courts in the U.S. or Canada, which could adversely affect the outcome of such dispute. -6- The Company's private ownership of oil and gas reserves under oil and gas leases in the United States differs distinctly from its ownership of foreign oil and gas properties. In the foreign countries in which the Company does business, the state generally retains ownership of the minerals and consequently retains control of (and in many cases, participates in) the exploration and production of hydrocarbon reserves. Accordingly, operations outside the United States may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, petroleum profits taxes, value added taxes, production bonuses, participation options and other charges. In addition, the Company may operate in such countries with a joint venture partner, and the Company's ability to conduct exploration, development and production activities may be materially adversely affected by decisions and actions of its joint venture partners. Certain of the Company's producing properties are located in Nigeria. Nigeria is a developing third world nation that has experienced periods of civil unrest and political and economic instability. In 1998, Nigeria made a peaceful transition from military rule to a democratically elected government. The establishment of a democratically elected government has brought with it the potential financial support of the international community. The amount of such financial support from the international community will be a factor in how well Nigeria thrives in the next several years. There can be no assurance of the extent of financial support by the international community if any. In addition, Nigeria and other African countries have occasionally asserted rights to land, including oil and gas properties, through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to the Company by another country, the Company's interests could be lost or decreased in value. In addition, political and economic instability in Africa could result in new governments or the adoption of new policies that might assume a substantially more hostile attitude toward foreign investment. Actions taken by the international community, future political unrest or actions by companies doing business in Nigeria may have a materially adverse effect on Nigeria and in turn, on TransAtlantic's financial condition or results of operations. TransAtlantic has no ability to control the factors that may lead to such events. Nigerian laws require that foreign companies involved in the petroleum industry hire and train indigenous personnel in petroleum operations. Nigerian oil workers are organized into a number of labor unions. In the fall of 1994, these labor unions called a general strike to protest against a number of the political changes that had occurred within Nigeria. There is no assurance that there will not be strikes in the future. Any future labor interruptions could adversely affect the Company's ongoing operations and its ability to explore for, produce, market and sell its reserves. FACTORS BEYOND THE COMPANY'S CONTROL AFFECT ITS ABILITY TO MARKET PRODUCTION. The marketability of TransAtlantic's production will depend upon numerous factors beyond the Company's control. These factors include the availability and capacity of gathering systems, pipelines and other production transportation systems, the effect of federal, state and other governmental regulation of such production and transportation, general economic conditions and the supply of and demand for crude oil and natural gas, the availability of alternate fuel sources and the effects of inclement weather, all of which could adversely affect TransAtlantic's ability to market its production. In addition, the Company may be unable to obtain favorable prices for the oil and gas it produces. THE CONCENTRATION OF THE COMPANY'S PROPERTIES INCREASES THE RISKS INHERENT IN OIL AND GAS ACTIVITIES. TransAtlantic's production and prospects are concentrated in a small number of properties and prospects. See "Item 2. Description of Properties." TransAtlantic will remain vulnerable to the disproportionate impact of delays or interruptions of production from its discoveries and exploratory prospects until it develops a more diversified production base. THE RESERVE INFORMATION IN THIS REGISTRATION STATEMENT ARE ESTIMATES WHICH SHOULD NOT BE UNDULY RELIED UPON. Numerous uncertainties are inherent in estimating quantities of proved and other reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represents only estimates based on available geological, geophysical, production and engineering data, the extent, quality and reliability of which vary. Oil and gas reserve engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact manner, and estimates of other engineers might differ materially from those shown. The accuracy of any reserve estimate is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, the estimates of future net cash flows from proved reserves and the present value thereof are based upon certain assumptions about future production levels, prices, costs and participation, if any, by third parties in the development of the Company's reserves that may not prove correct over time, for reasons which may or may not be under the control of or known to the Company. Any significant variance from these assumptions could materially affect the quantity and value of the Company's reserves as compared to the estimates contained herein. Information about reserves constitutes forward looking information. -7- PROCEEDINGS MAY BE INITIATED AGAINST THE COMPANY IF IT FAILS TO COMPLY WITH THE TERMS OF A SETTLEMENT AGREEMENT. In August 2000, the Company entered into a settlement agreement with Global Marine Integrated Services--International Inc. ("GMISI"), a wholly-owned subsidiary of Global Marine, Inc., relating to the payment of outstanding indebtedness on a promissory note from Tarpon-Benin S.A. to GMISI in the original amount of $3,071,060. See "Item 9. Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." The Company, as the indirect majority owner of Tarpon, guaranteed the note. Although some payments had been made against the note, Tarpon failed to pay the note in accordance with its terms and as of January 31, 2000 the note was in default. GMISI has agreed that so long as the Company complies with the terms of the settlement agreement, GMISI will not seek to enforce the note against the Company or initiate any proceedings against the Company with regard to the note or the guarantee. If the Company fails to or is unable to comply with the terms of the settlement agreement, GMISI may pursue legal and equitable remedies against TransAtlantic. A RECENT ARBITRATION DECISION RULED AGAINST THE COMPANY; IF THE COMPANY IS REQUIRED TO PAY THE DAMAGES AWARDED, IT COULD HAVE A MATERIAL ADVERSE EFFECT ON THE COMPANY. Several of the Company's wholly owned subsidiaries (the "Subsidiaries") are parties to a Shareholder Agreement, pertaining to the Company's interest in Tarpon-Benin S.A. ("Tarpon") of which the Company is the indirect majority owner. Tarpon owned a concession in the Republic of Benin. At a meeting of the shareholders in 1998, Tarpon elected to withdraw from the concession and allow the concession agreement to expire; however, a group of minority shareholders (the "Shareholders") objected. The Shareholders, along with the parent company of the Shareholders, initiated arbitration in October, 1998 under the American Arbitration Association. On September 18, 2000, the Company was advised that the arbitrator ruled that the Subsidiaries had breached the Shareholder Agreement and assessed damages of $1,848,359.32. While the Company was not a party to the Shareholder Agreement, the arbitrator ruled that the Company guaranteed all obligations of the Subsidiaries. The Company does not believe that the Subsidiaries have a basis to appeal the decision. However, the Company intends to contest the arbitrator's ruling against the Company. If the Company is required to pay the damages awarded, it could have a material adverse effect on the Company. THE COMPANY'S QUARTERLY RESULTS FLUCTUATE SIGNIFICANTLY AND SHOULD NOT BE UNDULY RELIED UPON. TransAtlantic's quarterly results of operations may fluctuate significantly as a result of variations in oil and gas production and prices and variations in TransAtlantic's drilling activities. Drilling activities can be affected by a number of factors including the availability of equipment for drilling or recompletions, weather, governmental regulations and available cash flow. WEATHER, UNEXPECTED SUBSURFACE CONDITIONS AND OTHER UNFORESEEN OPERATING HAZARDS MAY ADVERSELY IMPACT THE COMPANY'S ABILITY TO CONDUCT BUSINESS. 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 TransAtlantic 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 TransAtlantic's ability to market its production. Moreover, offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions. TransAtlantic will maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. Insurance may not cover downhole-operating risks, such as the costs of retrieving stuck equipment. Furthermore, TransAtlantic cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all to cover the risks faced by TransAtlantic. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect the Company's financial condition and results of operations. COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENTAL REGULATIONS COULD BE COSTLY AND COULD NEGATIVELY IMPACT PRODUCTION. The drilling for and production, handling, transportation and disposal of oil and gas and byproducts are subject to extensive regulation under federal, provincial, state, local and foreign country environmental laws that may be changed from time to time in response to economic or political conditions. See "--Government Regulation." Matters subject to regulation include, but are not limited to, permits for drilling operations, drilling, plugging and reclamation bonds, operational practices and reporting, the spacing of wells, unitization -8- and pooling of properties, taxation and environmental protection. In most instances, the applicable regulatory requirements relate to water and air pollution control and solid waste management measures, permitting requirements, or restrictions on operations in environmentally sensitive areas, such as coastal zones, wetlands, and wildlife habitat. Under these laws and regulations, the Company could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. The Company maintains limited insurance coverage for sudden and accidental environmental damages. The Company does not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Moreover, the Company does not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Offshore operations are subject to more extensive governmental regulation, including regulation that may, in certain circumstances, impose absolute liability for environmental damage and allow interruption or termination of business activities by government authorities based on environmental or other considerations. COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT THE COMPANY'S ABILITY TO CONDUCT OPERATIONS. Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. Major and independent oil and gas companies, as well as individuals and drilling programs, actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop such properties. Many of TransAtlantic's competitors have financial resources and exploration and development budgets that are substantially greater than those of TransAtlantic, which may adversely affect TransAtlantic's ability to compete successfully. In addition, many of TransAtlantic's larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. Other factors which affect the Company's ability to successfully compete are: the Company's access to seismic, geological and other information, and the Company's ability to retain the personnel necessary to properly evaluate such information; the location of, and the Company's ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production; and the standards the Company establishes for the minimum projected return on an investment of its capital. INFORMATION IN THIS REGISTRATION STATEMENT REGARDING THE COMPANY'S PROSPECTS REFLECTS THE COMPANY'S CURRENT INTENT AND IS SUBJECT TO CHANGE. The Company's current prospects and plans to explore these prospects are described in this registration statement. A prospect is a property on which the Company has identified what its geoscientists believe, based on available seismic and geological information, to be indications of hydrocarbons. The Company's prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect which will require substantial additional seismic data processing and interpretation. Whether the Company ultimately drills a prospect may depend on the following factors: receipt of additional seismic data or the reprocessing of existing data; material changes in oil or gas prices; the costs and availability of drilling rigs; success or failure of wells drilled in similar formations or which would use the same production facilities; availability and cost of capital; changes in the estimates of the costs to drill or complete wells; the Company's ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; and decisions of the Company's joint working interest owners. The Company will continue to gather data about its prospects, and it is possible that additional information may cause the Company to alter its drilling schedule or determine that a prospect should not be pursued at all. THE LOSS OF KEY PERSONNEL COULD NEGATIVELY AFFECT THE COMPANY'S OPERATIONS. TransAtlantic will depend to a large extent on the services of its senior management personnel. The loss of the services of any such personnel could have a potential adverse effect on TransAtlantic's operations. CERTAIN OFFICERS AND DIRECTORS MAY HAVE INTERESTS ADVERSE TO THE COMPANY. There may be potential conflicts of interest for certain of the officers and directors of TransAtlantic who are or may become engaged from time to time in the crude oil and natural gas business on their own behalf or on behalf of other companies with which they may serve in the capacity as directors or officers. Certain of the outside directors of TransAtlantic are officers and/or directors of other publicly traded crude oil and natural gas exploration and production companies. To the extent any such conflicts arise from time to time, they will be governed by and resolved in accordance with the applicable provisions of TransAtlantic's governing corporate legislation. GOVERNMENT REGULATION NIGERIA -9- All phases of oil exploration, development and production in Nigeria are regulated by the Nigerian government either directly, through the Nigerian Ministry of Petroleum Resources ("NMPR") or the Nigerian Department of Petroleum Resources ("NDPR") pursuant to the PETROLEUM DECREE, 1969, and under periodic policy statements issued by the Nigerian government and administrative practices of the NDPR. Areas of government regulation include restrictions on petroleum production, price controls, export controls, taxes and royalties, expropriation of property, environmental protection and rig safety. In addition, all petroleum drilling and production in Nigeria must be approved in advance by the Nigerian government through the NMPR or the NDPR. TransAtlantic's partner, Atlas Petroleum International Limited, as operator, and TransAtlantic's wholly owned subsidiary, Summit Oil & Gas Worldwide Ltd., as technical adivsor, must submit annual work programs and budgets to the NDPR for review and approval. Likewise, the NDPR must approve, in advance, all seismic and drilling activities as well as the installation of production facilities through the issuance of permits for such activities. Although the Company has no reason to believe that the applicable approval will not be received in the normal course, there is no assurance that the NDPR will grant the requisite approvals. Failure to obtain NDPR approval could have a materially adverse effect on the future results of operations of the Company. Producers are subject to a tax on adjusted petroleum profits. Adjusted petroleum profits consist generally of revenues from petroleum sales less operational expenses and certain capital costs (including drilling costs). The PETROLEUM PROFITS TAX ACT, 1969, prescribes a petroleum profits tax rate of 65.75% for the first five years and 85% thereafter. The Company understands that a reduced petroleum profits tax rate or other regulatory relief may be applicable to concession blocks awarded under the Indigenous Program. Any changes to the current royalty regime or the PETROLEUM PROFITS TAX ACT, 1969 or their applicability to the Indigenous Program will affect the Company. Under Nigerian legislation, a petroleum concession owner is required to engage in petroleum exploration and development. Concessions may be obtained directly from the NMPR or from an existing concession owner, provided that prior NMPR approval to an assignment is obtained. Petroleum concessions granted by the NMPR consist of either an oil exploration license, an oil prospecting license ("OPL") or an oil mining lease ("OML"). The PETROLEUM DECREE, 1969 provides that an OPL is issued for a maximum term of five years. An OPL gives the holder the exclusive right to conduct both seismic and exploratory drilling operations within a concession block and the right to carry away and dispose of petroleum produced during the term of the OPL. If, during the term of the OPL, testing or actual production demonstrates that the OPL is capable of producing 10,000 Bopd ("Commercial Quantities") and conditions imposed by the NMPR and NDPR are satisfied, including payment of applicable fees and the provision of specified documentation, the holder of an OPL becomes entitled to apply to the NMPR for an OML. An OML provides the holder with an exclusive right to conduct exploration and development drilling operations and the exploitation of petroleum discovered on the concession block for a term of up to twenty years. An OML may be renewed upon application to the NMPR. The PETROLEUM DECREE, 1969 contains provisions that require the holder of an OML to relinquish 50% of the geographic area encompassed by the OML after ten years upon the request of the NMPR. The acreage to be relinquished is identified by the holder of the OML. The lessee of an OML shall be entitled to apply in writing to the Minister, not less than twelve months before the expiration of the lease, for a renewal of the lease either in respect of the whole of the leased area or any particular part thereof, and the renewal shall be granted if the lessee has paid all rent and royalties due and has otherwise performed all his obligations under the lease. Under the PETROLEUM DECREE, 1969, the Nigerian government may elect, during the currency of an OML or OPL, to directly participate in the concession, which could result in a reduction of the participating interest of the Company. The PETROLEUM DECREE, 1969 does not specify the maximum level of government participation. Neither the PETROLEUM DECREE, 1969 nor any subsequent correspondence between the NMPR and the Company's Nigerian partner addresses either the payment to the Company or its Nigerian partner of a proportionate share of future costs or the reimbursement of past costs by the Nigerian government. EGYPT All phases of oil exploration, development and production in Egypt are regulated by the Egyptian government through Egyptian General Petroleum Corporation ("EGPC"). Areas of government regulation include exploration and production approvals, taxes and royalties, expropriation of property, environmental protection and safety. Concession holders are subject to an Egyptian corporate income tax of 42.5% that is paid by EGPC on behalf of the concession holder out of EGPC's share of revenues. Concessions are generally held under profit sharing agreements which are negotiated individually with EGPC. Under Egyptian legislation, a petroleum concession owner is required to engage in petroleum exploration and development. Concessions may be obtained directly from EGPC or from an existing concession owner, provided that prior EGPC approval to an assignment is obtained. The holders of the concession have the exclusive right to conduct both geophysical and exploratory drilling operations within the concession block and the right to carry away and dispose of production produced during the term of the concession. If, during the term of the concession, testing or production of commercial quantities of hydrocarbons is achieved and conditions imposed by EGPC are satisfied, including the provision of specified documentation, the holder of the concession has the right to apply to EGPC for a -10- conversion to a development lease and the formation of a joint operating company specifically set up to administer the development, exploration and administration of the development lease. The joint operating company is directed by a board of directors including, in equal numbers, members of EGPC and the concession holders. Management of the joint operating company is run by a chairman delegated by EGPC. Other senior management positions are negotiated between EGPC and the concession holders. The concession holder has the right to explore and produce oil from the development lease for a period of twenty years. A development lease can be extended upon proof of commercial reserves. Areas outside the development lease, but within the concession limits, are generally held for three exploration phases (generally consisting of three-year periods). Each exploration phase consists of a minimum work obligation, including minimum financial commitments. Following completion of the minimum work program and written acceptance by EGPC that the work program obligations have been fulfilled, the concession holder has the option to relinquish the concession or relinquish 25% of the concession and commit to a further exploration phase. The acreage to be relinquished is identified by the concession holder. The renewal of the lease shall be granted to the concession holder if all obligations have been performed under the lease. Egypt retains the right of requisition of production from Egyptian concessions and cancellation of the concession agreements upon the occurrence of specific events, including a national emergency due to war, imminent expectation of war or internal causes, unauthorized assignment of interests in the concession, the concession holder being adjudicated bankrupt by a court of competent jurisdiction and intentional extraction of any mineral not authorized by the concession agreement. Requisition or cancellation of the Company's concession agreements as a result of the foregoing or for any other reasons would have a material adverse effect on the Company. MANAGEMENT AND EMPLOYEES As of December 31, 1999, TransAtlantic and its subsidiaries had 10 employees of which three were executive officers. See "Item 10. Directors and Officers of Registrant." The Company utilizes consultants when necessary and engages field personnel on a contract basis to manage the Company's operated producing properties. ITEM 2. DESCRIPTION OF PROPERTY. The Company is engaged in the exploration, development and acquisition of oil and gas properties. The Company's activities are currently focused in evaluating and exploiting the petroleum potential of specific concessions in North and West Africa. These areas possess prolific source rocks that have charged some of the world's largest oil fields. Management believes that both areas offer good opportunity for the Company to explore for oil and in North Africa, for natural gas where existing infrastructure includes a network of oil and gas pipelines linking fields with ports and urban centers, as well as major gas transmission lines to European markets. The infrastructure for gas has not yet developed in West Africa. NIGERIA Nigeria began producing oil in 1957 and is currently Africa's largest oil producer and exporter. Given the critical role oil plays in the Nigerian economy, the Company believes that any potential civil or political unrest will not adversely affect the country's oil industry. The country offers numerous opportunities for continued oil exploration offshore at relatively shallow drilling depths and low exploration risk. THE INDIGENOUS PROGRAM TransAtlantic's participation in Nigeria is through a joint venture between the Company's wholly owned subsidiary, Summit Oil and Gas Worldwide Ltd. ("SOGW"), as technical advisor, and Atlas Petroleum International Limited ("Atlas"), a Nigerian company that serves as operator of the concession. The joint venture with Atlas is under a program (the "Indigenous Program") introduced in 1990 by the NMPR in an effort to increase production and domestic participation in the country's oil industry. The Indigenous Program provides qualified, privately-owned Nigerian companies with both preferential treatment in the allocation of available petroleum concession blocks and favorable economic terms for the development of such blocks. Participating Nigerian companies are permitted to establish revenue and cost sharing arrangements with foreign companies that provide the technical expertise, operational support and financial resources required for exploration and development operations. As part of the Indigenous Program, the Nigerian government receives production royalties and taxes and is not required to fund any exploration or development costs. The financial terms that are available to SOGW under the Indigenous Program differ from those generally available to most multinational companies that operate in Nigeria. Outside of the Indigenous Program, multinational companies are joint working interest owners with the Nigerian National Petroleum Company ("NNPC") under one of several different forms of joint ventures. The joint ventures generally provide that the participating company and the NNPC collectively fund operating and capital expenditures and recover their costs and profits from the -11- proceeds of production based on their relative participating interest. In addition, under the joint ventures, the NNPC has the right to approve proposed exploration and development projects. TransAtlantic believes that SOGW's ability under the Indigenous Program to proceed with exploration and development projects that it considers attractive without NNPC participation gives it increased flexibility to pursue other opportunities within Nigeria. Recent announcements by the Nigerian government and the NDPR have indicated that companies participating in the Indigenous Program should qualify for certain tax and royalty relief. However, no such royalty or tax relief has yet been instituted. In March 2000, SOGW initiated an arbitration to resolve certain differences of opinion between SOGW and Atlas relating to the interpretation of certain provisions of its joint operating agreement with Atlas. It also involves disagreements regarding reporting of royalties and lifting procedures. The dispute relates primarily to the undeveloped acreage on the concession, and does not affect the operation of the Ejulebe field. SOGW has filed an arbitration proceeding in Geneva. See "Item 3. Legal Proceedings." In addition, in 1996, SOGW loaned $5.0 million to the Chairman of Atlas by way of a three year promissory note, which was guaranteed by Atlas. Atlas pledged 50% of its 40% interest in OML-109 to SOGW as security. The note is in default and SOGW has initiated proceedings for its collection. The collection proceeding was filed in the High Court of England and Wales in London, England and is set for trial in early 2001. See "Item 3. Legal Proceedings." OIL MINING LICENSE ("OML") -- 109 SOGW owns a 30% interest in a 215,000 acre concession offshore Nigeria. Prior to the recovery of its accumulated costs incurred ("payout"), SOGW is responsible for the payment of 100% of capital costs and receives 60% of the net revenue accruing to SOGW and Atlas. With respect to 200,000 of the acres, SOGW has a 30% interest after payout (60,000 net acres) and a 22.5% working interest after payout in the remaining 15,000 acres (3,375 net acres) surrounding and including the Ejulebe field. Until a loan made by SOGW during 1996 to the Chairman of Atlas is repaid, SOGW is also entitled to receive 50% of Atlas' share of cash flow from the concession (20% net to SOGW) pursuant to Atlas's guarantee. See "--The Indigenous Program," above. The concession, located in the northwestern part of the Niger Delta, is 12 to 15 kilometers offshore in 50 to 250 feet of water. Originally granted as an oil prospecting license, OPL-75, the concession was converted to OML-109 in 1996. The oil mining license was granted for an initial term of 20 years and may be extended upon proof of additional commercial economic reserves. There are no governmental prescribed work program requirements for the concession; however, Atlas and SOGW must submit annual work programs and demonstrate continued activity to explore and develop the block. DEVELOPMENT AND EXPLORATION OF OML-109 The local geology offshore Nigeria is very similar in geophysical response, structural style and formation age to that of the Mississippi Delta in the Gulf of Mexico. Seismic interpretation techniques, such as "bright spot" identification, that have been proven to reduce exploration risk in the Gulf of Mexico and other areas are applicable to this area. Additionally, the Company believes that specialized seismic processing techniques will assist in delineating hydrocarbon type and extent of accumulations. In 1994, SOGW originally acquired and processed a 32 square mile 3-D seismic survey over a portion of the northern half of the concession, including the Ejulebe field. Subsequently, in 1996 SOGW and Atlas, through a service contractor, acquired and processed the "Ekura" survey consisting of approximately 127 square miles of 3-D seismic data. SOGW also acquired 2-D seismic in 1995 that covers the entire 215,000 acres, and in 1995 acquired additional 3-D coverage that had been previously acquired by Chevron. SOGW now has 3-D seismic surveys covering approximately 40% of the concession. EJULEBE FIELD Production under OML-109 first commenced in September 1998 with the development of the Ejulebe field. The field is located in the northern portion of the concession area, four miles northwest of the Mefa oilfield, which is located on the offsetting concession to OML-109 and operated by Chevron. The field was originally discovered by SOGW in 1994. Following the discovery, an appraisal well was drilled in 1995. Subsequently, SOGW and Atlas entered into a service contract dated January 14, 1996 whereby CXY Nigeria Oil Field Services Ltd., a subsidiary of Canadian Occidental Petroleum Ltd. ("CXY"), provides certain financial, technical and operational services in the 15,000 acres surrounding and including the Ejulebe field. Pursuant to the service contract, two additional exploratory wells and three development wells were drilled on or near the Ejulebe Field in 1996 and 1997. A production platform was built and pipeline laid for first production which commenced in September 1998. As compensation for providing the above services, CXY recovers its costs, which include actual -12- operating and capital costs and a financing fee, and receives 25% of the net operational revenues from Ejulebe and other hydrocarbon accumulations CXY discovers on the 15,000 acres. The 25% declines to 20% as certain cumulative production levels are attained. CXY pays the Company and Atlas a minimum payment of $510,000 ($306,000 net to the Company) per year if profits are not generated under the terms of the service contract. As part of their commitment, CXY drilled two successful development oil wells in the field, a pressure maintenance well on the flank of the structure and two unsuccessful exploratory wells. Currently, there are three wells producing oil in the field. Delivery of Ejulebe production is via a 14 mile, 6 inch pipeline from the central production facilities to a floating storage and off-loading facility operated by Conoco. TransAtlantic's capital expenditures to date total just over $14 million. CXY's capital expenditures to date exceed $105 million on the field. During 1999, the Ejulebe field produced approximately 2.65 MMBbls at a gross daily average of approximately 7,230 Bopd. Over the final six months of 1999, the field averaged 6,100 Bopd and for the first six months of 2000, the field averaged 5,740 Bopd. This rate is significantly lower than pre-production estimates. The Company's arrangement with CXY provides that the Company receives a minimum payment until CXY reaches payout. At current production levels, SOGW is realizing only the minimum payment of approximately $306,000 per year. If the production rate remains stable and oil prices remain above $25 per barrel, the Company estimates that the Ejulebe field should become profitable in year 2001. Otherwise, TransAtlantic will continue to receive only its share of the minimum payment under the services contract with CXY. Management continues to explore ways to increase daily rates and accelerate production of the remaining reserves; no assurances can be made, however, that management will be successful. At present production rates, it is not anticipated that the production quotas set by the Nigerian Government as a member of the Organization of Petroleum Exporting Countries will have an impact on the Ejulebe field. Estimated net proved reserves attributable to this field at December 31, 1999 were 4.25 MMBbls with a PV-10 Value of $ 4.57 million. ADDITIONAL PROSPECTS ON OML-109 The balance of the 200,000 acres on the OML-109 are to be explored and developed by SOGW and Atlas. SOGW continually reevlauates its interpretation of the seismic data covering this area and has identified eight prospects on or extending onto OML-109, including the Kahuna Prospect and the Tuna Prospect, described below. No exploration activities can be undertaken, however, until settlement of the dispute with the Company's indigenous partner. The Company anticipates that a drilling program will be undertaken with respect to the Kahuna and Tuna prospects approximately six to eight months after settlement or resolution of the arbitration. The Company continually reviews its drilling plans in light of changing circumstances. See "Item 1. Description of Business--Risk Factors--Prospects." The Company's drilling schedule with respect to its other prospects will depend on the results of the Company's program on the Kahuna and Tuna prospects and other factors described under "Item 1. Description of Business--Risk Factors--Prospects." Kahuna Prospect. A down to the basin fault closure to the east of the Sonam structural crest is the basis for the Kahuna prospect. It covers approximately 1,000 acres in area, with a water depth of approximately 125 feet. This area consists of major growth faults together with several small fault blocks. Several amplitude anomalies are associated with the fault closures, giving credence to the prospect. Estimated net dry hole costs to drill this well are $3.5 million. Tuna Prospect. This prospect is located upthrown and adjacent to the down-to-the-basin fault that forms the Kahuna prospect. The structure covers an area of approximately 800 acres and exhibits anomalous seismic amplitudes. Water depth at the prospect is approximately 125 feet. A well drilled to approximately 8,000 feet would test the primary section of interest. Estimated net dry hole costs to drill this well are $3.5 million. EGYPT Egypt is a major focal area for the Company. Management believes that the country offers excellent opportunities to build a large reserve base in areas with proven petroleum systems, excellent economics and shallow, inexpensive drilling. In addition, there are existing facilities for the gathering, treating, storage and transportation of crude oil located in and around the existing fields within each of the Company's concessions. CENTRAL SINAI CONCESSION The Central Sinai Concession consists of 4.5 million acres and is located onshore in the central portion of the Sinai Peninsula within the Gulf of Suez basin. The western portion of the block borders the Gulf of Suez shore for more than 100 kilometers. With the exception of the coastal lands and the interior basin, the terrain is primarily mountainous topography. There are three oil fields confined -13- within the boundaries of the concession but specifically excluded from the concession rights. The Egyptian government oil company holds these fields, which were discovered by Shell between 1946 and 1947 using gravity techniques before the emergence and use of seismic techniques. The producing horizons are shallow Miocene and Eocene formations at depths ranging from 2,000 feet to 4,000 feet. Refinery and tanker terminals exist at Suez, which is located adjacent to the northern boundary of the Central Sinai concession, and at Wadi Feiran, 20 kilometers south of the concession. Storage and loading facilities exist at Ras Budran on the southern boundary of the block. An excellent metaled road, capable of accommodating the heaviest of oilfield traffic, runs from north of Suez along the west coast of the Sinai Peninsula to Sharm el-Sheikh, though other roads are few. ACQUISITION OF INTEREST IN CONCESSION The Company's wholly-owned subsidiary, GHP Exploration (Egypt) Ltd. ("GHP-Egypt"), acquired its 25% interest in the concession pursuant to a Participation Agreement dated March 27, 1998 with Alliance Egyptian National Exploration Company ("Alliance"). In consideration of the 25% interest, GHP-Egypt repaid Alliance $1.0 million of their prior costs incurred. In addition, GHP-Egypt agreed to pay 40% of the $6.0 million minimum financial commitment ($2.4 million net to GHP-Egypt) associated with the initial work program required to be carried out on the concession of which all has been paid as of July 31, 2000. Alliance is the operator under the concession, and GHP-Egypt serves as the technical advisor. CONCESSION TERMS The concession agreement requires that GHP-Egypt and Alliance pay all of the operating and capital costs for developing the concession, while the production will be split between GHP-Egypt, Alliance and EGPC, the government partner. Up to 35% of the crude oil and natural gas produced from the concession is available to GHP-Egypt and Alliance to recover operating and capital costs ("Cost-Recovery Oil"). To the extent eligible costs exceed 35% of the crude oil and natural gas produced and sold from the concession in any given quarter, such excess costs may be carried into future quarters without limit. The remaining 65% of all crude oil and natural gas produced from the concession ("Profit Oil") is divided between EGPC and GHP-Egypt and Alliance, with the percentage received by GHP-Egypt and Alliance reducing from 26% to 15% as the gross daily average crude oil and natural gas equivalent produced on a quarterly basis increases from less than 5,000 Bbls/d to in excess of 50,000 Bbls/d. To the extent that eligible operating and capital costs do not exceed 35% of the crude oil and natural gas produced and sold from the concession in any given quarter, such excess Cost-Recovery Oil is split between EGPC and GHP-Egypt and Alliance in the same percentages as the Profit Oil outlined above. WORK PROGRAM OBLIGATION GHP-Egypt and Alliance are in the first exploration phase under the concession. The work program required under the terms of the concession agreement mandates the drilling of four wells and the acquisition of 200 square kilometers of 3-D seismic data and additional 500 line kilometers of 2-D seismic data in the initial three-year exploration period that expired September 22, 2000. The exploration period has been extended an additional six (6) months through operations, subject to regulatory approval. This program requires a net minimum financial commitment of $2.4 million. A 25% acreage relinquishment is required after the initial exploration period. As of June 30, 2000, the Company had incurred all of this amount and the government had waived any unmet work program obligations. Since then, the Company has expended a small amount of money employing the services of a workover rig on the Lagia-6, Lagia-7 and South Lagia wells. EXPLORATION PROGRAM In February 1999, TransAtlantic and its industry partner acquired approximately 310 kilometers of 2-D seismic data over several leads that had been identified from previous data. Seismic processing and interpretation of this data set was completed in October 1999. From this interpretation seven prospects and leads were identified. Four exploratory test sites were chosen from these prospects. Although called for in the concession agreement, no additional 2-D or 3-D seismic was shot on the concession. The government accepted the work program of GHP-Egypt and its partner which included drilling more than the minimum number of wells and which met the financial commitment called for under the concession agreement. West Asl-1, the first well in this drilling program, is located approximately three kilometers from the prolific Asl field. West Asl-1 was designed to target the same Miocene and Eocene section found to be productive at Asl field. Total depth of this exploration well was expected to be approximately 5,500 feet. The West Asl-1 test well began drilling on December 3, 1999 and reached the primary objective on December 14, 1999. When entering the primary Eocene target interval, the well experienced total loss of mud filtrate into the formation resulting in the loss of the hole. The well was officially plugged and abandoned on December 18, 1999. The Company next began drilling the South Lagia well in January 2000. This well, although showing promising indications of hydrocarbons, was determined to be non-commercial following testing. In March 2000, the Company drilled the Lagia-6 well. The Lagia-6 discovery well -14- was drilled to a total depth of 2,500 feet and production casing was set at 1,250 feet in order to evaluate the Miocene Nukhul formation. Electric logs and hydrocarbon shows while drilling indicated a gross sand section of 170 feet with over 60 feet of net oil pay. In April 2000, the Lagia-7 well was drilled approximately 380 meters downdip of Lagia-6 and encountered a gross hydrocarbon column of 177 feet with over 75 feet of net oil pay. A fifth well, drilled in May 2000, was a dry hole. The Company is evaluating options for commercializing the field, and further drilling is dependent upon determinations of commerciality and further study of the well results. The Company and its partner plan to extend the first exploration period by six months by conducting further operations on the concession, subject to regulatory approval. Should regulatory approval be denied, the Company and its partner will seek approval for a development lease surrounding the Lagia-6, Lagia-7 and South Lagia wells. WEST GHARIB CONCESSION The West Gharib concession consists of 630,000 acres and is located on the onshore portion of the Gulf of Suez Basin. Most of the concession's 120 kilometer length is located within the prolific Gulf of Suez petroleum system. The topography throughout the concession consists of coastal plain geology with minor surface faulting. There is one oil field located within the boundaries of the concession but specifically excluded from the concession rights. On the West Gharib concession, both oil and gas pipelines run the length of the concession with storage and loading facilities located adjacent to the concession at Ras Shukeir. ACQUISITION OF INTEREST IN CONCESSION The Company's wholly owned subsidiary, GHP Exploration (West Gharib) Ltd. ("GHP-West Gharib"), acquired its 30% interest in the concession pursuant to a Participation Agreement dated April 27, 1998 with Dublin International Petroleum (Egypt) Limited ("Dublin"), a wholly owned subsidiary of Tanganyika Oil Company Ltd. In consideration of the 30% interest, GHP-West Gharib repaid Dublin and Tanganyika $303,000 of their sunk costs. In addition, GHP-West Gharib agreed to pay 60% of the first two exploration wells to a maximum of $750,000 net to GHP-West Gharib. Thereafter, GHP-West Gharib will pay 30% of all exploration and development costs. Dublin is the operator of the concession. CONCESSION TERMS The concession agreement requires that GHP-West Gharib and its partners in the concession pay all of the operating and capital costs for developing the concession, while the production will be split between GHP-West Gharib, its joint venture partners, and EGPC. Up to 30% of the crude oil and natural gas produced from the concession is available to GHP-West Gharib and its partners to recover operating and capital costs ("Cost-Recovery Oil"). To the extent eligible costs exceed 30% of the crude oil and natural gas produced and sold from the concession in any given quarter, such excess costs may be carried into future quarters without limit. The remaining 70% of all crude oil and natural gas produced from the concession ("Profit Oil") is divided between EGPC and GHP-West Gharib and its partners, with the percentage received by GHP-West Gharib and its partners reducing from 30% to 15% as the gross daily average crude oil and natural gas equivalent produced on a quarterly basis increases from less than 5,000 Bopd to in excess of 100,000 Bopd. To the extent that eligible operating and capital costs do not exceed 30% of the crude oil and natural gas produced and sold from the concession in any given quarter, such excess Cost-Recovery Oil is split 70% to EGPC and 30% to GHP-West Gharib and its partners. WORK PROGRAM OBLIGATION The required work program for the initial three-year exploration period, which commenced on June 1, 1998, is to drill three wells, acquire 50 square kilometers of 3-D seismic data and 300 line kilometers of 2-D seismic data. All of the work program obligations have been met. Net financial exposure to GHP-West Gharib for this initial exploration period is approximately $1.86 million, of which all had been incurred as of December 31, 1999. In addition to meeting its work program obligations for the initial exploration period, through July 31, 2000, the Company has spent an additional $1.5 million on the West Gharib concession. EXPLORATION PROGRAM The joint venture has acquired 43 square kilometers of 3-D seismic data, 248 line kilometers of 2-D seismic data and reprocessed existing 2-D seismic data. Based on this seismic data, two exploration wells and one appraisal well were drilled during 1999 resulting in the discovery and subsequent commercial declaration of the Hana oil field and one dry hole (Farha 1). In June 2000, the Company and its partners acquired a 60 square kilometer 3-D survey over several prospects adjacent to the Hana field and commenced the acquisition of a 400 square kilometer 3-D survey to delineate additional prospects in the Hana field. HANA FIELD -15- On June 23, 1999, TransAtlantic and its partners spudded the Hana-1 exploration well. The Hana-1 well, drilled on the basis of 3-D seismic, resulted in a significant oil discovery. The well encountered over 60 feet of net pay in the Miocene-aged Kareem formation and tested oil at a stabilized rate of 568 Bopd. The Hana-2 appraisal well, drilled in September 1999, encountered the top of the Kareem Sand 47 feet updip from the discovery well. The well was perforated across the entire 76 feet of net pay interval and production tested at a stabilized rate of 2,180 Bopd with zero water cut. The test rate was restricted to the capacity of the bottom hole pump. The higher structural position and thicker contiguous pay interval in the Hana-2 well considerably enhanced the interpretive scope and size of the reservoir. One exploratory well drilled to the south of the Hana field was a dry hole. During the first half of 2000, four additional appraisal wells were successfully drilled and completed. Production from the wells is being trucked to a pipeline approximately ten kilometers away while permanent production facilities are being installed, which will be capable of handling up to 15,000 Bopd. These facilities are expected to be completed in the third quarter of 2000. For the six months ended June 30, 2000, average daily production net to the Company from its West Gharib concession was 1,578 Bopd (241 Bopd net to the Company). The wells are currently producing at an average of 2,473 Bopd (278 Bopd net to the Company). Estimated net proved reserves attributable to this field at December 31, 1999 were 525.9 MMBbls with a PV-10 Value of $7.68 million. TUNISIA During December 1999 and prior to incurring any expenditures, the Company elected to withdraw from its concession in Tunisia in order to focus its available resources on its Egyptian and Nigerian exploration and development opportunities. UNITED STATES The Company owns properties in the United States which are not material to its business. The Company does not have any proved reserved attributable to its U.S. properties. The Company does not have any current exploration plans with respect to its prospects in the United States. DRILLING ACTIVITY TransAtlantic participated in the drilling of six (1.92 net wells) from January 1, 1998 to December 31, 1999:
1999 1998 --------------------------------- ------------------------------- Gross Net Gross Net Wells Wells Wells Wells(1) ----- ----- ----- -------- Exploratory Egypt.................................. 4.00 1.15 -- -- Nigeria................................ -- -- -- -- United States.......................... 1.00 .67 1.00 0.10 ---- ---- ---- ---- Development................................. -- -- -- -- ---- ---- ---- ---- Total....................................... 5.00 1.82 1.00 0.10 ==== ==== ==== ====
(1) For purposes of this table, "net wells" reflects gross wells multiplied by the Company's or its subsidiaries' working interest before payout. Three of the exploratory wells drilled in 1999 were productive, while the one well drilled in 1998 was productive. Since December 31, 1999, the Company has drilled four exploratory wells and four development wells in Egypt, of which six were successful. The Company did not drill any additional wells in Nigeria or the United States. UNDEVELOPED LAND The following table sets forth TransAtlantic's and its subsidiaries' interests in properties on which no producing wells have been drilled as of December 31, 1999: -16-
Gross Acres Net Acres(1) -------------- --------------- Nigeria......................................................................... 212,000 62,700 Egypt........................................................................... 5,102,174 1,306,652 United States................................................................... 17,425 5,635 ====== ===== Total.................................................................. 5,331,599 1,374,987
(1) Calculated based on the Company's after-payout working interest. OIL AND GAS WELLS As of December 31, 1999, TransAtlantic owned interests in six producing oil wells, one producing gas well and one pressure maintenance well. The following table sets forth the producing wells and wells capable of producing in which TransAtlantic and its subsidiaries owned a working interest at December 31, 1999:
OIL WELLS GAS WELLS ----------------------------------------------- -------------------------------------------- PRODUCING SHUT-IN PRODUCING SHUT-IN ----------------------- ----------------------- ----------------------- -------------------- GROSS NET GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- ----- --- Nigeria............................ 3 1.80 - - - - - - Egypt.............................. 2 0.60 - - - - - - United States...................... 1 1.00 1 1.0 1 0.67 - - Total..................... 6 3.40 1 1.0 1 0.67 - -
-17- RESERVES AND FUTURE NET CASH FLOWS The Company's proved reserves and the PV-10 Values attributable to such reserves for the years ended December 31, 1998 and 1999 were estimated by Ryder Scott Company Petroleum Engineers ("Ryder Scott") of Calgary, Alberta, independent petroleum consultants. For the year ended December 31, 1997, the Company's proved reserves and the PV-10 Value attributable to such reserves were estimated by O'Neill Petroleum Consultants.
December 31, ---------------------------------------- 1999 1998 1997(2)(3) ------------ ------------ ------------ NIGERIA(1) PROVED DEVELOPED: Oil (Bbls) ........... 4,246,377 5,670,267 -- Gas (Mcf) ............ -- -- -- PROVED UNDEVELOPED: Oil (Bbls) ........... -- -- 10,866,000 Gas (Mcf) ............ -- -- -- TOTAL PROVED: Oil (Bbls) ........... 4,246,377 5,670,267 10,866,000 Gas (Mcf) ............ -- -- -- PV-10 Value ............. $ 4,568,046 $ 2,189,751 $24,785,000 EGYPT(4) PROVED DEVELOPED: Oil (Bbls) ........... 201,629 -- -- Gas (Mcf) ............ -- -- -- PROVED UNDEVELOPED: Oil (Bbls) ........... 324,319 -- -- Gas (Mcf) ............ -- -- -- TOTAL PROVED: Oil (Bbls) ........... 525,948 -- -- Gas (Mcf) ............ -- -- -- PV-10 Value ............. $ 7,682,324 $ -- $ -- TOTAL(5) PROVED DEVELOPED: Oil (Bbls) ........... 4,448,006 5,670,267 -- Gas (Mcf) ............ -- -- -- PROVED UNDEVELOPED: Oil (Bbls) ........... 324,319 -- 10,866,000 Gas (Mcf) ............ -- -- -- TOTAL PROVED: Oil (Bbls) ........... 4,772,325 5,670,267 10,866,000 Gas (Mcf) ............ -- -- -- PV-10 Value ............. $12,250,370 $ 2,189,751 $24,785,000
--------------- (1) SOGW's indigenous partner has pledged 50% of its 40% interest in OML-109 to SOGW as security for amounts advanced by SOGW during 1996. See "Item 2. Description of Property--Nigeria--The Indigenous Program." This additional 20% interest is included in the reserve volumes and future net cash flows. (2) Effective July 1, 1997, the Company disposed of all of its Canadian oil and gas interests. Accordingly, no reserves are shown attributable to these interests. (3) The reserve report prepared by O'Neill Petroleum Consultants was prepared prior to the commencement of actual production from the Ejulebe field. The reserve report included proved undeveloped gas reserves at December 31, 1997 of 23,012,000 Mcf with no PV-10 Value. Based upon actual production results, the reservoir calculations were revised and the proved oil reserves for the Ejulebe field significantly reduced. The proved gas reserves in the O'Neill Report were written off in 1998 because no infrastructure exists to produce gas offshore Nigeria; accordingly, there is presently no market for gas from OML 109. -18- (4) The Company had an updated reserve report prepared by Ryder Scott as of May 31, 2000 for the Hana field to reflect the results of the wells drilled in the first part of 2000. Proved developed reserves and total proved reserves attributable to the Hana field were 404,342 Mbbls and 764,094 Mbbls, respectively, with an aggregate PV-10 Value of $13,058,596. (5) Does not include minimal proved reserves attributable to the Company's U.S. interests. In general, estimates of economically recoverable oil and natural gas reserves and of the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices and future operating costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The Company's actual production, revenues, severance and excise taxes, and development and operating expenditures, with respect to its reserves will vary from such estimates, and such variances could be material. See "Item 1. Description of Business--Risk Factors." Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. In accordance with applicable requirements of the SEC, the estimated discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. Set forth below are net quantities of oil (including condensate and natural gas liquids) and gas produced by the Company for each of the last three fiscal years. The Company is not a party to any long-term supply on similar agreements with foreign governments or authorities where it is a producer.
December 31, ---------------------------------------- 1999 1998 1997 ------------- -------------- --------- NIGERIA(1) Oil (MBbls) ................. 1,571 417 -- Gas (MMcf) .................. -- -- -- MBOE ........................ 1,571 417 -- EGYPT Oil (MBbls) ................. -- -- -- Gas (MMcf) .................. -- -- -- MBOE ........................ -- -- -- CANADA(2) Oil (MBbls) ................. -- -- 19 Gas (MMcf) .................. -- -- 418 MBOE ........................ -- -- 89 TOTAL(3) Oil (MBbls) ................. 1,571 417 19 Gas (MMcf) .................. -- -- 418 MBOE ........................ 1,571 417 89
----------------------------- (1) SOGW's indigenous partner has pledged 50% of the revenues attributable to its 40% interest in OML-109 to SOGW as security for amounts advanced by SOGW during 1996. See "Item 2--Description of Property--Nigeria--The Indigenous Program." This additional interest is included in the December 31, 1999 reserve report. The above table reflects only SOGW's 60% interest -19- and does not include the quantities attributable to the pledged interest. (2) Effective July 1, 1997, the Company disposed of all of its Canadian oil and gas interests. (3) Does not include minimal production attributable to the Company's U.S. interests. MARKETING AND PRICING The Company's Nigerian production is marketed by CXY to crude purchasers or refiners at market prices, adjusted for transportation and crude quality. The Company's Egyptian production is marketed by EGPC or, at TransAtlantic's option, by the Company, to crude purchasers or refiners at market prices, adjusted for handling charges, transportation and crude quality. The Company's United States natural gas and crude oil production is marketed to aggregators or marketers of crude oil and natural gas, generally under 30 day contracts that renew automatically at market prices. The price received for the Company's production is subject to fluctuation and volatility. See "Item 1. Description of Business--Risk Factors." ITEM 3. LEGAL PROCEEDINGS. Several of the Company's wholly owned subsidiaries (the "Subsidiaries") are parties to a Shareholder Agreement effective February 28, 1997, pertaining to the Company's interest in Tarpon-Benin S.A. ("Tarpon") of which the Company is the indirect majority owner. Tarpon owned a concession in the Republic of Benin. At a meeting of the shareholders in 1998, Tarpon elected to withdraw from the concession and allow the concession agreement to expire; however, a group of minority shareholders (the "Shareholders") objected. The Shareholders, along with the parent company of the Shareholders, initiated arbitration in October, 1998 under the American Arbitration Association. The claimants in the arbitration seek damages in an amount sufficient to perform certain alleged obligations which the claimants contend are required to be performed pursuant to the terms of the Shareholder Agreement, including the acquisition and processing of 500 kilometers of new seismic lines on the concession, an annual training program and a bank guarantee for seismic work. On September 18, 2000, the Company was advised that the arbitrator ruled that the Subsidiaries had breached the Shareholder Agreement and assessed damages of $1,848,359.32. While the Company was not a party to the Shareholder Agreement, the arbitrator ruled that the Company guaranteed all obligations of the Subsidiaries. The Company does not believe that the Subsidiaries have a basis to appeal the decision. However, the Company intends to contest the arbitrator's ruling against the Company. No assurances can be made that the Company will be successful. On the Company's South Fort Stockton Prospect in Pecos County, Texas, the Winfield Ranch #17-1E well was drilled to a total depth of 25,740 feet and was cased and logged. Log analysis indicated a potential for more than 1,100 feet of gross pay in the Ellenburger formation, a highly prolific gas zone in the region and the primary objective of the well. In early December 1998, during operations to clean out the production casing, a string of drill pipe supplied by Weatherford International, Inc. and manufactured by a Weatherford subsidiary parted and became stuck in the bottom section of the hole. Efforts to retrieve the stuck string of drill pipe were not successful. When settlement discussions with Weatherford and its insurer failed to yield an acceptable settlement, the working interest owners together with the operator, Baytech, Inc., filed a lawsuit against Weatherford in state court in Pecos County, Texas on March 3, 1999. Substantial discovery has taken place, and the trial is currently set for December 2000. The lawsuit against Weatherford seeks to require Weatherford to either redrill or pay to redrill another well to the Ellenburger formation. The lawsuit also seeks consequential and exemplary damages. Under its joint operating agreement (the "JOA") with Atlas, the Company, through its wholly owned subsidiary SOGW, owns a 30% interest (60% revenue interest prior to payout) in the remaining 200,000 acres of OML 109 outside the Ejulebe field. In March 2000, SOGW initiated an arbitration in Geneva, Switzerland with the International Chamber of Commerce to resolve certain differences of opinion relating to the interpretation of the JOA. In particular, the Company seeks a declaratory judgment as to how taxes are to be paid, how the bank account is to operate and how the assignment of proceeds to pay the outstanding loans should work. The arbitration proceeding is scheduled to commence in September 2000. Once resolved, the Company anticipates proceeding with further exploration of the remainder of OML 109. In addition, in 1996, SOGW loaned $5.0 million to the Chairman of Atlas, by way of a promissory note, which was guaranteed by Atlas. The note bears interest at LIBOR plus 3% per annum. At July 31, 2000, approximately $6.65 million of principal and interest was outstanding under the note. The note is currently in default. Under the terms of the guarantee, SOGW is entitled to receive 50% of Atlas' share of cash flow from the concession. Since the note is in default, SOGW has additional rights under the loan documents regarding the Atlas share of production. SOGW has initiated proceedings in the High Court of England and Wales in London, England for its collection, and trial is set for early 2001. ITEM 4. CONTROL OF REGISTRANT. The Company records its common shares on its transfer agent's books in registered form. Some of the Company's common shares are registered in the name of intermediaries, such as brokerage houses and clearing houses, on behalf of their clients and, as a result, the -20- Company does not know the identity of the beneficial owners. To the best of the Company's knowledge, it is not directly or indirectly owned or controlled by another corporation or by any foreign government nor is there any arrangement, the operation of which may, in the future, result in a change of control. As of August 31, 2000, the Company is not aware of any person, firm or corporation which beneficially owns, directly or indirectly, or exercises control or direction over, voting securities carrying more than ten percent of the voting rights attached to any class of the securities of the Company. The following table is furnished as of August 31, 2000, to indicate beneficial ownership of the Company's common shares by all executive officers and directors of the Company as a group:
Title of Class Identity of Person or Group Amount Beneficially Owned(1) Percent of Class -------------- --------------------------- ---------------------------- ---------------- Common shares Directors and executive officers 8,701,282(2) 10.96% as a group (9 persons)
------------------- (1) Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and generally includes voting or investment power with respect to securities. Unissued common shares subject to options, warrants or other convertible securities currently exercisable or convertible, or exercisable or convertible within 60 days, are deemed outstanding for the purpose of computing the beneficial ownership of common shares of the person holding such convertible security but are not deemed outstanding for computing the beneficial ownership of common shares of any other person. (2) Includes 4,714,000 common shares issuable upon the exercise of outstanding stock options held by directors and officers as a group. ITEM 5. NATURE OF TRADING MARKET. The common shares of the Company are listed and posted for trading on The Toronto Stock Exchange and trade under the symbol "TNP.U". The following table sets forth the volume of trading, and the high and low sales price per common share for the periods indicated:
Volume High Low ---------- ----- ----- Quarter ended March 31, 1998............................. 2,735,950 $1.45 $0.65 Quarter ended June 30, 1998 ............................. 1,691,400 $0.93 $0.63 Quarter ended September 30, 1998......................... 3,420,641 $1.00 $0.63 Quarter ended December 31, 1998.......................... 4,272,689 $0.78 $0.30 Quarter ended March 31, 1999............................. 2,855,021 $0.50 $0.16 Quarter ended June 30, 1999.............................. 5,969,924 $0.28 $0.15 Quarter ended September 30, 1999......................... 11,602,283 $0.34 $0.12 Quarter ended December 31, 1999.......................... 4,940,968 $0.24 $0.15 Quarter ended March 31, 2000............................. 19,138,305 $0.42 $0.15 Quarter ended June 30, 2000.............................. 7,505,203 $0.25 $0.14
The price of the common shares, as reported by the Toronto Stock Exchange at the close of business on August 31, 2000 was $0.15. The Company's common shares are not traded on an exchange in the United States, and there is no established market in the United States for the Company's common shares. As at August 31, 2000, a total of 79,384,092 of our common shares were issued and outstanding and held by 330 holders of record, of which 47 holders of record, holding 9,128,192 of our common shares, were residents of the United States. The computation of the number of common shares held of record by residents of the United States is based upon the number of common shares held of record by holders with United States addresses. Residents of the United States may beneficially own common shares which are held of record by non-residents of the United States. ITEM 6. EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS. There are no governmental laws, decrees, or regulations in Canada relating to restrictions on the export or import of capital, or affecting the remittance of interest, dividends, or other payments to non-resident holders on the Company's common stock. Any remittances of -21- dividends to United States residents are, however, subject to a 15% withholding tax (5% if the shareholder is a corporation owning at least 10% of the outstanding common stock of the Company) pursuant to Article X of the reciprocal tax treaty between Canada and the United States. See "Item 7 - Taxation." There are presently no applicable limitations specific to the rights of non-Canadians to hold or vote the common stock of the Company under the laws of Canada or the Province of Alberta or in the charter documents of the Company. Although certain such limitations exist in the provisions of the Investment Canada Act, management of the Company considers that they are inapplicable to the Company. The Investment Canada Act requires that a non-Canadian making an investment which would result in the acquisition of control of a Canadian business, the gross value of the assets of which exceed certain threshold levels or the business activity of which is related to Canada's cultural heritage or national identity, to either notify, or file an application for review with, Investment Canada, the federal agency created by the Investment Canada Act. At present, the Company does not have any assets in Canada and therefore does not constitute a Canadian business as that term is defined under the Act and such restrictions are therefore inapplicable. ITEM 7. TAXATION. CERTAIN CANADIAN FEDERAL INCOME TAX CONSEQUENCES Management of the Company considers that the following general summary fairly describes the principal Canadian federal income tax consequences applicable to a holder of common stock of the Company who is a resident of the United States and who is not a resident of Canada and who does not use or hold, and is not deemed to use or hold, his shares of common stock of the Company in connection with carrying on a business in Canada (a "non-resident shareholder"). This summary is based upon the current provisions of the Income Tax Act (Canada) (the "ITA"), the regulations thereunder (the "Regulations"), the current publicly announced administrative and assessing policies of the Canada Customs & Revenue Agency and all specific proposals (the "Tax Proposals") to amend the ITA and Regulations announced by the Minister of Finance (Canada) prior to the date hereof. This description is not exhaustive of all possible Canadian federal income tax consequences and does not take into account or anticipate any changes in law, whether by legislative, governmental or judicial action. DIVIDENDS Dividends paid, or credited, or deemed to be paid or credited, on the common stock of the Company to a non-resident will be subject to withholding tax. The Canada-U.S. Income Tax Convention (1980) (the "Treaty") provides that the normal 25% withholding tax rate is reduced to 15% on dividends paid on shares of a corporation resident in Canada (such as the Company) to residents of the United States, and also provides for a further reduction of this rate to 5% where the beneficial owner of the dividends is a corporation which is a resident of the United States which owns at least 10% of the voting shares of the corporation paying the dividend. Where the dividends are received by a resident of the United States carrying on business in Canada through a permanent establishment in Canada or by a person who performs independent personal services in Canada from a fixed base situated in Canada, and holding of the shares in respect of which the dividends are paid is effectively connected with that permanent establishment, the dividends are generally subject to Canadian tax as business profits or income from rendering such services and the Treaty does not limit the tax payable on such income under the Act. CAPITAL GAINS In general, a non-resident person is subject to tax in Canada at the rates generally applicable to residents of Canada on any "taxable capital gain" arising on the disposition of "taxable Canadian property." Shares of a corporation which are listed on a prescribed stock exchange will only be taxable Canadian property to a non-resident person if, at any time during the five year period immediately preceding the disposition, the non-resident shareholder, either alone or together with persons with whom such non-resident did not deal at arm's length, owned 25 percent or more of the issued shares of any class of series of the capital stock of the corporation, or the non-resident's shares were acquired in a tax deferred exchange in consideration for property that was itself taxable Canadian property. In situations where shares constitute taxable capital property, the taxable portion of a capital gain for dispositions occurring after February 27, 2000, is equal to two-thirds of the amount by which the proceeds of disposition of such shares, net of any reasonable costs associated with the disposition, exceeds the adjusted cost base to the holder of the shares. -22- Article XIII of the Treaty provides that gains realized by a United States resident on the disposition of shares of a corporation that is a resident of Canada, including shares which constitute taxable Canadian property, may not be taxed in Canada unless the value of those shares is derived principally from real property situated in Canada or the shares form part of the business property of a permanent establishment which the resident of the United States has or had in Canada within the 12 month period preceding the date of disposition or if the shares pertain to a fixed base in Canada which is or was available within the 12 month period preceding the date of disposition of the purpose of performing independent personal services. MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS The following discussion summarizes the material United States federal income tax consequences, under current law, generally applicable to a U.S. Holder (as defined below) of the Company's common stock. This discussion does not address consequences peculiar to persons subject to special provisions of federal income tax law, such as tax-exempt organizations, qualified retirement plans, financial institutions, insurance companies, real estate investment trusts, regulated investment companies, broker-dealers, nonresident alien individuals, foreign corporations, or shareholders owning common stock representing 10% of the vote and value of the Company. In addition, this discussion does not cover any state, local or foreign tax consequences. The following discussion is based upon the sections of the Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations, published Internal Revenue Service ("IRS") rulings, published administrative positions of the IRS and court decisions that are currently applicable, any or all of which could be materially and adversely changed, possibly on a retroactive basis, at any time. In addition, this discussion does not consider the potential effects, both adverse and beneficial of recently proposed legislation which, if enacted, could be applied, possibly on a retroactive basis, at any time. The following discussion is for general information only and is not intended to be, nor should it be construed to be, legal or tax advice to any holder or prospective holder of the Company's common stock and no opinion or representation with respect to the United States federal income tax consequences, to any such holder or prospective holder is made. Accordingly, holders and prospective holders of the Company's common stock should consult their own tax advisors about the federal, state, local and foreign tax consequences of purchasing, owning and disposing of shares of common stock of the Company. U.S. HOLDERS As used herein, a "U.S. Holder" is defined as (i) a citizen or resident of the U.S., or any state thereof, (ii) a corporation or other entity created or organized under the laws of the U.S., or any political subdivision thereof, (iii) an estate the income of which is subject to U.S. federal income tax regardless of source, or (iv) a trust whose administration is subject to the primary supervision of a U.S. court and which has one or more U.S. fiduciaries who have the authority to control all substantial decisions of the trust. DISTRIBUTIONS ON SHARES OF COMMON STOCK U.S. Holders receiving dividend distributions (including constructive dividends) with respect to the Company's common stock are required to include in gross income for United States federal income tax purposes the gross amount of such distributions to the extent that the Company has current or accumulated earnings and profits, without reduction for any Canadian income tax withheld from such distributions. Such Canadian tax withheld may be credited, subject to certain limitations, against the U.S. Holder's United States federal income tax liability or, alternatively, may be deducted in computing the U S. Holder's United States federal taxable income by those who itemize deductions. (See more detailed discussion at "Foreign Tax Credit" below.) To the extent that distributions exceed current or accumulated earnings and profits of the Company, they will be treated first as a return of capital up to the U.S. Holder's adjusted basis in the common stock and thereafter as gain from the sale or exchange of such shares. Preferential tax rates for long-term capital gains are applicable to a U.S. Holder which is an individual, estate or trust. There are currently no preferential tax rates for long-term capital gains for a U.S. Holder which is a corporation. Dividends paid on the Company's common stock will not generally be eligible for the dividends received deduction provided to corporations receiving dividends from certain United States corporations. FOREIGN TAX CREDIT A U.S. Holder who pays (or has withheld from distributions) Canadian income tax with respect to the ownership of the Company's common stock may be entitled, at the option of the U.S. Holder, to either a deduction or a tax credit for such foreign tax paid or withheld. Generally, it will be more advantageous to claim a credit because a credit reduces United States federal income taxes on a dollar-for-dollar basis, while a deduction merely reduces the taxpayer's income subject to tax. This election is made on a year-by-year basis and applies to all foreign taxes paid by (or withheld from) the U.S. Holder during that year. Subject to certain limitations, Canadian taxes withheld will be eligible for credit against the U.S. Holder's United States federal income taxes. Under the Code, the limitation on foreign taxes -23- eligible for credit is calculated separately with respect to specific classes of income. Dividends paid by the Company generally will be either "passive" income or "financial services" income, depending on the particular U.S. Holder's circumstances. Foreign tax credits allowable with respect to each class of income cannot exceed the U.S. federal income tax otherwise payable with respect to such class of income. The consequences of the separate limitations will depend on the nature and sources of each U.S. Holder's income and the deductions appropriately allocated or apportioned thereto. The availability of the foreign tax credit and the application of the limitations on the credit are fact specific and holders and prospective holders of common stock should consult their own tax advisors regarding their individuals circumstances. DISPOSITION OF SHARES OF COMMON STOCK A U.S. Holder will recognize gain or loss upon the sale of shares of common stock equal to the difference, if any, between (i) the amount of cash plus the fair market value of any property received; and (ii) the shareholder's tax basis in the common stock. This gain or loss will be capital gain or loss if the shares are a capital asset in the hands of the U.S. Holder, and such gain or loss will be long-term capital gain or loss if the U.S. Holder has held the common stock for more than one year. Gains and losses are netted and combined according to special rules in arriving at the overall capital gain or loss for a particular tax year. Deductions for net capital losses are subject to significant limitations. For U.S. Holders who are individuals, any unused portion of such net capital loss may be carried over to be used in later tax years until such net capital loss is thereby exhausted. For U.S. Holders which are corporations (other than corporations subject to Subchapter S of the Code), an unused net capital loss may be carried back three years from the loss year and carried forward five years from the loss year to be offset against capital gains until such net capital loss is thereby exhausted. OTHER CONSIDERATIONS The Company has not determined whether it meets the definition of a "passive foreign investment company" (a "PFIC"). It is unlikely that the company meets the definition of a "foreign personal holding company" (a "FPHC") or a "controlled foreign corporation (a "CFC") under current U.S. law. If more than 50% of the voting power or value of the Company were owned (actually or constructively) by one or more U.S. Holders who each owned (actually or constructively) 10% or more of the voting power of the Company's common shares ("10% Shareholders"), then the Company would become a CFC and each 10% Shareholder would be required to include in its taxable income as a constructive dividend an amount equal to its share of certain undistributed income of the Company. If (1) more than 50% of the voting power or value of the Company's common shares were owned (actually or constructively) by five or fewer individuals who are citizens or residents of the United States and (2) 60% or more of the Company's gross income consisted of certain interest, dividend or other enumerated types of income, then the Company would be a FPHC. If the Company were a FPHC, then each U.S. Holder (regardless of the amount of the Company's common shares owned by such U.S. Holder) would be required to include in its taxable income as a constructive dividend its share of the Company's undistributed income of specific types. If 75% or more of the Company's annual gross income has ever consisted of, or ever consists of, "passive" income or if 50% or more of the average value of the Company's assets in any year has ever consisted of, or ever consists of, assets that produce, or are held for the production of, such "passive" income, then the Company would be or would become a PFIC. If the Company were to be a PFIC, then a U.S. Holder would be required to pay an interest charge together with tax calculated at maximum tax rates on certain "excess distributions" (defined to include gain on the sale of stock) unless such U.S. Holder made an election either to (1) include in his or her taxable income certain undistributed amounts of the Company's income or (2) mark to market his or her Company common shares at the end of each taxable year as set forth in Section 1296 of the Code. INFORMATION REPORTING AND BACKUP WITHHOLDING U.S. information reporting requirements may apply with respect to the payment of dividends to U.S. Holders of the Company shares. Under Treasury regulations currently in effect, non-corporate holders may be subject to backup withholding at a 31% rate with respect to dividends when such holder (1) fails to furnish or certify a correct taxpayer identification number to the payor in the required manner, (2) is notified by the IRS that it has failed to report payments of interest or dividends properly or (3) fails, under certain circumstances, to certify that it has not been notified by the IRS that it is subject to backup withholding for failure to report interest and dividend payments properly. -24- ITEM 8. SELECTED FINANCIAL DATA. The selected financia1data presented in the table below for the quarterly periods ended June 30, 2000 and 1999, and the five fiscal years ended December 31, 1999, are derived from the Company's consolidated financial statements. This data includes the accounts of the Company and its wholly-owned subsidiaries for periods owned by the Company. The following selected financial data is qualified by reference to, and should be read in conjunction with, the consolidated financial statements and related notes included elsewhere in this Form 20-F. Reference is also made to "Item 9 - Management's Discussion and Analysis of Financial Condition and Results of Operations." The selected consolidated financial data as at December 31, 1997, 1996 and 1995 and for the two years ended December 31, 1996 are derived from audited consolidated financial statements that are not included herein. The selected financial data as at June 30, 2000 and 1999 and for the six months ended June 30, 2000 and 1999 are unaudited. However, these interim financial statements have been prepared on the same basis as the audited annual financial data and in the opinion of management, contain all adjustments necessary for a fair presentation of the financial position and results of operations for such periods. The results of operations for the six months ended June 30, 2000 are not necessarily indicative of results to be expected for a full fiscal year. TransAtlantic follows the full cost method of accounting for oil and gas operations.
Six Months Ended June 30 Year ended December 31 ---------------------- ----------- ----------- --------- ---------- ---------- 2000 1999 1999 1998 1997 1996 1995 ---- ---- ---- ---- ---- ---- ---- (in thousands of U.S. dollars, except per share amounts) Oil and gas revenues.................. $18,584 $10,198 $21,999 $3,391 $636 $1,485 $1,290 Cash from (used in) operating 210 (1,104) (595) (1,352) 763 (354) 228 activities ........................... Per share........................... - (0.02) (0.01) (0.04) (0.02) (0.01) 0.01 Net loss.............................. 825 1,392 2,888 12,686 12,368 713 1,731 Per share........................... 0.01 0.02 0.05 0.35 0.37 0.03 0.07 Dividends per share................... - - - - - - - Total assets.......................... 16,547 15,701 15,645 21,488 28,543 26,579 19,233 Long term debt........................ - - - - 5,906 - 1,960 Shareholders' equity.................. 12,480 11,655 11,059 10,798 15,347 26,294 16,440 Capital expenditures.................. 1,952 1,708 3,920 2,838 13,659 6,124 7,962 Acquisition of GHP.................... - - - 9,105 - - - Proceeds on disposition of oil and gas properties............................ - - 109 3,877 4,131 394 -
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES: The Company's consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada ("Canadian GAAP"). These principles, as they pertain to the Company's consolidated financial statements, are not materially different from United States' generally accepted accounting principles ("US GAAP"), except as follows: (a) There are certain diferences between the full cost method of oil and gas accounting as applied in Canada and as applied in the United States. The Company has reviewed such differences and determined that, except as discussed below, no material variances in financial statement balances would have resulted from the applicaiton of full cost accounting in accordance with US GAAP. The Company has completed ceiling test calculations in accordance with US GAAP at December 31, 1999, 1998 and 1997. The ceiling tests computed under US GAAP did not result in any differnces as at Decebmer 31, 1999 and 1997. However, at December 31, 1998 the US GAAP ceiling test results in an additional impairment of $488. This difference would increase the Company's net loss for the year ended December 31, 1998 and would reduce the Company's total assets and shareholders' equity at December 31, 1998 and subsequent periods. -25- (b) In accordance with US GAAP, the liability method of accounting for income taxes is used instead of the deferral method. Under the liability method, current and deferred income taxes are recognized at currently enacted rates to reflect the expected future tax consequences arising from the difference between transactions recorded in the financial statements and those in income tax returns. In addition, purchase price adjustments arising from business combinations are grossed up for the related income tax impact under US GAAP. No adjustments to the financial statements are required with respect to the accounting for income taxes. (c) The Company applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees", and related interpretations, in accounting for its stock options issued to employees, directors and officers of the Company for purposes of reconciliation to US GAAP. As such, compensation expense would be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, "Accounting for Stock-based Compensation", established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensations plans. As allowed by SFAS No. 123, the Company has elected to continue to apply the intrinsic value-based method of accounting described above and has adopted the disclosure requirements of SFAS No. 123. Stock options issued to third parties are accounted at their fair values in accordance with SFAS No. 123. No adjustments to the financial statements are required with respect to the accounting for stock options, except for the inclusion of additional disclosures below. During the periods ended June 30, 2000, and December 31, 1999 and 1998, the Company granted options to employees, directors and officers which, for purposes of reconciling to US GAAP, have been accounted for in compliance with APB Opinion No. 25. All were granted with exercise prices at the market price of the Company's stock on the date of grant. Accordingly, no compensation expense is recorded in the Company's statement of operations and deficit. The Company has calculated the fair value of stock options granted to employees using the Black-Scholes option pricing model with the following weighted-average assumptions:
June 30 December 31, ------- -------------------- 2000 1999 1998 ------- ------- ------- Risk free interest rate.................. 5.75% 5.55% 5.15% Volatility............................... 5.27% 6.13% 5.27% Expected option life (in years).......... 4.5 4.5 4.5 Dividend Yield........................... 0% 0% 0%
Had the Company determined compensation cost based upon the fair value at the grant date for its stock options under SFAS No. 123, the Company's net income and loss per share amounts would have been reduced to the pro forma amounts indicated below:
June 30 December 31, ------- -------------------- 2000 1999 1998 ------- ------- ------- Net loss under US GAAP: As reported........................ $825 $2,888 $12,686 Pro forma.......................... $834 $3,040 $12,999 Net loss per common share: As reported........................ 0.01 0.05 0.35 Pro forma.......................... 0.01 0.05 0.36
(d) The reduction in stated capital recorded during 1998 under Canadian GAAP would have to be reversed under US GAAP. As a result, the Company's shareholders' equity under US GAAP at December 31, 1998 and subsequent periods would be restated as follows: -26-
June 30 December 31, ------- --------------------- 2000 1999 1998 ------- ------- ------- Share capital............................ $43,757 $41,511 $38,362 Deficit.................................. (31,277) (30,452) (27,564) ------ ------ ------ $12,480 $11,059 $10,798 ====== ====== ======
(e) Supplementary disclosures required under US GAAP are as follows:
Six Months Ended JUNE 30 DECEMBER 31, 2000 1999 1998 ------------------- ---------- ------------ Cash interest paid.................................... - - - Cash taxes paid....................................... - - - Components of change in non-cash working capital: Restricted cash............................ $355 $1,187 - Accounts receivable........................ 47 167 49 Accounts payable and accrued liabilities... 31 (583) 79 Other...................................... (24) 82 (475) $410 $853 (347) === === ===
(f) Additional Disclosures Required Under US GAAP: The components of accounts payable and accrued liabilities are as follows:
June 30 December 31, ------------ ----------------------- 2000 1999 1998 ------------ ---------- ----------- Accounts payable........................... $501 $494 $647 Accrued liabilities........................ 446 1,210 874 $947 $1,704 $1,521 === ===== =====
ITEM 9. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. OVERVIEW On December 1, 1998, the Company's predecessor, Profco Resources Ltd., acquired GHP Exploration Corporation in an amalgamation transaction. The resulting enterprise was renamed TransAtlantic Petroleum Corp. The GHP acquisition provided a working capital infusion of $1.9 million and brought international exploration prospects in Egypt, Tunisia and the United States. The year ended December 31, 1999 was the first full year of operations of TransAtlantic Petroleum Corp. following the acquisition of GHP. In December 1999, the Company relinquished its interest in Tunisia. In September 1998, production from the Company's Nigerian operations commenced. The Hana oil discovery in Egypt in July 1999 represented a significant milestone in TransAtlantic's history. First oil sales occurred in late December 1999. The field has been developed in the first half of 2000, and it is expected to provide cash flow to offset a portion of the Company's ongoing exploration and development projects for the foreseeable future. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our results of operations in the future. -27- The following discussion should be read in conjunction with the Company's consolidated financial statements and notes thereto included as an exhibit to this registration statement. RESULTS OF OPERATIONS SIX MONTHS ENDED JUNE 30, 2000 AND SIX MONTHS ENDED JUNE 30, 1999 Total revenues for the first six months of 1999 and 2000 were $10.5 million and $18.7 million, respectively. The increase in revenues reflects the higher price per barrel received in the first six months of 2000 and the commencement of production from the Company's Hana field in the West Gharib concession, Egypt. Production from two Hana wells commenced at the end of 1999 with first sales being booked in 2000. An additional four wells were placed on production in the second quarter. For the six months ended June 30, 2000, the Hana field production averaged 241 Bopd net to the Company. This production helped the Company achieve improved operating income and operating cash flow for the period ended June 30, 2000, compared to the same period in 1999. Cash flow provided to the Company from the Hana field was used to partially pay for the developmental drilling on the Hana field. Although production and costs at the Ejulebe field offshore Nigeria remain relatively constant, the revenues from the Ejulebe field continue to be dedicated to payment of the service fee to the service contractor. This will continue until the capital component of the service fee has been reduced, at which point the Company will begin to share in a portion of the profits from the field. A minimum payment of $34,000 per month is paid by CXY Oilfield Services Nigeria, Ltd., the service contractor. This minimum payment revenue effectively pays the overhead costs of the Company's operations in Nigeria. OIL AND GAS SALES The Company commenced receiving revenues from production from the Hana field in the West Gharib Concession in Egypt in 2000. Production averaged 1,578 Bopd (to the 100% interest) in the first six months of 2000 from the Hana wells. Revenues net to the Company from the Hana field were $1.93 million in the period ending June 30, 2000; after payment of production taxes and operating expenses, the Company received $880,297. In the first six months of 2000, oil and gas sales from both the Ejulebe field and Hana field totaled $18.5 million, significantly more than the $10.2 million in the first half of 1999. This is attributable to the Hana field coming on stream and the higher price per barrel being realized on the sale of the Ejulebe crude. A portion of the revenues represents SOGW's 60% share of revenue from the Ejulebe field, less the royalty payable to the Nigerian government as well as an additional 20% share of revenue from the Ejulebe field the Company receives to apply against a promissory note owed by the Chairman of SOGW's Nigerian partner. During the period ended June 30, 2000 and 1999, the Company sold 745,412 and 952,706 barrels (net) produced from the Ejulebe field at average prices of $26.86 and $12.76, respectively. During the period ended June 30, 2000, the Company sold 43,948 barrels (net) produced from the Hana field at an average price of $21.18. The increased average sales price for production in 2000 reflects the increase in world oil prices in 2000 from prices in 1999. Due to the method by which the Nigerian government calculates royalty payments, SOGW also receives, in addition to the minimum revenue payment due from CXY discussed above, its 60% share of the difference between the royalty paid to the government and 18.5% of the actual sales price received for the crude oil sold. SOGW's share of this differential totaled approximately $0.08 million for the six months ended June 30, 2000 and $0.14 million for the six months ended June 30, 1999. PRODUCTION EXPENSES Production costs for the first six months of 2000 were $18.098 million as compared to $10.396 million for the first six months of 1999. Production costs for the Ejulebe field for the six months ended June 30, 2000 and June 30, 1999 consist of the service fee payable to CXY ($16.3 million in 2000 and $9.9 million in 1999) and other production related costs ($0.35 million in 2000 and $0.36 million in 1999). Both the service fee and other production costs for the first quarter of 1999 and 2000 relate primarily to the Ejulebe field operations in Nigeria. The large increase in production expense during 2000 reflects the start-up of production from the Hana field. Operating costs at the Hana field averaged $2.36 per barrel which includes transportation and terminalling costs. DEPRECIATION, DEPLETION AND AMORTIZATION -28- The provision for depreciation, depletion and amortization ("DD&A") is a function of the total costs of exploring, developing and placing on stream crude oil and natural gas properties, production from the properties and the proven reserves assigned to the properties throughout the year and also depreciation and amortization of non-oil and gas assets. During the six months ended June 30, 1999 and 2000, the Company recorded DD&A expense of $0.55 million and $0.6 million, respectively. DD&A expense for the first half of 2000 consisted of $0.29 million attributable to Nigerian operations, $0.28 million attributable to Egyptian operations with the remainder attributable to amortization of other Company assets. DD&A expense for the first half of 1999 consisted of $0.43 million attributable to Nigerian operations, $0.10 million attributable to amortization of the premium paid on the 7% Convertible Debentures due September 3, 1999 prior to redemption in 1999, with the remainder attributable to depreciation of other assets. LOSS ON DISPOSITION OF PROPERTY AND EQUIPMENT No significant dispositions were recorded in the first half of 2000 or the first half of 1999. GENERAL AND ADMINISTRATIVE EXPENSES As of June 30, 1999, the Company had cost centers for general and administrative expenses in Nigeria, the United States and Canada. As of December 31, 1999, the Company added the Egyptian cost center. All of the general and administrative charges in Nigeria for personnel and facilities were either capitalized or recorded as part of production expenses as they either related to exploration activities or were incurred in connection with producing activities from the Ejulebe field. In Canada and the United States, certain costs that related to the Company's international operations have been allocated to the applicable subsidiary and capitalized or charged to the operations of that country. Those costs which cannot be allocated to a specific country or which relate to revenue producing operations have been charged to general or administrative expenses. Total general and administrative expense and that portion allocated to oil and gas property is recapped in the following table:
Six Months Ended June 30, -------------------------- 2000 1999 --------- --------- (in thousands) Expenses prior to capitalization: Canada............................. $ 224 $ 284 Nigeria............................ 387 434 Egypt.............................. 196 124 United States...................... 406 491 ------ ------ Total......................... $1,213 $1,333 ====== ====== Capitalized costs directly related to geological and geophysical activites: Canada............................. -- -- Nigeria............................ (288) (434) Egypt.............................. (185) (124) United States...................... (27) (87) -- -- Total......................... (500) (645) ------ ------ General and administrative expense: $ 713 $ 688 ====== ======
INTEREST AND OTHER EXPENSE The Company recorded interest and other expense of $0.16 million for the six months ended June 30, 2000 and $0.13 million for the six months ended June 30, 1999. Interest and other expense in these periods in 1999 and 2000 consisted primarily of accrued interest related to the note payable to GMISI. YEAR ENDED DECEMBER 31, 1999 AND YEAR ENDED DECEMBER 31, 1998 -29- Comparison of the Company's results of operations for the years ending December 31, 1998 and December 31, 1999 is difficult because of the change in asset structure between the two years. Revenues and expenses for the year ended December 31, 1998 reflected 11 months of operations as Profco; during this period the principal asset of the Company was the Nigerian property which was not in commercial operation until September 1998. As of December 1, 1998, the Company acquired GHP and therefore oil and gas revenues from the GHP oil and gas assets for the month of December 1998 are included in the revenues and expenses for the year ending December 31, 1998. In December 1998, a substantial portion of GHP's United States assets were sold for $3.8 million and that property sale is reflected in the year ending December 1998. Total revenues for the years ended December 31, 1998 and 1999 were $3.7 million and $22.6 million, respectively. Revenues increased during 1999 as a result of production from the Ejulebe Field. Included in 1999 revenues is $3.8 million reimbursed to the Company from CXY for prior costs in connection with development of the Ejulebe field offshore Nigeria. See "Other" below. OIL AND GAS SALES The Company's oil and gas revenues and related production costs in 1999 and 1998 were primarily comprised of the Company's share of revenue and production expenses from the Ejulebe field offshore Nigeria. This field came on stream in September 1998 and the first crude lifting occurred in December 1998. In 1999, crude liftings occurred every month or in some cases, every other month. Although crude production commenced from the Hana field in Egypt in December 1999, no revenues for Hana crude oil sales were recorded in 1999. Oil and gas sales for 1999 and 1998 totaled $22.0 million and $3.4 million, respectively, and represent SOGW's 60% share of revenue from the Ejulebe field, less the royalty payable to the Nigerian government, as well as an additional 20% share of revenue from the Ejulebe field the Company receives to apply against a promissory note owed by the chairman of SOGW's Nigerian partner. During the years ended December 31, 1999 and 1998, the Company sold 1,571,200 and 416,500 barrels (net to SOGW's 60% interest) at average prices of $16.75 and $9.75, respectively. The increased production in 1999 reflects a full year of production. The increased average sales price for production in 1999 reflects the increase in world oil prices in 1999 from prices in 1998. Due to the method by which the Nigerian government calculates royalty payments, SOGW also receives, in addition to the minimum revenue payment due from CXY discussed above, its 60% share of the difference between the royalty paid to the government and 18.5% of the actual sales price received for the crude oil sold. SOGW's share of this differential totaled approximately $0.22 million for 1999 and $0.07 million for 1998. PRODUCTION EXPENSES Production costs for the years ended December 31, 1999 and December 31, 1998 consist of the service fee payable to CXY for operation of the Ejulebe field ($21.5 million in 1999 and $3.1 million in 1998) and other production related costs ($0.97 million in 1999 and $0.2 million in 1998). Both the service fee and other production costs for 1999 and 1998 relate primarily to the Ejulebe field operations in Nigeria. The large increase in production expense during 1999 reflects increased production from the Ejulebe field. DEPRECIATION, DEPLETION AND AMORTIZATION During the years ended December 31, 1999 and December 31, 1998, the Company recorded DD&A expense of $0.8 million and $1.1 million, respectively. DD&A expense for 1999 consisted of $0.65 million attributable to Nigerian operations, $0.1 million attributable to amortization of the Company's 7% Convertible Debentures due September 3, 1999 prior to redemption in 1999 and $0.05 million attributable to depreciation of corporate office equipment. DD&A expense for 1998 consisted of $0.8 million attributable to Nigerian operations, $0.15 million attributable to amortization of the premium paid on the 7% Convertible Debentures due September 3, 1999 and $0.14 million attributable to depreciation of office equipment. LOSS ON DISPOSITION OF PROPERTY AND EQUIPMENT No significant dispositions were recorded in 1999. The 1998 loss on disposition of property and equipment consists of a $0.14 million loss on the sale of marketable securities and a $0.6 million loss on the sale of miscellaneous office equipment. ADJUSTMENT OF OIL AND GAS PROPERTIES Companies in the oil and gas industry utilizing the full cost method of accounting are required to undergo a ceiling test quarterly, -30- on a country by country basis. The ceiling test calculation estimates future net revenues from proven reserves, based on current prices, together with the cost of unproven properties, with a reduction for future site restoration costs (where applicable), general and administrative expenses, financing costs and income taxes. The result is then compared to the current net book value of their crude oil and natural gas properties. If the calculation results in a deficiency, companies are required to reduce current year's earnings by a corresponding amount. During the years ended December 31, 1999 and December 31, 1998, the Company recorded writedowns of $0.89 million and $10.4 million, respectively. In 1998, the Company abandoned the Sud Nefta concession in Tunisia and the concession in Benin and wrote off $2 million of costs. The $0.16 million writedown recorded in 1999 relates to additional costs incurred in abandoning the Sud Nefta concession. In addition, during 1998 the Company recorded a writedown of $8.4 million in the value of its Nigerian oil and gas assets. This writedown was due to the decrease in reserve value as a result of historically low crude prices for the Ejulebe field at December 31, 1998. At current production rates, the Ejulebe field is not operating at a breakeven rate and SOGW is receiving only the guaranteed minimum revenue payment and royalty differential. With no assurance that the production rate can be increased or sustained, the Company was unable to record any increase to its reserve value attributable to these variables. However, it is possible if production rates remain steady and the crude price for the Ejulebe crude remains above $25 per barrel, that SOGW could begin receiving revenues in year 2001. GENERAL AND ADMINISTRATIVE EXPENSES As of December 31, 1999 and 1998, the Company had cost centers for general and administrative expenses in Nigeria, the United States and Canada. As of December 31, 1999, the Company added the Egyptian cost center. All of the general and administrative charges in Nigeria for personnel and facilities were either capitalized or recorded as part of production expenses as they either related to exploration activities or were incurred in connection with producing activities from the Ejulebe field. In Canada and the United States, certain costs that related to the Company's international operations have been allocated to the applicable subsidiary and capitalized or charged to the operations of that country. Those costs which cannot be allocated to a specific country or which relate to revenue producing operations have been charged to general or administrative expenses. Total general and administrative expense and that portion allocated to oil and gas property is recapped in the following table:
Years Ended December 31, ----------------------------- 1999 1998 ------- -------- (in thousands) Expenses prior to capitalization: Canada.................................................................. $ 393 $ 767 Nigeria................................................................. 820 1,286 Egypt................................................................... 262 -- United States........................................................... 730 104 ------- ------- Total...................................................... 2,205 2,157 ======= ======= Capitalized costs directly related to geological and geophysical activities: Canada.................................................................. (92) (274) Nigeria................................................................. (727) (1,286) Egypt................................................................... (262) -- ------- ------- Total...................................................... (1,179) (1,560) ======= ======= General and administrative expenses.......................................... $ 1,026 $ 597 ======= =======
The increase in general and administrative expenses between 1998 and 1999 is attributable to the acquisition of GHP and the consequent increase in foreign operations. The 1998 total consists only of the Profco operations whereas 1999 includes Egypt and the United States as well as corporate expenses. INTEREST AND OTHER EXPENSE The Company recorded interest and other expense of $0.3 million for the year ended December 31, 1999 and $0.8 million for the -31- year ended December 31, 1998. Interest and other expense in 1999 consisted primarily of accrued interest related to the note payable to GMISI. Interest and other expense for the year ended December 31, 1998 included $0.24 million in accrued interest relating to the note payable to GMISI, but also included $0.4 million of interest relating to the 7% Convertible Debentures due September 3, 1999 which were issued in September 1997 and redeemed in April 1999. The balance of interest and other expense for 1998 related primarily to impairment of marketable securities. OTHER The Company received cash of $3.8 million in the first quarter of 1999 from CXY as reimbursement of prior costs incurred in the Ejulebe field in Nigeria. The terms of the service contract with CXY required CXY to fund the drilling, completion and equipment costs of the Ejulebe field, incur certain other expenditures and reimburse SOGW for $10 million of prior costs incurred upon the Ejulebe field reaching one million barrels of cumulative oil production. During 1996, CXY advanced $5 million to SOGW as a loan bearing interest at LIBOR plus 3% per annum in respect of the service contract. The net payment of $3.8 million received in 1999 represents the $10 million payment less the principal and accrued interest due on the advance made during 1996. YEAR ENDED DECEMBER 31, 1998 AND YEAR ENDED DECEMBER 31, 1997 Revenues and production expenses for the year ended December 31, 1997 reflected the six month results from the Company's Canadian oil and gas assets which were sold effective June 30, 1997, resulting in the 1997 loss on disposition of property and equipment of $2.3 million. The Company's corresponding amounts for 1998 primarily represented SOGW's share of revenue and production costs from the Ejulebe field offshore Nigeria that came on stream during September 1998. Total revenues for the years ended December 31, 1998 and 1997 were $3.39 million and $0.64 million, respectively. Revenues increased during 1998 as a result of the commencement of production from the Ejulebe field. OIL AND GAS SALES The Company's oil and gas revenues and related production costs in 1998 were primarily comprised of revenues from the sale of production from the Ejulebe field, as well as an additional 20% share of revenue from the Ejulebe field the Company receives to apply against a promissory note owed by the Chairman of SOGW's Nigerian partner. The Company's oil and gas revenues and related production costs in 1997 were comprised of revenues from the Company's Canadian oil and gas assets which were sold effective June 30, 1997. Oil and gas sales for 1998 and 1997 totaled $3.39 million and $0.64 million, respectively. During the year ended December 31, 1998, the Company sold 416,500 Bbls (net to SOGW's 60% interest) at average price of $9.75 per barrel. The increased production in 1998 reflects the start-up of the Ejulebe field. PRODUCTION EXPENSES Production costs for the years ended December 31, 1998 ($3.3 million) and December 31, 1997 ($0.2 million) consist of production expenses for the Ejulebe field in 1998 and for the Canadian oil and gas properties in 1997. The increase in production expense during 1998 reflects the payment of the service fee to the service contractor for the Ejulebe field. DEPRECIATION, DEPLETION AND AMORTIZATION During the years ended December 31, 1998 and December 31, 1997, the Company recorded DD&A expense of $1.1 million and $0.55, respectively. DD&A expense for 1998 consisted of $0.8 million attributable to Nigerian operations, $0.15 million attributable to amortization of the premium paid on the 7% Convertible Debentures due September 3, 1999 and $0.15 million attributable to depreciation of office equipment. DD&A expense for 1997 consisted of the expense associated with the Company's Canadian properties and to depreciation of office equipment. LOSS ON DISPOSITION OF PROPERTY AND EQUIPMENT The 1998 loss on disposition of property and equipment consists of a $0.14 million loss on the sale of marketable securities and a $0.6 million loss on the sale of miscellaneous office equipment. The 1997 loss on disposition of property and equipment consists of a $2.3 million loss on the sale of the Company's Canadian oil and gas assets. ADJUSTMENT OF OIL AND GAS PROPERTIES -32- Companies in the oil and gas industry are required to undergo a ceiling test quarterly, on a country by country basis. The ceiling test calculation estimates future net revenues from proven reserves, based on current prices, together with the cost of unproven properties, with a reduction for future site restoration costs (where applicable), general and administrative expenses, financing costs and income taxes. The result is then compared to the current net book value of their crude oil and natural gas properties. If the calculation results in a deficiency, companies are required to reduce current year's earnings by a corresponding amount. During the years ended December 31, 1998 and December 31, 1997, the Company recorded writedowns of $10.4 million and $9.6 million, respectively. In 1998, the Company abandoned the Sud Nefta concession in Tunisia and the concession in Benin and wrote off $2 million of costs. In addition, during 1998 the Company recorded a writedown of $8.4 million in the value of its Nigerian oil and gas assets. This writedown was due to the decrease in reserve value as a result of historically low crude prices for the Ejulebe field at December 31, 1998. The $9.6 million writedown recorded in 1997 relates to the Company's Sud Nefta concession in Tunisia and the Benin concession as a result of drilling a non-commercial well on each of the prospects. GENERAL AND ADMINISTRATIVE EXPENSES As of December 31, 1998 and 1997, the Company had cost centers for general and administrative expenses in Nigeria, the United States and Canada. All of the general and administrative charges in Nigeria for personnel and facilities were either capitalized or recorded as part of production expenses as they either related to exploration activities or were incurred in connection with producing activities from the Ejulebe field. In Canada and the United States, certain costs that related to the Company's international operations have been allocated to the applicable subsidiary and capitalized or charged to the operations of that country. Those costs which cannot be allocated to a specific country or which relate to revenue producing operations have been charged to general or administrative expenses. Total general and administrative expense and that portion allocated to oil and gas property is recapped in the following table:
Years Ended December 31, ---------------------------------- 1998 1997 ------------- ------------ (in thousands) Expenses prior to capitalization: Canada.............................................................. $ 767 $ 491 Nigeria............................................................. 1,286 1,143 Egypt............................................................... - - United States....................................................... 104 - ------------- ------------ Total...................................................... 2,157 1,634 ============= ============ Capitalized costs directly related to geological and geophysical activities: Canada.............................................................. (274) (45) Nigeria............................................................. (1,286) (1,143) Egypt............................................................... - - United States....................................................... - - Total...................................................... (1,560) (1,188) General and administrative expenses.......................................... $ 597 $ 446 ============= ============
The increase in general and administrative expenses between 1998 and 1997 is primarily attributable to overhead increases associated with the amalgamation of Profco with GHP Exploration. The 1997 general and administrative expenses consist only of Profco operations which were localized in Canada and Nigeria. INTEREST AND OTHER EXPENSE The Company recorded interest and other expense of $0.8 million for the year ended December 31, 1998 and $0.15 for the year ended December 31, 1997. Interest and other expense for the year ended December 31, 1998 included $0.24 million in accrued interest relating to the note payable to Global Marine Integrated Services - International Inc., but also included $0.4 million of interest relating to the 7% Convertible Debentures due September 3, 1999 which were issued in September 1997 and redeemed in April 1999. The balance of interest and other expense for 1998 related primarily to impairment of marketable securities. Interest and other expense in 1997 consisted primarily of interest relating to the 7% Convertible Debentures due September 3, 1999 which -33- were issued in September 1997. LIQUIDITY AND CAPITAL RESOURCES CAPITAL SOURCES The Company has historically funded its operations, acquisitions, exploration and development expenditures from cash flows from operating activities, issuance of debt and equity securities and sales of non-strategic assets and oil and gas properties. On May 31, 2000, the Company completed a brokered private placement totaling 1.6 million units with gross proceeds of approximately $304,000. Each unit cost $0.19 and consisted of one common share and 0.6 common share purchase warrant. A whole warrant is exercisable at $0.25 until May 31, 2001. In connection with the placement, the Company paid costs of $8,156. The funds from this placement were used for general corporate purposes. On January 28, 2000, the Company completed a brokered private placement totaling 10 million units with gross proceeds of approximately $2 million. Each unit cost $0.20 and consisted of one common share and one-half common share purchase warrant. A whole warrant is exercisable at $0.25 until January 31, 2001. In connection with the placement, the Company paid costs of $0.163 million and issued one million warrants to the broker exercisable at $0.25 per share on or before January 31, 2001. The funds from this placement were used primarily to fund the four well drilling program on the Central Sinai concession and the development drilling on the West Gharib concession and for general corporate purposes. As a result of payments to GMISI and the redemption of outstanding debentures, the Company reduced its total principal and related accrued interest due on outstanding debt from $9.2 million at December 31, 1998, to $2.9 million at December 31, 1999. Because of interest payable on the GMISI debt, the outstanding debt at June 30, 2000 was $3.12 million. At December 31, 1999, the Company had a working capital deficiency of $3.5 million consisting primarily of approximately $2.85 million of principal and accrued interest attributable to the note payable to GMISI. At June 30, 2000, the Company had a working capital deficiency of $3.34 million; although there was additional interest on the note payable to GMISI, cash flow from the Hana field was used to pay for the expenditures on the Company's drilling programs in Egypt. Throughout 1999 and the first half of 2000, the Company had ongoing discussions with GMISI with respect to amounts due under the outstanding note payable that has been guaranteed by the Company. On August 24, 2000, the Company and GMISI entered into a settlement agreement that provides that the entire obligation can be satisfied if the Company pays GMISI $1.5 million before November 22, 2000, subject to certain regulatory approvals. If not paid, the entire note amount ($3.12 million at June 30, 2000) plus accrued interest is converted to long term debt bearing interest at 12% per annum and payable in monthly installments of $75,000 per month. On July 21, 1999, the Company completed a private placement of 4.65 million special warrants at $ 0.20 per unit for gross proceeds of $0.93 million. Each special warrant consisted of one common share and one-half of a common share purchase warrant. A whole purchase warrant entitles the purchaser to purchase one common share at $0.25 on or before December 31, 2000. The net proceeds were used to fund the ongoing exploration activities in Egypt and for general corporate purposes. On May 17, 1999, the Company redeemed its outstanding Cdn. $9 million of 7% Convertible Debentures due September 3, 1999 in exchange for the payment of $3.65 million in cash and the issuance of approximately 9.15 million common shares of TransAtlantic at a deemed price of $0.25 per share. CAPITAL EXPENDITURES AND COMMITMENTS In the first half of 2000, the Company incurred $2.0 million in capital expenses as compared to $1.7 in the first half of 1999. This increase is due to the increased activities on the Egyptian concessions. The Company incurred $3.9 million and $11.9 million in capital expenditures during 1999 and 1998, respectively. Of the 1999 amount, $2.7 million was incurred on the Egyptian concessions, $0.63 million was incurred in Nigeria and the U.S. and the balance represents capitalized costs. Of the 1998 amount, $9.1 million was incurred in the acquisition of GHP through the issuance of 19.0 million common shares. The remaining $2.8 million was incurred primarily on the Company's Nigerian concession and its abandoned Benin and Sud Nefta concessions. These costs were financed through existing working capital. -34- The Company has total remaining commitments on its Central Sinai concession and on its West Gharib concession, both located in Egypt, of approximately $0.1 million and expects to incur an additional $0.5 million over the next 6 months, excluding general and administrative expenses. In addition, the Company expects to incur additional expenses in the West Gharib concession to drill additional development wells and install production facilities. To meet its debt obligations and outstanding capital commitments for calendar year 2000, the Company will be required to use existing cash on hand and cash flow from operations, negotiate outstanding amounts due and obtain additional debt or equity financing. There can be no assurance that the Company will be able to continue to meet its obligations on the above commitments. See "Item 1. Description of Business-Risk Factors." FUTURE FINANCIAL CONDITION The Company's future financial condition and ability to provide value to its shareholders is contingent on the extent of the recoverable reserves from the Hana and Ejulebe fields, the discovery of other economically recoverable reserves, its ability to restructure or refinance its existing debt obligations and its ability to raise additional exploration and development capital. Success is also dependent on oil and gas product prices, the cost of acquiring, finding, developing, and producing crude oil and natural gas reserves and the ability to achieve profitable production rates on its existing reserve base and future discoveries, if any. To a large extent, the production rates on the Company's existing discoveries and potential future discoveries are, or may be, beyond the control of the Company. The production rate maintained by field operators or service contractors may significantly impact the Company's production limits with little influence by the Company. The prices received by the Company from the sale of its production are subject to fluctuation in response to changes in supply, market uncertainty and a variety of other factors beyond the Company's control. ITEM 9A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Not applicable. -35- ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT. The following table provides the names of all of our directors and executive officers, their positions, terms of office and their principal occupations during the past five years. Each director is elected for a one year term or until his successor has been duly elected or appointed. Officers serve at the pleasure of the Board of Directors.
Name, Residence, Position with the Company and Term of Office Principal Occupations During the Past Five Years --------------------------------------------- --------------------------------------------------------------------- JOHN ANDRIUK(1).............................. President, Andriuk Enterprises, Ltd. Calgary, Alberta Director since August, 1995 JOHN J. FLEMING (2).......................... Chairman, Roseland Resources, Ltd. Calgary, Alberta Vice Chairman of the Board since December 1998 Director since November, 1992 DON V. INGRAM................................ President and Chief Executive Officer, Imco Recycling Inc. Dallas, Texas Director since March, 1995 STEPHEN S. KURTZ(2).......................... President and Chief Executive Officer of Shenkin Kurtz Baker & Co. Denver, Colorado LLC (an accounting firm) and SKB Business Services (a Century Director since December, 1998 Business Services firm). BARRY D. LASKER.............................. President, Chief Executive Officer and Chief Operating Officer of Houston, Texas TransAtlantic Petroleum Corp. President, Chief Executive Officer, Chief Operating Officer since December 1998 Director since December, 1998 GEORGE H. PLEWES(1)(2)....................... Chairman of Southwestern Gold Corporation (an international mining Pembroke, Bermuda exploration company). Chairman of the Board since December 1998 Director since December, 1998 TREVOR W. WILSON(1).......................... Senior Vice President of Lions Gate Entertainment Corp. from West Vancouver, British Columbia September, 1997 to May, 1998; prior thereto, Vice Chairman of Director since December, 1998 Yorkton Securities Inc. (a securities dealer). SCOTT C. LARSEN.............................. President of various subsidiaries of TransAtlantic Petroleum Corp. Dallas, Texas Acting Chief Financial Officer and Corporate Secretary since September 1999 MICHAEL J. GARTLAND.......................... Occupied various exploration positions with TransAtlantic Petroleum Houston, Texas Corp. and GHP. Vice President Exploration since September 1999
-36- -------------------------------- (1) Member of the Compensation Committee. (2) Member of the Audit Committee. The Company does not have an executive committee. Each of our directors were elected at our last annual general meeting of shareholders. The term of office of each director concludes at our next annual general meeting of shareholders, unless the director's office is earlier vacated in accordance with our by-laws. There are no family relationships among any of our directors, officers or key employees. ITEM 11. COMPENSATION OF DIRECTORS AND OFFICERS. During the fiscal year ended December 31, 1999, we paid our executive officers $440,000 in aggregate cash compensation. Bonuses of $85,000 were paid in the first quarter of 2000. We are required, under applicable securities legislation in Canada, to disclose to our shareholders details of compensation paid to our directors and officers. The following fairly reflects all material information regarding compensation paid by the Company to its directors and officers, which information has been disclosed to our shareholders in accordance with applicable Canadian law. The following table sets forth all annual and long term compensation for services in all capacities to the Company and its subsidiaries for the three most recently completed financial years in respect of the Company's CEO and, if they earned more than Cdn. $100,000 or its equivalent in U.S. dollars, each of the individuals who was, as of December 31, 1999, an executive officer of the Company (collectively, the "Named Executive Officers"). SUMMARY COMPENSATION TABLE
Annual Compensation Long Term Compensation -------------------------------------------------------------- -------------------------------------- Securities Under Other Annual Options/ Restricted Compen- SARs Shares or LTIP All Other Salary Bonus sation Granted Restricted Payouts Compen- Year ($) ($)(1) ($)(2) (#)(3) Share Units ($) ($) sation ---- ------------ ------- ------------ ---------- --------------- ------- ----------- Barry D. Lasker 1999 $150,000 $50,000 - 825,000 - - - President & Chief 1998 $12,500 - - 606,350(5) - - - Executive Officer(4) 1997 - - - - - - - Michael J. Gartland 1999 $140,000 $15,000 - 300,000 - - - Vice President 1998 $11,666 - - 121,800 - - - Exploration 1997 - - - - - - - Scott C. Larsen 1999 $150,000 $20,000 - 300,000 - - - Acting CFO & 1998 - - - 110,000 - - - Corporate Secretary 1997 - - - 40,000 - - - John J. Fleming 1999 - - - 200,000 - - $20,000 Former Chief 1998 Cdn.$140,000 - - 153,300 - - $60,000 Executive Officer(6) 1997 Cdn.$140,000 - - 140,000 - - -
-37- -------------------------------- (1) 1999 bonuses were paid in February 2000. (2) Perquisites and other personal benefits do not exceed the lesser of Cdn. $50,000 and 10% of the total of the annual salary and bonus of any of the named executive officers. (3) The Company has not granted any SARs. (4) Mr. Lasker was appointed Chief Executive Officer on December 1, 1998 upon completion of the amalgamation with GHP. Mr. Lasker was formerly Chief Executive Officer of GHP. (5) Includes 526,350 options to acquire common shares of the Company originally issued by GHP. (6) Mr. Fleming was Chief Executive Officer of the Company until December 1, 1998 at which time he ceased to be employed by the Company. In consideration thereof, Mr. Fleming was awarded 100,000 common shares of the Company with a deemed value of Cdn. $60,000 and US $100,000 in severance pay, US $25,000 of which was paid in 1999. Mr. Fleming remains Vice Chairman and a director of the Company. EMPLOYMENT CONTRACTS AND TERMINATION AGREEMENTS All of the Company's employment contracts with its executive officers are verbal. The agreements provide for the remuneration described above under the Summary Compensation Table. The agreements may be terminated at the election of the executive officer or the Company on reasonable notice. Bonuses and stock options may be paid or granted in the discretion of the Board of Directors upon recommendation of the Compensation Committee. PENSION PLANS The Company does not have any pension plans. The Company's U.S. subsidiary, TransAtlantic Petroleum (USA) Corp. has established a 401(k) Retirement Plan (the "Plan") under applicable U.S. income tax legislation. The Plan provides for voluntary contributions by both the employees and the Company, at their discretion. Directors are not eligible to participate in this plan. DIRECTORS' COMPENSATION The Company does not have any arrangements pursuant to which directors are remunerated by the Company or its subsidiaries for their services in their capacities as directors, consultants or experts other than stock options to purchase common shares of the Company which are granted to the Company's directors from time to time. OTHER REMUNERATION During the financial year ended December 31, 1999, there was no remuneration paid or payable, directly or indirectly, by the Company and its subsidiaries pursuant to any existing plan or arrangement to its directors or Named Executive Officers. OPTION GRANTS DURING THE MOST RECENTLY COMPLETED FINANCIAL YEAR The following table discloses the particulars of options to purchase common shares granted by the Company during the 1999 fiscal year to the Named Executive Officers (the Company has not granted stock appreciation rights): -38-
Percentage Of Market Value Securities Total Of Securities Under Options Underlying Options Granted To Exercise or Options (1) Employees Base On the Granted In Financial Price Date Of Grant Optionee (#)0 Year ($/Share) ($/Security) Expiration Date ------------------------------- ---------- ------------- ----------- -------------- --------------- John J. Fleming................ 50,000 5.3 $0.20 $0.20 May 27, 2004 150,000 7.9 $0.20 $0.20 Dec. 4, 2004 Barry D. Lasker................ 250,000 26.5 $0.20 $0.20 May 27, 2004 575,000 30.3 $0.20 $0.20 Dec. 4, 2004 George H. Plewes............... 50,000 5.3 $0.20 $0.20 May 27, 2004 400,000 21.1 $0.20 $0.20 Dec. 4, 2004 Scott C. Larsen................ 150,000 15.9 $0.20 $0.20 May 27, 2004 150,000 7.9 $0.20 $0.20 Dec. 4, 2004 Michael J. Gartland............ 150,000 15.9 $0.20 $0.20 May 27, 2004 150,000 7.9 $0.20 $0.20 Dec. 4, 2004
AGGREGATE OPTION EXERCISES DURING THE MOST RECENTLY COMPLETED FINANCIAL YEAR AND FINANCIAL YEAR END OPTION VALUES The following table discloses the particulars of stock options exercised during 1999 by the Named Executive Officers (the Company has not granted stock appreciation rights):
Unexercised Value of Unexercised Securities Aggregate Options at FY-End In-The-Money Acquired Value (#)(2) Options at FY-End(1) On Exercise Realized(1) ------------------------------- ----------------------------- (#) ($) Exercisable Unexercisable Exercisable Unexercisable ----------- ----------- -------------- ------------- ----------- ------------- Barry D. Lasker..... - - 1,431,350 - - - George H. Plewes.... - - 887,550 - - - John J. Fleming..... - - 493,300 46,667 - - Scott C. Larsen..... - - 550,000 13,333 - - Michael J. Gartland. - - 421,800 - - -
------------------ (1) Value is the product of the number of shares multiplied by the difference between the closing market price on the relevant date and the exercise price. The closing market price on December 31, 1999 was US $0.19 per share. (2) As of December 31, 1999. -39- ITEM 12. OPTIONS TO PURCHASE SECURITIES FROM REGISTRANT OR SUBSIDIARIES. The Company may grant, pursuant to its stock option plan, which was established in 1995, stock options to its directors, officers, employees and consultants or to employees or consultants of a subsidiary or of a company providing management services to the Company or to a subsidiary in consideration of them providing their services. The Company's Board of Directors determines the number of shares subject to each option within the guidelines established by the plan. The options enable such persons to purchase shares of the Company at a price fixed pursuant to the rules of the plan. 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 the capacity outlined above. The options are exercisable by the optionee giving the Company notice and payment of the exercise price for the number of shares to be acquired. Under the plan approved by the Company's shareholders, the Board of Directors is empowered to grant stock options to insiders; shareholder approval is not required. The maximum number of common shares issuable under the plan is 7,750,000. As of August, 31, 2000, there are outstanding stock options to purchase up to 5,302,550 shares of the Company's common stock. The following table discloses outstanding options held by directors and officers at such date:
No. of Company Common Shares Underlying Exercise Name/Group Options Price Date of Grant Expiration Date -------------------------------- -------------- --------- ----------------- ----------------- Executive Officers as a Group... 60,000 $1.00 (Cdn) March 13, 1996 March 13, 2001 40,000 $1.00 (Cdn) July 30, 1997 July 30, 2002 348,000 $0.57 December 1, 1998 December 1, 2001 130,500 $0.57 December 1, 1998 December 17, 2002 87,000 $0.57 December 1, 1998 April 1, 2003 82,650 $0.57 December 1, 1998 September 8, 2003 190,000 $0.57 December 23, 1998 December 23, 2003 550,000 $0.20 May 27, 1999 May 27, 2004 875,000 $0.20 December 3, 1999 December 3, 2004 Directors who are not Executive 200,000 $2.70 (Cdn) March 13, 1996 March 13, 2001 Officers........................ 75,000 $3.15 (Cdn) October 15, 1996 October 15, 2001 155,000 $2.30 (Cdn) May 23, 1997 May 23, 2002 215,000 $2.20 (Cdn) July 30, 1997 July 30, 2002 304,500 $0.57 December 1, 1998 December 1, 2001 43,500 $0.57 December 1, 1998 December 17, 2002 152,250 $0.57 December 1, 1998 April 1, 2003 52,200 $0.57 December 1, 1998 September 8, 2003 438,400 $0.57 December 23, 1998 December 23, 2003 300,000 $0.20 May 27, 1999 May 27, 2004 950,000 $0.20 December 3, 1999 December 3, 2004 -------------------------------------------------------------------------------------------------------------------- -40- Directors and Officers as a Group........................... 2,675,000 $0.20 628,400 $0.38 1,200,600 $0.57 100,000 $1.00 (Cdn) 200,000 $2.70 (Cdn.) 215,000 $2.20 (Cdn.) 155,000 $2.30 (Cdn.) 75,000 $3.15 (Cdn.)
ITEM 13. INTEREST OF MANAGEMENT IN CERTAIN TRANSACTIONS. There have been no material transactions during the last three fiscal years, and there are no presently proposed transactions, to which the Company or any of its subsidiaries was or is to be a party, in which any director, officer or ten-percent shareholder, or any relative of the foregoing persons, had or is to have a direct or indirect material interest. During the last three fiscal years, none of the Company's directors or officers, or any associate of any director or officer was indebted to the Company. PART II ITEM 14. DESCRIPTION OF SECURITIES TO BE REGISTERED. AUTHORIZED AND ISSUED SHARES The authorized share capital of the Company consists of unlimited common shares without par value. As of August 31, 2000, the Company had a total of 79,384,092 common shares issued and outstanding. All of the common shares are fully paid and not subject to any future call or assessment. All of the common shares of the Company rank equally as to voting rights, participation in a distribution of the assets of the Company on a liquidation, dissolution or winding-up of the Company and the entitlement to dividends. Dividends are payable if, as and when declared by our board of directors subject to the prior rights of holders of shares ranking senior to the common shares with respect to dividends, if any. The holders of the common shares are entitled to receive notice of all shareholder meetings and to attend and to cast one vote per common share at such meetings. The common shares do not have preemptive or conversion rights. In addition, there are no sinking fund or redemption provisions applicable to the common shares. The Alberta Corporations Act provides that the rights and provisions attached to any class of shares may not be modified, amended or varied unless consented to by special resolution passed by a majority of not less than 2/3 of the votes cast in person or by proxy by holders of shares of that class. PART III ITEM 15. DEFAULTS UPON SENIOR SECURITIES. Not Applicable. ITEM 16. CHANGES IN SECURITIES AND CHANGES IN SECURITY FOR REGISTERED SECURITIES. Not Applicable. -41- PART IV ITEM 17. FINANCIAL STATEMENTS. The financial statements filed as part of this registration statement are listed in Item 19 - Financial Statements and Exhibits. All financial statements in this registration statement, unless otherwise stated, are presented in accordance with Canadian GAAP. ITEM 18. FINANCIAL STATEMENTS. Not applicable. -42- ITEM 19. FINANCIAL STATEMENTS AND EXHIBITS. FINANCIAL STATEMENTS
DESCRIPTION PAGE ----------- ---- 1. TransAtlantic Petroleum Corp. Auditors' Report................................................................... Consolidated Balance Sheets as at June 30, 2000, December 31, 1999 and December 31, 1998 ........................................................ Consolidated Statements of Operations and Deficit for the six months ended June 30, 2000 and for the three years ended December 31, 1999, 1998 and 1997 .................................................. Consolidated Statements of Cash Flows for the six months ended June 30, 2000 and for the three years ended December 31, 1999, 1998 and 1997 Notes to the Consolidated Financial Statements..................................... 2. GHP Exploration Corporation Consolidated Balance Sheet as at September 30, 1998................................ Consolidated Statement of Operations and Deficit for the nine months ended September 30, 1998.................................................... Consolidated Statement of Cash Flows for the nine months ended September 30, 1998................................................................. Consolidated Balance Sheets as at December 31, 1997 and December 31, 1996.............................................................. Consolidated Statements of Operations and Deficit for the two years ended December 31, 1997 and 1996............................................. Consolidated Statements of Cash Flows for the two years ended December 31, 1997 and 1996.........................................................
EXHIBITS -43-
EXHIBIT DESCRIPTION PAGE ------- ----------- ---- 1.1 Certificate of Continuance of Profco Resources Ltd. dated June 10, 1997. 1.2 Articles of Continuance of Profco Resources Ltd. dated June 4, 1997. 1.3 Certificate of Amendment of Profco Resources Ltd. dated July 21, 1997. 1.4 Certificate of Registration of Profco Resources Ltd. dated July 31, 1997. 1.5 By-Law No. 1 of Profco Resources Ltd. dated May 23, 1997. 1.6 Certificate of Amendment of Profco Resources Ltd. dated December 2, 1998. 1.7 Articles of Amendment of Profco Resources Ltd. dated December 2, 1998. 2.1 Profco Resources Ltd. Stock Option Plan (1995) dated April 7, 1995. 2.2 Amendment to Profco Resources Ltd. Stock Option Plan (1995), dated June 2, 1997. 2.3 Amendment to TransAtlantic Petroleum Corp. Stock Option Plan (formerly Profco Resources Ltd. Stock Option Plan) (1995), dated June 14, 1999. 2.4 Amendment to TransAtlantic Petroleum Corp. Stock Option Plan (1995), dated June 6, 2000. 3.1 Oil Mining Lease No. 109 granted by Federal Republic of Nigeria to Atlas Petroleum International Limited dated May 27, 1996. 3.2 Joint Operating Agreement of 1st of August, 1995 Relating to Oil Prospecting License 75 between Atlas Petroleum International Limited and Summit Oil & Gas Worldwide Ltd. 3.3 First Amendment to Joint Operating Agreement of 1st of August, 1995 Relating to Oil Prospecting License 75. 3.4 Petroleum Services Subcontract dated January 14, 1996 between CXY Nigeria Oilfield Services Ltd., Atlas Petroleum International Limited and Summit Oil & Gas Worldwide Ltd. 3.5 Amendment to Petroleum Services Subcontract dated July 2, 1997. 3.6 Amendment to Petroleum Services Subcontract dated October 26, 1998. -44- EXHIBIT DESCRIPTION PAGE ------- ----------- ---- 3.7 Deed of Assignment dated April 9, 1998 between the Alliance Egyptian National Exploration Company, as Assignor, and GHP Exploration (Egypt) Ltd., as Assignee. 3.8 Participation Agreement dated March 27, 1998 between Alliance Egyptian National Exploration Company and GHP Exploration (Egypt) Ltd. and GHP Exploration Corporation. 3.9 First Amendment to Participation Agreement dated February 4, 2000 between Alliance Egyptian National Exploration Company and GHP Exploration (Egypt) Ltd. and TransAtlantic Petroleum Corp (formerly GHP Exploration Corporation). 3.10 Concession Agreement for Petroleum Exploration and Exploitation between the Arab Republic of Egypt and The Egyptian General Petroleum Corporation and National Exploration Company, in Central Sinai Area, A.R.E., dated September 22, 1997. 3.11 Oil Prospecting License No. 75 granted by the Federal Republic of Nigeria to Atlas Petroleum International Nigeria Limited dated February 8, 1991. 3.12 Consent of the Federal Republic of Nigeria to the Assignment of 30% Interest by Atlas Petroleum International Limited dated Jul 22, 1992 3.13 Agreement dated July 17, 1992 between Atlas Petroleum International Limited and Summit Partners Management Co. relating to Oil Prospecting License 75. 3.14 Operating Agreement dated January 1, 1999 between Alliance Egyptian National Exploration Company and GHP Exploration (Egypt) Ltd. 3.15 Deed of Assignment dated March 17, 1999 between Dublin International Petroleum (Egypt) Limited and Tanganyika Oil Company, Ltd., as Assignors, and GHP Exploration (West Gharib) Ltd., as Assignee. 3.16 Farmout Agreement dated April 27, 1998 between Tanganyika Oil Company, Ltd., Dublin International Petroleum (Egypt) Limited and GHP Exploration (Egypt) Ltd. 3.17 Resolution No. 1 amending the Farmout Agreement approved by Dublin International Petroleum (Egypt) Limited and GHP Exploration (West Gharib) Ltd. 3.18 Concession Agreement for Petroleum Exploration and Exploitation between the Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Tanganyika Oil Company Ltd. and Dublin International Petroleum (Egypt) Limited, in West Gharib Area, Eastern, A.R.E., dated June 1, 1998. -45- EXHIBIT DESCRIPTION PAGE ------- ----------- ---- 3.19 International Joint Operating Agreement dated April 27, 1998 between Dublin International Petroleum (Egypt) Limited and GHP Exploration (West Gharib) Ltd. and Drucker Petroleum Inc. 3.20 Petroleum Handling and Sale Agreement dated December 30, 1999 by and between General Petroleum Company and Dara Petroleum Company. 3.21 Settlement Agreement dated August 24, 2000 between Global Marine, Inc., Global Marine Integrated Services--International Inc. and TransAtlantic Petroleum Corp.
-46- SIGNATURES Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized. TRANSATLANTIC PETROLEUM CORP. By: ------------------------------------------- Barry D. Lasker, President, Chief Executive Officer and Chief Operating Officer Date:___________, 2000 -47- KPMG Consolidated Financial Statements of TRANSATLANTIC PETROLEUM CORP. Unaudited as at June 30, 2000 and the six months ended June 30, 2000 and 1999 Audited as at December 31, 1999 and 1998 and for each of the years in the three year period ended December 31, 1999 AUDITORS' REPORT TO THE DIRECTORS We have audited the consolidated balance sheets of TransAtlantic Petroleum Corp. as at December 31, 1999 and 1998 and the consolidated statements of operations and deficit and cash flows for each of the years in the three year period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 1999 and 1998 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 1999 in accordance with Canadian generally accepted accounting principles. Accounting principles generally accepted in Canada vary in certain significant respects from accounting principles generally accepted in the United States. Application of accounting principles generally accepted in the United States would have affected results of operations for each of the years in the three year period ended December 31, 1999 and shareholders' equity as at December 31, 1999 and 1998, to the extent summarized in note 11 to the consolidated financial statements. Chartered Accountants Calgary, Canada March 27, 2000 (except for notes 4(a), 9(c) and 11 which are as of September 22, 2000) COMMENTS FOR U.S. READERS 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(a) to the consolidated financial statements. Our report to the directors, dated March 27, 2000 (except for notes 4(a), 9(c) and 11 which are as of September 22, 2000) 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. Chartered Accountants Calgary, Canada March 27, 2000 Page 1 TRANSATLANTIC PETROLEUM CORP. Consolidated Balance Sheets (Thousands of U.S. Dollars)
--------------------------------------------------------------------------------------------------------------- December 31, June 30, ---------------------------------- 2000 1999 1998 --------------------------------------------------------------------------------------------------------------- (unaudited) ASSETS Current assets: Cash and short-term investments $ 208 $ 161 $ 2,955 Restricted cash (note 9) 208 563 1,750 Accounts receivable 191 275 4,228 Other current assets 120 92 170 --------------------------------------------------------------------------------------------------------------- 727 1,091 9,103 Property and equipment (note 3) 15,820 14,554 12,135 Other - - 250 --------------------------------------------------------------------------------------------------------------- $ 16,547 $ 15,645 $ 21,488 =============================================================================================================== LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities (note 2) $ 947 $ 1,704 $ 1,521 Indebtedness (note 4) 3,120 2,882 9,169 --------------------------------------------------------------------------------------------------------------- 4,067 4,586 10,690 Shareholders' equity: Share capital (note 5) 28,879 26,633 23,484 Deficit (note 7) (16,399) (15,574) (12,686) --------------------------------------------------------------------------------------------------------------- 12,480 11,059 10,798 Basis of presentation (note 1) Commitments and contingencies (note 9) Subsequent events (notes 4(a) and 9(c) ) --------------------------------------------------------------------------------------------------------------- $ 16,547 $ 15,645 $ 21,488 ===============================================================================================================
See accompanying notes to consolidated financial statements. Page 2 TRANSATLANTIC PETROLEUM CORP. Consolidated Statements of Operations and Deficit (Thousands of U.S. Dollars)
--------------------------------------------------------------------------------------------------------------- Six Months Ended June 30, Years Ended December 31, ------------------------------- --------------------------------------------- 2000 1999 1999 1998 1997 --------------------------------------------------------------------------------------------------------------- (unaudited) Revenues: Oil and gas sales, net of royalties $ 18,584 $ 10,198 $ 21,999 $ 3,391 $ 636 Interest income 158 333 564 328 177 --------------------------------------------------------------------------------------------------------------- 18,742 10,531 22,563 3,719 813 Expenses: Production: Service fees 16,318 9,908 21,453 3,113 - Taxes 947 - - - - Other 833 488 970 199 196 Depreciation, depletion and amortization 598 554 800 1,120 551 Loss on disposition of property and equipment - - - 196 2,260 Write-down of oil and gas properties - 152 889 10,365 9,576 General and administrative 713 688 1,026 597 446 Interest and other 158 133 313 815 152 --------------------------------------------------------------------------------------------------------------- 19,567 11,923 25,451 16,405 13,181 --------------------------------------------------------------------------------------------------------------- Net loss for the period 825 1,392 2,888 12,686 12,368 Deficit, beginning of period 15,574 12,686 12,686 14,878 2,510 Reduction in stated capital (note 7) - - - (14,878) - --------------------------------------------------------------------------------------------------------------- Deficit, end of period $ 16,399 $ 14,078 $ 15,574 $ 12,686 $ 14,878 =============================================================================================================== Net loss per share (note 8)
See accompanying notes to consolidated financial statements. Page 3
TRANSATLANTIC PETROLEUM CORP. Consolidated Statements of Cash Flows (Thousands of U.S. Dollars) ----------------------------------------------------------------------------------------------------------------------- Six Months Ended June 30, Years Ended December 31, ---------------------------- --------------------------------------------- 2000 1999 1999 1998 1997 ----------------------------------------------------------------------------------------------------------------------- (unaudited) Cash provided by (used in): Operating activities: Net loss for the period $ (825) $ (1,392) $ (2,888) $(12,686) $(12,368) Items not involving cash: Depreciation, depletion and amortization 598 554 800 1,120 551 Write-down of oil and gas properties - 152 889 10,365 9,576 Other items not involving cash 27 (240) (249) 196 2,260 ---------------------------------------------------------------------------------------------------------------------- (200) (926) (1,448) (1,005) 19 Changes in non-cash working capital 410 (178) 853 (347) 744 ---------------------------------------------------------------------------------------------------------------------- 210 (1,104) (595) (1,352) 763 Investing activities: Exploration and acquisition of oil and gas properties (1,952) (1,708) (3,920) (2,838) (13,659) Past cost reimbursement (note 3) - - 3,828 - - Proceeds from sale of property and equipment - - 109 3,877 4,131 Changes in non-cash working capital (601) 4,502 1,159 (511) 7,085 ---------------------------------------------------------------------------------------------------------------------- (2,553) 2,794 1,176 528 (2,433) Financing activities: Issuance of common shares, net 2,152 - 889 - 1,421 Borrowings of long-term debt - - - - 5,906 Repayments of long-term debt - (4,354) (4,354) (3,588) - Changes in non-cash working capital 238 (242) 90 857 - ---------------------------------------------------------------------------------------------------------------------- 2,390 (4,596) (3,375) (2,731) 7,327 ---------------------------------------------------------------------------------------------------------------------- Increase (decrease) in cash and short-term investments 47 (2,906) (2,794) (3,555) 5,674 Cash and short-term investments, beginning of period 161 2,955 2,955 6,510 863 ---------------------------------------------------------------------------------------------------------------------- Cash and short-term investments, end of period $ 208 $ 49 $ 161 $ 2,955 $ 6,510 ======================================================================================================================
Cash and short-term investments is comprised of cash and investments with maturities of thirty days or less. See accompanying notes to consolidated financial statements. Page 4 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) ------------------------------------------------------------------------------- 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 application of accounting principles generally accepted in the United States would have affected these consolidated financial statements to the extent summarized in note 11. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Actual results could differ from those estimates and assumptions; however, management believes that such differences would not be material. 1. BASIS OF PRESENTATION, NATURE OF OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES: (a) Basis of presentation: The consolidated financial statements have been presented on a going-concern basis which contemplates that TransAtlantic Petroleum Corp. (the "Company") will continue to meet its obligations as they come due in the foreseeable future. As at June 30, 2000, the Company had a working capital deficiency of $3.3 million (December 31, 1999 - $3.5 million). To meet its obligations as they come due, the Company will be required to use existing cash on hand, cash flow from operations, if any, re-negotiations of debt obligations and the issuance of additional debt or equity. If the going concern assumption were inappropriate, then adjustments would be necessary in the carrying value and classification of assets and the reported results of operations in the financial statements. (b) Nature of operations: The Company is an independent oil and gas company amalgamated under the laws of Alberta for the purpose of exploring for, developing and producing crude oil, natural gas and natural gas liquids. The Company's current activities are focused in Egypt and Nigeria and are conducted through various wholly-owned subsidiaries. The Company's viability, including the recoverability of the Company's oil and gas investments, and the results of its operations, is dependent upon the discovery of economically recoverable reserves, its ability to obtain the necessary financing to complete development of the reserves and the future profitable production from its developed reserves. Inherent in these requirements is the importance of product prices and the costs of acquiring, finding, developing and producing crude oil and natural gas reserves. The prices Page 5 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) ------------------------------------------------------------------------------- 1. BASIS OF PRESENTATION, NATURE OF OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED): received by the Company or its subsidiaries from the sale of their crude oil and natural gas production are subject to fluctuation in response to changes in supply, market uncertainty and a variety of factors beyond the Company's control. (c) Oil and gas properties: Under the full cost method of accounting, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves in cost centers on a country-by-country basis. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from the sale of oil and gas properties are accounted for as reductions to 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, depletion and amortization of oil and gas properties using the unit-of-production method based upon production and estimates of 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 computer equipment and software is provided for on the straight-line basis at rates between three and seven years designed to amortize the cost of the assets over their estimated useful lives. The net carrying value of the Company's oil and gas properties is limited to an estimated recoverable amount. This amount is determined by estimating the amount of future net revenues from proved properties based on period-end prices less future production, general and administrative, financing and site restoration costs and production and income taxes, together with the value of unproved properties at the lower of cost and realizable value on a country-by-country basis. When it is determined that the net realizable value is less than the carrying value of the oil and gas properties, the impairment is charged to income. Where appropriate, provisions are made in the accounts for estimated future net costs of well abandonment and site restoration, including removal of production facilities at the end of their useful life. Costs are based on estimates valued at year-end prices and in accordance with the current legislation and industry practices. The annual provision is computed on a unit-of-production basis and is recorded as an expense for the year. A substantial portion of the Company's activities are conducted jointly with industry partners and the accompanying consolidated financial statements reflect only the Company's proportionate interest in such activities. Page 6 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) ------------------------------------------------------------------------------- 1. BASIS OF PRESENTATION, NATURE OF OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED): (d) Foreign currency translation: 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, except for unrealized gains and losses on long-term monetary items which are deferred and amortized to earnings over their remaining term. (e) Financial instruments: The fair value of cash and short-term investments, receivables and accounts payable and accrued liabilities approximates their carrying value. The Company has no derivative financial instruments. (f) Stock option policy: The Company has one stock-based compensation plan that is detailed in note 5(c). No compensation expense is recognized for this plan when stock options are granted. Consideration paid upon exercise of stock options is credited to share capital. (g) Income taxes: Effective January 1, 2000, the Canadian Institute of Chartered Accountants ("CICA") changed the accounting standard relating to the accounting for income taxes. The CICA's new standard on accounting for income taxes adopts the liability method of accounting for future income taxes. Under the liability method, future income tax assets and liabilities are determined based on "temporary differences" (differences between the accounting basis and the tax basis of the assets and liabilities), and are measured using the currently enacted, or substantively enacted, tax rates and laws expected to apply when these differences reverse. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the asset will not be realized. Income tax expense or benefit is the sum of the Company's provision for current income taxes and difference between the opening and ending balances of the future income tax assets and liabilities. Prior to adoption of this new standard, income tax expense was determined using the deferral method. Under this method, deferred income tax expense was determined based on "timing differences" (differences between the accounting and tax treatment of items of expense or income), and were measured using the tax rates in effect in the year the differences originated. Certain deferred tax assets, such as the benefit of tax losses Page 7 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) ------------------------------------------------------------------------------- 1. BASIS OF PRESENTATION, NATURE OF OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED): carried forward, were not recognized unless there was virtual certainty that they would be realized. (g) Income taxes (continued): The Company has adopted the new income tax accounting standard retroactively without restatement of prior periods. There has not been any change in the Company's deficit or future income taxes as a result of adopting the new income tax accounting standard. 2. BUSINESS COMBINATION: On October 19, 1998, the Company entered into an Arrangement Agreement with GHP Exploration Company ("GHP"), a Yukon Territory corporation, and on November 24, 1998 the shareholders of GHP approved the Arrangement. On December 1, 1998, the Company and GHP completed the Arrangement and the Company acquired all of the issued and outstanding common shares of GHP. The Company was then re-named TransAtlantic Petroleum Corp. The acquisition was accounted for using the purchase method and, accordingly, the results of operations of GHP were included in the consolidated financial statements from the date of acquisition of December 1, 1998. Pursuant to the terms of the Arrangement Agreement, each common share of GHP was exchanged for 0.87 common shares of the Company. The Company issued a total of 19,003,828 common shares having a fair market value of $9.1 million. As of June 30, 2000, and December 31, 1999 and 1998, the Company had $0.16 million, $0.24 million and $0.51 million, respectively, of severance costs included in accounts payable and accrued liabilities related to the amalgamation. The purchase price was allocated to the assets and liabilities based on their estimated fair market value as follows: --------------------------------------------------------------------------- Cash $ 758 Other current assets 1,887 Property and equipment 7,083 Other assets 150 Current liabilities (773) --------------------------------------------------------------------------- Net assets acquired $ 9,105 ===========================================================================
Page 8 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 3. PROPERTY AND EQUIPMENT:
------------------------------------------------------------------------------------------------------------ Accumulated depletion, depreciation Net book December 31, 1999 Cost and amortization value ------------------------------------------------------------------------------------------------------------ Crude oil and natural gas properties Nigeria $ 18,181 $ (9,841) $ 8,340 Egypt 5,071 -- 5,071 United States 1,730 (728) 1,002 Furniture, fixtures and other assets 376 (235) 141 ------------------------------------------------------------------------------------------------------------ $ 25,358 $ (10,804) $ 14,554 ============================================================================================================ December 31, 1998 ------------------------------------------------------------------------------------------------------------ Crude oil and natural gas properties Nigeria $ 17,743 $ (9,191) $ 8,552 Egypt 2,047 -- 2,047 United States 1,357 -- 1,357 Furniture, fixtures and other assets 365 (186) 179 ------------------------------------------------------------------------------------------------------------ $ 21,512 $ (9,377) $ 12,135 ============================================================================================================ June 30, 2000 ------------------------------------------------------------------------------------------------------------ Crude oil and natural gas properties Nigeria $ 18,181 $ (10,117) $ 8,064 Egypt 6,746 (282) 6,464 United States 1,920 (728) 1,192 Furniture, fixtures and other assets 377 (277) 100 ------------------------------------------------------------------------------------------------------------ $ 27,224 $ (11,404) $ 15,820 ============================================================================================================
(a) The carrying value of capital assets is subject to uncertainty associated with the quantity of oil and gas reserves, future production rates, commodity prices and other factors. Future events could materially change the carrying values recognized in the accompanying consolidated financial statements. At December 31, 1998, the Company's capitalized costs of its Nigerian oil and gas properties exceeded the ceiling limitation and the Company recorded in the 1998 financial statements an $8.4 million non-cash impairment of these assets. At June 30, 2000, included within the Company's recorded balance for Nigerian crude oil and natural gas properties was $6.5 million (December 31, Page 9 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 3. PROPERTY AND EQUIPMENT (CONTINUED): 1999 - $6.5 million; December 31, 1998 - $6.4 million) of costs related to unproved properties not being amortized. During 1996, Summit Oil and Gas Worldwide Ltd. ("SOGW") signed a service contract with CXY Nigeria Oilfield Services Limited ("CXY"), a wholly-owned subsidiary of Canadian Occidental Petroleum Ltd. with respect to the Ejulebe field. The terms of the contract required CXY to fund the drilling, completion and equipment costs of the Ejulebe field, incur certain other expenditures and reimburse SOGW for prior costs incurred ("Past Cost Reimbursement") upon the Ejulebe field reaching one million barrels of cumulative oil production, which occurred in 1999. In February and March 1999, the Company was credited $10 million from CXY in satisfaction of the Past Cost Reimbursement; $3.8 million in cash and $6.2 million in satisfaction of the CXY loan. During 1996, CXY advanced $5 million to SOGW bearing interest at LIBOR plus 3% per annum in respect of the service contract. $6.2 million of the Past Cost Reimbursement was used to repay the CXY loan. SOGW advanced these funds, bearing interest at LIBOR plus 3% per annum and in return received, as security for the loan, an assignment from its indigenous partner of certain rights as to distributions from cash flows from the OML-109 concession offshore Nigeria. The Company has recorded this advance as a component of its unproved property as at December 31, 1999 and 1998. This note is non-performing as of December 31, 1999 and the Company has initiated a collection proceeding. Interest on the note has been recognized to the extent received, which equalled $0.6 million in 1999 and nil to June 30, 2000. Under the service contract with CXY, CXY paid all of the capital, which totaled in excess of $100 million, to drill development wells and install a production platform and pipeline for the Ejulebe field. CXY is paid a service fee by SOGW and its Nigerian partner out of production revenues. The service fee is comprised of several components including a return of capital invested by the service contractor. Currently, all production revenues, after payment of royalties, are paid to CXY. The Ejulebe field only becomes profitable to the Company after the combination of price and production rate pays down CXY's invested capital. (b) During 1998, the Company acquired, in its acquisition of GHP (see note 2), a 30% working interest in the West Gharib Concession, held by GHP Exploration (West Gharib) Ltd., and a 25% working interest in the Central Sinai Concession, held by GHP Exploration (Egypt) Ltd. Also acquired were several other properties which were sold in December 1998 for total proceeds of $3.8 million, and varying interests in exploration acreage all located in the United States. The recorded balances for the Company's United States properties primarily relate to unproved prospects and are not being Page 10 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 3. PROPERTY AND EQUIPMENT (CONTINUED): amortized. During 1999, the Company wrote down the net book value of its U.S. cost center by $0.7 million. (c) During 1997, several of the Company's subsidiaries entered into an agreement to acquire a 52.8% interest in Tarpon Benin S.A. ("Tarpon") for cash consideration of $1.4 million. Tarpon was the owner of an exploration and production concession in the Republic of Benin in which Tarpon had the exclusive right to explore for and produce oil and natural gas within the concession. The agreement required the Company's subsidiaries and other parties to fund the drilling of an exploratory well, seismic program and training program. At December 31, 1997, approximately $8.7 million of costs related to Tarpon were written off as the exploration program proved uneconomic. During 1998, an additional $1.6 million of costs were written off. (d) During 1997, SOGW Tunisia Ltd. entered into an agreement to earn a 6.7% working interest in a drilling permit located in Tunisia by paying 10% of the drilling costs associated with the initial well. The well was determined to be uneconomic and the costs incurred to December 31, 1997 were written off. Also, the Company participated in the El Hamra prospect in 1998 and 1999 but has made the decision to likewise abandon it. During 1999, $0.16 million was written off and in 1998, $0.4 million was written off on the Company's Tunisia prospects. (e) A total of $0.5 million, $1.2 million and $1.6 million of overhead costs incurred during the six months ending June 30, 2000 and the years ended December 31, 1999 and 1998, respectively, related to exploration and development activities was capitalized. 4. INDEBTEDNESS: (a) Note payable to Global Marine Integrated Services International Inc. ("GMISI"): A promissory note with a principal balance of $2.3 million plus accrued interest of $0.5 million as of December 31, 1999 issued by Tarpon, is related to the drilling of the exploratory well offshore Benin (see note 9(c)) and is guaranteed by the Company. The note payable, originally at prime plus 2% interest, became non-performing as of August, 1999. The note provides for default interest at prime plus 5%. Tarpon is insolvent and the Company notified GMISI in January, 1999 that it would be unable to meet its obligation under the guarantee at that time. The Company proposed a debt restructure plan and pursuant thereto, the Company made a principal payment of $0.5 million on February 17, 1999 and additional principal payments of $50,000 each month from March, 1999 through June, 1999. Since that time, there have been ongoing discussions but no further payments. On August 24, 2000, the Company and GMISI entered into a settlement agreement that provides for the entire amount to be satisfied if the Company pays GMISI $1.5 million prior to November 22, 2000. If not paid, the gross principal plus accrued Page 11 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 4. INDEBTEDNESS (CONTINUED): interest is converted to long-term debt, bearing interest at 12% per annum and payable in monthly instalments of $75,000. During 1999 and 1998, the Company recorded interest expense of $0.32 and $0.24 million, respectively, related to this note. The fair value of the note payable at December 31, 1999 and 1998 approximates its carrying value. (b) Convertible unsecured debenture: During 1999 and 1998, the Company recorded interest expense of $0.1 million and $0.4 million, respectively, related to the debentures. In April, 1999, the Company entered into an Amending Supplemental Trust Indenture allowing for the early redemption of its Cdn. $9 million (approximately $5.9 million U.S. dollars) 7% convertible debentures whereby the debenture holders were paid $3.6 million in cash and received 9.144 million common shares of the Company at an ascribed price of $0.25 per share. 5. SHARE CAPITAL: (a) Authorized: Unlimited number of common shares, without par value (b) Issued:
------------------------------------------------------------------------------------- Number of (In thousands) Shares Amount ------------------------------------------------------------------------------------- Balance, December 31, 1997 34,481 $ 30,225 Reduction in stated capital (note 7) - (14,878) Issued on acquisition of GHP (note 2) 19,004 8,137 ------------------------------------------------------------------------------------- Balance, December 31, 1998 53,485 23,484 Issuances of stock 4,880 930 Conversion of debentures 9,144 2,286 Issue costs - (67) ------------------------------------------------------------------------------------- Balance, December 31, 1999 67,509 26,633 Issuances of stock 11,875 2,400 Issue costs - (154) ------------------------------------------------------------------------------------- Balance, June 30, 2000 79,384 $ 28,879 =====================================================================================
Page 12 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 5. SHARE CAPITAL (CONTINUED): (c) Stock option plan: The Company has a directors and management Stock Option Plan under which 7.75 million common shares were reserved for issuance as at June 30, 2000. These options are granted with a five year expiry, the majority of which are fully vested. Details of the Company's plan as at June 30, 2000 and December 31, 1999 and 1998, and changes during the periods, are presented below.
------------------------------------------------------------------------------------------------------- Years Ended December 31, June 30, 2000 1999 1998 ------------------ ---------------------------------------- Weighted Weighted Weighted Number average Number average Number average of exercise of exercise of exercise options price options price options price ------------------------------------------------------------------------------------------------------- Outstanding at beginning of period 5,773 $ 0.44 4,764 $ 0.84 2,130 $ 1.23 Granted 140 0.26 3,120 0.20 2,634 0.52 Exercised - - - - - - Cancelled and expired (475) 1.30 (2,111) 0.98 - - ------------------------------------------------------------------------------------------------------- Outstanding at end of period 5,438 $ 0.36 5,773 $ 0.44 4,764 $ 0.84 ======================================================================================================= Exercisable at year period 5,244 $ 0.33 5,478 $ 0.40 4,174 $ 0.78 =======================================================================================================
The following table summarizes information about stock options as at June 30, 2000:
===================================================================================================== Options Outstanding Options Exercisable ----------------------------------------------------------------------------------------------------- Weighted- Average Range of Prices Remaining Weighted- Weighted - --------------------- Number Contractual Average Number Average Low High Outstanding Life Exercise Price Exercisable Exercise Price ----------------------------------------------------------------------------------------------------- $ 0.20 $ 0.20 2,845 4.0 $ 0.20 2,845 $ 0.20 0.26 0.57 2,140 3.0 0.50 2,140 0.50 0.67 2.11 453 1.5 0.78 259 0.47 ----------------------------------------------------------------------------------------------------- $ 0.20 $ 2.11 5,438 3.4 $ 0.36 5,244 $ 0.33 =====================================================================================================
Page 13 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 5. SHARE CAPITAL (CONTINUED): The following table summaries information about stock options at December 31, 1999:
===================================================================================================== Options Outstanding Options Exercisable ----------------------------------------------------------------------------------------------------- Weighted- Average Range of Prices Remaining Weighted- Weighted - --------------------- Number Contractual Average Number Average Low High Outstanding Life Exercise Price Exercisable Exercise Price ----------------------------------------------------------------------------------------------------- $ 0.20 $ 0.20 2,845 4.5 $ 0.20 2,845 $ 0.20 0.38 0.57 2,000 3.5 0.52 2,000 0.52 0.67 2.17 928 2.0 1.05 633 0.95 ----------------------------------------------------------------------------------------------------- $ 0.20 $ 2.17 5,773 4.0 $ 0.80 5,478 $ 0.78 =====================================================================================================
(d) Warrants: On July 21, 1999, the Company completed a private placement of 4.65 million units at $0.20 per unit for gross proceeds of $0.93 million. Each unit consisted of one common share and one-half common share purchase warrant. A whole warrant is exercisable at $0.25 per share until December, 2000. As at June 30, 2000 2.32 million share purchase warrants (December 31, 1999 - 2.32 million) were outstanding. On January 28, 2000, the Company completed a brokered private placement totaling 10 million units for gross proceeds of $2.0 million. Each unit cost $0.20 and consisted of one common share and one-half common share purchase warrant. A whole warrant is exercisable at $0.25 until January 31, 2001. In connection with the placement, the Company issued one million warrants to the broker, exercisable at $0.25 per share on or before January 31, 2001. On May 31, 2000, the Company completed a private placement totaling 1.6 million units for gross proceeds of $0.3 million. Each unit cost $0.19 and consisted of one common share and 0.60 of one common share purchase warrant. A whole warrant is exercisable at $0.25 until May 31, 2001. In addition, in May 2000, the Company issued 100,000 common shares to the Company's 40(K) retirement plan, and issued 175,000 common shares to former employees under a previously accrued December 1998 severance agreement. 6. INCOME TAXES: The Company and its wholly-owned subsidiaries have accumulated losses or resource related deductions available for income tax purposes, subject to confirmation by the Page 14 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 6. INCOME TAXES (CONTINUED): applicable authorities in Canada, in the United States and in Nigeria. 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. 7. REDUCTION IN STATED CAPITAL: On June 9, 1998, the shareholders of the Company approved a special resolution authorizing a reduction in statutory capital in respect of the common shares by U.S. $14.9 million. This resulted in a corresponding reduction in the accumulated deficit as shown in the consolidated balance sheets and the consolidated statements of operations and deficit. 8. NET LOSS PER SHARE:
======================================================================================= June 30, December 31, ----------------------- ------------------------------------ 2000 1999 1999 1998 1997 --------------------------------------------------------------------------------------- Net loss per share $ 0.01 $ 0.02 $ 0.05 $ 0.35 $ 0.37 =======================================================================================
Per common share amounts were calculated using a weighted average number of shares outstanding at June 30, 2000 of 76,509,779 and 55,918,882 at June 30, 1999 (December 31, 1999 - 61,685,180; 1998 - 36,064,916; 1997 - 33,870,621). Common share equivalents relating to options and share purchase warrants were not included in the weighted average number of shares for June 30, 2000 and December 31,1999, 1998 and 1997 since their inclusion would not have been dilutive. 9. COMMITMENTS AND CONTINGENCIES: (a) In March 1998, GHP Exploration (Egypt) Ltd. entered into a Participation Agreement to acquire a 25% working interest in the 18,150 square kilometer Central Sinai Concession located in Egypt's Sinai Peninsula. The work program requires a minimum financial commitment of $6.0 million to the 100% interest and expires September 22, 2000. The Company's share of this commitment is $2.4 million, of which $2.4 million had been incurred as of June 30, 2000 (December 31, 1999 - $1.6 million). (c) In April 1998, GHP Exploration (West Gharib) Ltd. entered into a Farmout Agreement to acquire a 30% working interest in the West Gharib Concession consisting of 2,530 square kilometers located on the Western shore of the Gulf of Suez basin. The work program requires a minimum financial commitment of $5.0 million to the 100% interest and expires June 1, 2001. The Company's share of this commitment is approximately $2 million, of which all had been incurred as of December 31, 1999. The Company has $0.6 Page 15 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) ------------------------------------------------------------------------------- 9. COMMITMENTS AND CONTINGENCIES (CONTINUED): million in escrow, which is recorded as restricted cash, to secure its interest in the concession. (c) Several of the Company's wholly-owned subsidiaries (the "Companies") are parties to an arbitration brought by a group of minority shareholders (the "Claimants") of Tarpon (see note 3(c)) seeking, among other things, damages in an amount sufficient to perform certain alleged obligations which the Claimants contend are required to be performed pursuant to the terms of a shareholder agreement. On September 18, 2000, the Company was advised that the arbitrator ruled that the Subsidiaries had breached the Shareholder Agreement and assessed damages of $1.8 million. While the Company was not a party to the Shareholder Agreement, the arbitrator ruled that the Company guaranteed all obligations of the Subsidiaries. The Company does not believe that the Subsidiaries have a basis to appeal the decision. However, the Company intends to contest the arbitrator's ruling against the Company. No provision for any possible loss with respect to this contingency has been made in the consolidated financial statements. No assurances can be made that the Company will be successful. (d) As at December 31, 1999 future minimum annual lease payments under operating lease agreements for office premises and equipment for the next five years are approximately $0.6 million in years 2000, 2001 and 2002, and $0.5 million in years 2003 and 2004. 10. SEGMENT INFORMATION: As at June 30, 2000, the Company and its subsidiaries operate in one dominant industry, the exploration for, and the development and production of crude oil and natural gas. Identifiable assets, revenues and net loss in each of its geographic areas are as follows:
------------------------------------------------------------------------------------------------------------------- Identifiable Net Loss June 30, 2000 Assets Revenues (Income) ------------------------------------------------------------------------------------------------------------------- (in thousands) Nigeria $ 8,198 $ 16,727 $ 359 Egypt 6,576 1,934 (362) United States 1,463 81 328 Canada 306 - 210 Others 4 - 290 ------------------------------------------------------------------------------------------------------------------- $ 16,547 $ 18,742 $ 825 =================================================================================================================== Page 16 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 10. SEGMENT INFORMATION (CONTINUED): December 31, 1999 ------------------------------------------------------------------------------------------------------------------- Nigeria $ 8,475 $ 22,423 $ 574 Egypt 5,110 15 (15) United States 1,772 125 1,304 Canada 274 - 533 Others 14 - 492 ------------------------------------------------------------------------------------------------------------------- $ 15,645 $ 22,563 $ 2,888 =================================================================================================================== December 31, 1998 ------------------------------------------------------------------------------------------------------------------- Nigeria $ 12,627 $ 3,649 $ 9,172 United States 6,241 28 80 Egypt 2,297 - 2 Benin - - 1,613 Canada 311 42 1,417 Tunisia 12 - 402 ------------------------------------------------------------------------------------------------------------------- $ 21,488 $ 3,719 $ 12,686 ===================================================================================================================
11. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES: The Company's consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada ("Canadian GAAP"). These principles, as they pertain to the Company's consolidated financial statements, are not materially different from United States' generally accepted accounting principles ("U.S. GAAP") except as follows: (a) There are certain differences between the full cost method of oil and gas accounting as applied in Canada and as applied in the United States. The Company has reviewed such differences and determined that, except as discussed below, no material variances in financial statement balances would have resulted from the application of full cost accounting in accordance with U.S. GAAP. The Company has completed ceiling test calculations in accordance with U.S. GAAP at December 31, 1999, 1998 and 1997. The ceiling tests computed under U.S. GAAP did not result in any differences as at December 31, 1999 and 1997. However, at December 31, 1998 the U.S. GAAP ceiling test results in an additional impairment of $488. This difference would increase the Company's net loss for the year ended Page 17 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) -------------------------------------------------------------------------------- 11. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED): December 31, 1998 and would reduce the Company's total assets and shareholders' equity at December 31, 1988 and subsequent periods. (b) In accordance with U.S. GAAP (and Canadian GAAP effective January 1, 2000), the liability method of accounting for income taxes is used instead of the deferral method. Under the liability method, current and deferred income taxes are recognized, at currently enacted rates, to reflect the expected future tax consequences arising from the difference between transactions recorded in the financial statements and those in income tax returns. In addition, purchase price adjustments arising from business combinations are grossed up for the related income tax impact under U.S. GAAP. No adjustments to the financial statements are required with respect to the accounting for income taxes. (c) The Company applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees", and related interpretations, in accounting for its stock options issued to employees, directors and officers of the Company for purposes of reconciliation to U.S. GAAP. As such, compensation expense would be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, "Accounting for Stock-based Compensation", established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, the Company has elected to continue to apply the intrinsic value-based method of accounting described above and has adopted the disclosure requirements of SFAS No. 123. Stock options issued to third parties are accounted at their fair values in accordance with SFAS No. 123. No adjustments to the financial statements are required with respect to the accounting for stock options, except for the inclusion of additional disclosures below. During the periods ended June 30, 2000, December 31, 1999 and 1998, the Company granted options to employees, directors and officers which, for purposes of reconciling to U.S. GAAP, have been accounting for in compliance with APB Opinion No. 25. All were granted with exercise prices at market price of the Company's stock on the date of grant. Accordingly, no compensation expense is recorded in the Company's statement of operations and deficit. The Company has calculated the fair value of stock options granted to employees using the Black-Scholes option pricing model with the following weighted-average assumptions: Page 18 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) ------------------------------------------------------------------------------- 11. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED):
---------------------------------------------------------------------------------------------------------- December 31, June 30, ----------------------------------- 2000 1999 1998 ---------------------------------------------------------------------------------------------------------- Risk free interest rate 5.75% 5.55% 5.15% Volatility 5.27% 6.13% 5.27% Expected option life (in years) 5.0 5.0 5.0 Dividend yield 0% 0% 0% ========================================================================================================== Had the Company determined compensation cost based upon the fair value at the grant date for its stock options under SFAS No. 123, the Company's pro forma net loss per share amounts would have been as follows: ---------------------------------------------------------------------------------------------------------- December 31, June 30, ----------------------------------- 2000 1999 1998 ---------------------------------------------------------------------------------------------------------- Net loss under U.S. GAAP: As reported $ 825 $ 2,888 $ 12,686 Pro forma 834 3,040 12,999 ---------------------------------------------------------------------------------------------------------- Net loss per common share: As reported $ 0.01 $ 0.05 $ 0.35 Pro forma 0.01 0.05 0.36 ========================================================================================================== (d) The reduction in stated capital recorded during 1998 under Canadian GAAP would have to be reversed under U.S. GAAP. As a result, the Company's shareholders' equity under U.S. GAAP at December 31, 1998 and subsequent periods would be restated as follows: ---------------------------------------------------------------------------------------------------------- December 31, June 30, ----------------------------------- 2000 1999 1998 ---------------------------------------------------------------------------------------------------------- Share capital $ 43,757 $ 41,511 $ 38,362 Deficit (31,277) (30,452) (27,564) ---------------------------------------------------------------------------------------------------------- $ 12,480 $ 11,059 $ 10,798 ==========================================================================================================
Page 19 TRANSATLANTIC PETROLEUM CORP. Notes to Consolidated Financial Statements Years ended December 31, 1999, 1998 and 1997 (Information as at June 30, 2000 and for the six months ended June 30, 2000 and 1999 is unaudited) (U.S. Dollars) ------------------------------------------------------------------------------- 11. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED): (e) Supplementary disclosures required under U.S. GAAP are as follows:
----------------------------------------------------------------------------------------------------------- Six months ended December 31, June 30, --------------------------------- 2000 1999 1998 ----------------------------------------------------------------------------------------------------------- Components of change in non-cash working capital: Restricted cash $ 355 $ 1,187 $ - Accounts receivable 47 167 49 Accounts payable and accrued liabilities 32 (583) 79 Other (24) 82 (475) ----------------------------------------------------------------------------------------------------------- $ 410 $ 853 $ (347) =========================================================================================================== (f) Additional Disclosures Required Under U.S. GAAP The components of accounts payable and accrued liabilities are as follows: ----------------------------------------------------------------------------------------------------------- December 31, June 30, --------------------------------- 2000 1999 1998 ----------------------------------------------------------------------------------------------------------- Accounts payable $ 501 $ 494 $ 647 Accrued Liabilities 446 1,210 874 ----------------------------------------------------------------------------------------------------------- $ 947 $ 1,704 $ 1,521 ===========================================================================================================
Page 20 AUDITORS' REPORT To the Directors of GHP EXPLORATION CORPORATION We have audited the consolidated balance sheet of GHP EXPLORATION CORPORATION as at December 31,1997 and the consolidated statements of operations and deficit and cash flows for each of the years in the two year period ended December 31, 1997. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 1997 and the results of its operations and the changes in its financial position for each of the years in the two year period ended December 31, 1997 in accordance with generally accepted accounting principles. Toronto, Canada, /s/ Ernst & Young February 17,1998 (except for note 10 ------------------------ which is as at June 24, 1998). Chartered Accountants 1 GHP EXPLORATION CORPORATION CONSOLIDATED BALANCE SHEETS (In U.S. Dollars)
December 31, 1997 ----------------- ASSETS CURRENT ASSETS Cash and short-term investments $ 3,573,368 Receivables 1,029,898 Prepaid expenses and other 106,727 ------------ 4,709,993 PROPERTY AND EQUIPMENT (NOTE 3) 10,987,859 ------------ $ 15,697,852 ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 2,387,041 SHAREHOLDERS' EQUITY Share capital (Note 5) 14,659,806 Deficit (1,348,995) ------------ 13,310,811 ------------ $ 15,697,852 ============
Approved by the Board of Directors: /s/ GEORGE H. PLEWES /s/ BARRY D. LASKER ----------------------------- ----------------------------- George H. Plewes Barry D. Lasker Director Director The accompanying notes are an integral part of these financial statements. 2 GHP EXPLORATION CORPORATION CONSOLIDATED STATEMENTS OF OPERATION AND DEFICIT (In U.S. Dollars)
For The Years Ended December 31, 1997 1996 ---- ---- REVENUES Interest income $ 497,420 $ 49,407 Oil and gas sales 6,388 - ----------- ----------- 503,808 49,407 EXPENSES General and administrative (Note 7) 1,192,258 29,851 Depreciation, depletion and Amortization 23,232 - Impairment of oil and Gas properties - - Oil and gas production - - ----------- ----------- 1,215,490 29,851 ----------- ----------- NET INCOME (LOSS) FOR THE PERIOD (711,682) 19,556 DEFICIT, AT BEGINNING OF PERIOD (637,313) (656,869) ----------- ----------- DEFICIT, AT END OF PERIOD $(1,348,995) $ (637,313) ----------- ----------- NET INCOME (LOSS) PER SHARE $ (0.04) $ 0.00 =========== ===========
The accompanying notes are integral part of these financial statements. 3 GHP EXPLORATION CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOW (IN U.S. DOLLARS)
Years Ended December 31, 1997 1996 ----------- ---------- OPERATING ACTIVITIES Net income(loss)for the period $ (711,682) $ 19,566 Add Items not Involving cash: Depreciation, depletion and amortization 23,232 - ----------- ---------- (688,450) 19,556 Changes in non-cash working capital balances: Increase in receivables (1,029,898) - Decrease in prepaid expenses and other (72,293) (30,130) Increase in accounts payable and accrued liabilities 4,532 30,092 ----------- ---------- Cash provided by (used in) operating activities (1,786,109) 19,518 ----------- ---------- INVESTING ACTIVITIES Exploration and acquisition of properties (Note 3) Non-cash portion of oil and gas property expenditures (9,979,433) (201,696) 2,350,947 - Issuance of common shares for properties (Note 5) (143,000) - Acquisition of corporate assets (136,684) - ----------- ---------- Cash used in investing activities (7,908,170) (201,696) ----------- ---------- FINANCING ACTIVITIES Issuance of common shares (Note 5) 11,250,000 3,000,000 Share issue expenses (Note 5) (937,316) (62,877) Issuance of common shares for properties (Note 5) 143,000 - Increase in note payable - 54,600 Decrease in note payable (Note 7) - (544,498) Issuance of common shares in satisfaction of note payable (Note 5) - 544,498 ----------- ---------- CASH PROVIDED BY FINANCING ACTIVITIES 10,455,684 2,991,723 ----------- ---------- NET INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS 761,405 2,809,545 Cash and short-term investments, beginning of period 2,811,963 2,418 ----------- ---------- Cash and short-term investments, end of period $ 3,573,368 $2,811,963 =========== ==========
The accompanying notes are an integral part of these financial statements. 4 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (in U.S. Dollars) 1. BASIS OF PRESENTATION On February 16, 1997, GHP Corporation, a company incorporated in the United States, was acquired by a newly-incorporated Canadian shell company, GHP Exploration Corporation, in exchange for 12,385,496 common shares. Since both entities were under common control, this transaction did not constitute a business combination under accounting principals generally accepted in Canada, and has been accounted for to recognize the continuity of interests of the shareholders of GHP Corporation in the consolidated assets, liabilities and operations of GHP Exploration Corporation. On April 17, 1997, GHP Exploration Corporation amalgamated with Laverty Industrial Development Inc., a company whose shares were quoted on the Canadian Dealing Network ("Laverty"), to form a new British Columbia corporation named "GHP Exploration Corporation". Under the terms of the amalgamation agreement, each common share of the Company and each 15 common shares of Laverty were exchanged into one common share of the amalgamated company. A total of 465,392 common shares were issued to the former Laverty shareholders. The amalgamated entity was continued into the Yukon Territory on April 30, 1997. This amalgamation was accounted for as an acquisition of Laverty by GHP Exploration Corporation using the purchase method of accounting; however, the fair market value of the acquired net assets of Laverty was nominal. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS GHP Exploration Corporation ("GHP" or the "Company") is a junior oil and gas company incorporated under the laws of the Yukon Territory for the purpose of exploring for, developing and producing crude oil, natural gas and natural gas liquids in the United States and internationally. The Company's U.S. exploration and production activities are focused along the Texas and Louisiana gulf coast, both onshore and offshore, and in the Delaware Basin of West Texas. The Company's international activities are currently focused in Egypt and Tunisia. The Company's future financial condition, including the recoverability of the Company's oil and gas investments, and the results of its operations is dependent upon the discovery of economically recoverable reserves, its ability to obtain the necessary financing complete development of the reserves and the future profitable production from its developed reserves. 5 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U. S. Dollars) Inherent in these requirements is the importance of product prices and the costs of acquiring, finding, developing and producing crude oil and natural gas reserves. The prices received by the Company from the sale of its crude oil and natural gas production are subject to fluctuation in response to changes in supply, market uncertainty and a variety of factors beyond the Company's control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the level of consumer demand, and the price and availability of alternative fuels. PRINCIPLES OF CONSOLIDATION 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; GHP Corporation (a Colorado corporation), GHP Exploration (Tunisia) Ltd. (a Bermuda corporation), GHP Exploration (Egypt) Ltd. (a Bermuda corporation) and GHP Exploration (West Gharib) Ltd. (a Bermuda corporation). A substantial portion of the Company's activities are conducted jointly with industry partners and the accompanying consolidated financial statements reflect only the Company's proportionate interest in such activities. OIL AND GAS PROPERTIES In connection with the events described in Note 1, the Company changed its method of accounting for oil and gas exploration and development activities from the successful efforts method to the full cost method. Due to the limited operating history of the Company, no adjustment to historical results was required. 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 centres on a country-by-country basis. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from the sale of oil and gas properties are accounted for as reductions to 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, depletion and amortization (DD&A) of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities as determined by independent reservoir engineers. Unevaluated costs are excluded from the amortization base until the properties associated with these costs are evaluated and determined to be productive or become impaired. The net carrying value of the Company's oil and gas properties is limited to an estimated recoverable amount. This amount is determined by estimating the amount of future net revenues from proved properties based on period-end prices less future production, general and administrative, financing and site-restoration costs and production and income taxes, together with the value of unproved properties at the lower of cost and realizable value. When it is determined that the net realizable value is less than the carrying value of the oil and gas properties the impairment is charged to income. Provision is made in the accounts for estimated future net costs of well abandonments and site restoration, including removal of production facilities at the end of their useful life. Costs are based on estimates valued at year-end prices and in accordance 6 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) with the current legislation and industry practices. The annual provision is computed on a unit-of-production basis and is recorded as an expense for the year. CORPORATE ASSETS Corporate assets consists primarily of furniture, fixtures and computer equipment. Depreciation of these, 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. NET INCOME (LOSS) PER SHARE Net income (loss) per share is determined based on the weighted average number of common shares outstanding for the year. Common equivalent shares relating to options and warrants to purchase common shares were not included in the weighted average number of shares since their inclusion would not have been dilutive. FINANCIAL INSTRUMENTS The fair value of cash and short-term investments, receivables and accounts payable and accrued liabilities approximates their carrying value. The Company has no derivative financial instruments. 3. PROPERTY AND EQUIPMENT AS AT DECEMBER 31, 1997:
Accumulated Net Book Summary Cost DD&A Value -------- ------------ ------------ ------------ Crude oil & natural gas properties Proved properties (all located in the U.S.) $ 5,816,173 $ (3,446) $ 5,812,727 Unproved properties and properties under development: (not being amortized) United Stales 4,276,699 - 4,276,699 Egypt - - - Tunisia 781,535 - 781,535 Corporate assets 136,684 (19, 786) 116,898 ------------ ----------- ------------ $ 11,011,091 $ (23,232) $ 10,987,859 ============ =========== ============
The net recoverable amount calculated under the Company's ceiling test exceeded the carrying value of the Company's proved crude oil and natural gas holdings for the period ended and December 31, 1997, on both an undiscounted and a 10% discounted value basis. The carrying value of capital assets are subject to uncertainty associated with the quantity of oil and gas reserves, future production rates, commodity prices and other factors. Future events could materially change the carrying values recognized in the accompanying consolidated financial statements. 4. INCOME TAXES The Company has accumulated losses for income tax purposes in Canada and in the United States that may be applied to reduce future years' income tax liabilities. Such losses in Canada of $274,000 expire commencing in 2004 and such losses in the United States of $2.8 million expire commencing in 2008. 7 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) No recognition has been given in these consolidated financial statements to the future tax benefits that may result from the utilization of these losses for income tax purposes. The benefit, if any, of the application of these losses will be recognized when and to the extent they are realized. 5. SHAREHOLDERS' EQUITY SHARE CAPITAL AUTHORIZED: GHP's authorized capital consists of an unlimited number of common shares without par value. The Company's share capital for the year ended December 31, 1997 is set forth below:
Common Net Shares Consideration ------ ------------- (No. of shares) Common shares outstanding at December 31,1996 12,385,496 $ 4,204,121 Shares issued for cash 4,500,000 10,312,684 Shares issued in Laverty amalgamation (Note 2) 465,392 1 Shares issued for oil and gas property 65,000 143,000 ----------- ----------- Common shares outstanding at December 31, 1997 17,415,888 14,659,806 =========== ===========
STOCK OPTIONS The Company has a Director's and Management Stock Option Plan under which 1.930 million shares were reserved for issuance as at December 31, 1997. These options are exercisable until varying dates ranging from 2001 until 2003 at prices ranging from $.50 to $3.00 per share. Details of options outstanding are as follows:
Year Ended December 31. ----------------------- Balance, beginning of period 950,000 Granted during the period 980,000 Expired during the period - --------- Balance, end of period 1,930,000 =========
WARRANTS As at December 31,1997, the Company had 2,144 million warrants outstanding at an exercise price of $2.50 per share and which are exercisable until March 1, 1999. 8 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U. S. Dollars) 6. COMMITMENTS AND CONTINGENCIES As at December 31, 1997, future minimum annual lease payments under operating lease agreements for office premises and equipment for the next five years are as follows: 1998-$105,000, 1999-$105,000, 2000- $102,000, 2001- $102,000, 2002- $77,000. 7. RELATED PARTY TRANSACTIONS FINANCIAL SERVICES A financial services firm controlled by a director of the Company provided services to the Company totaling $48,930 in 1997, $46,343 in 1996, $4,735 in 1995, $7,086 in 1994 and $3,164 in 1993. NOTE PAYABLE On October 31, 1996, the Chairman and Chief Executive Officer of the Company converted his note receivable from the Company, totaling $544,498, into 1,088,996 common shares of the Company. 8. SEGMENT INFORMATION As at December 31, 1997, the Company and its subsidiaries operated in the United States, Tunisia and Canada within one dominant industry segment; the exploration for, and the development and production of crude oil and natural gas. Identifiable assets, revenues and net loss in each of these geographic areas are as follows:
IDENTIFIABLE ASSETS REVENUES NET LOSS ------ -------- -------- United States $14,916,318 $ 503,808 $ (425,728) Tunisia 781,534 - (12,093) Canada - - (273,861) ----------- ----------- ----------- $15,697,852 $ 503,808 $ (711,682) =========== =========== ===========
9. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES These financial statements have been prepared in accordance with accounting principles generally accepted in Canada ("Canadian GAAP"). In certain aspects, Canadian GAAP differs from accounting principles generally accepted in the United States ("U.S. GAAP") and from policies prescribed by the U.S. Securities and Exchange Commission. If U.S. GAAP had been followed, net income (loss) for each period and net income (loss) per share would have been the same as determined under Canadian GAAP. 9 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) 10. SUBSEQUENT EVENTS PRIVATE PLACEMENT In February 1998 the Company issued 3.888 million special warrants ("Special Warrants") at a price of$2.00 per Special Warrant. Each Special Warrant was exchangeable, without further payment, into one common share and one-half of one common share purchase warrant. Each whole common share purchase warrant entitles the holder to acquire an additional common share of the Company for a period of one year at a price of $2.50 per share. In addition, the Company granted to the agent of the Special Warrant placement 200,000 Agent's Special Warrants entitling the agent to acquire, without any payment, 200,000 share purchase warrants. In June 1998, the Company filed a final prospectus for the purpose of qualifying 3,888,000 common shares and 1,944,000 common share purchase warrants to be issued upon the exercise or deemed exercise of the 3,888,000 Special Warrants previously issued by the Company. EGYPT In March 1998, the Company entered into a Participation Agreement to acquire a 25% working interest in a 4.5 million acre block in Egypt's Sinai Peninsula ("Sinai Concession"). The minimum work requirement on the Sinai Concession totals $6 million to the 100% interest. The Company is required under its agreement to post a $2.4 million letter of guaranty for its share of the initial work requirements. Pursuant to the terms of the Participation Agreement, the Company was required to repay $1million of the concession holder's cost incurred to date. In 1998, the Company paid the concession holder $500,000 in cash and issued 214,592 common shares having a value of $500,000. In Apri1 1998, the Company entered into a Farmout Agreement to acquire a 30% working interest in the West Gharib Concession consisting of 2,530 square kilometres located on the Western shore of the Gulf of Suez basin. The application for the concession was accepted by the Egyptian government on November 17, 1997, and was ratified by the Egyptian government on June 1, 1998. The minimum work requirement on the concession totals $5 million to the 100% interest. The Company is required under its agreement to post a $1.5 million letter of guaranty for its share of the minimum work requirement. Pursuant to the terms of the Farmout Agreement, the Company was also required to repay $303,000 of the concession holder's cost incurred to date. SHARES ISSUED TO GHP CORPORATION 401 (K) RETIREMENT PLAN On March 30, 1998, the Company issued 25,000 Common Shares to the GHP Corporation 401 (k) Retirement Plan. 10 GHP EXPLORATION CORPORATION CONSOLIDATED BALANCE SHEETS (In U.S. Dollars)
September 30,1998 ----------------- (Unaudited) ASSETS CURRENT ASSETS Cash and short-term investments $ 2,725,822 Receivables 112,812 Prepaid expenses and other 389,736 ------------ 3,228,370 ------------ PROPERTY AND EQUIPMENT (NOTE 3) 13,248,439 ------------ $ 16,476,809 ============ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 588,747 SHAREHOLDERS' EQUITY Share capital (Note 5) 23,021,746 Deficit (7,133,684) ------------ 15,888,062 ------------ $ 16,476,809 ============
Approved by the Board of Directors: /s/ GEORGE H. PLEWES /s/ BARRY D. LASKER -------------------- ------------------- George H. Plewes Barry D. Lasker Director Director The accompanying notes are an integral part of these financial statements. 1 GHP EXPLORATION CORPORATION CONSOLIDATED STATEMENTS OF OPERATION AND DEFICIT (In U.S. Dollars)
September 30, 1998 ---- REVENUES Interest income $ 218,542 Oil and gas sales 304,786 ----------- 523,328 EXPENSES General and administrative 1,470,685 Depreciation, depletion and Amortization 242,924 Impairment of oil and Gas properties 4,434,572 Oil and gas production 159,836 ----------- 6,308,017 ----------- NET LOSS FOR THE PERIOD (5,784,689) DEFICIT, AT BEGINNING OF PERIOD (1,348,995) ----------- DEFICIT, AT END OF PERIOD $(7,133,684) ----------- NET LOSS PER SHARE $ (0.30) ===========
The accompanying notes are integral part of these financial statements. 2 GHP EXPLORATION CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOW (In U.S. Dollars)
Nine Months Ended September 30, 1998 ------------------ (Unaudited) OPERATING ACTIVITIES Net loss for the period $(5,784,689) Add Items not Involving cash: Depreciation, depletion and amortization 242,924 Impairment of oil and gas properties 4,434,572 ----------- (1,107,193) Changes in non-cash working capital balances: Decrease in receivables 751,649 Decrease in prepaid expenses and other (283,009) Increase in accounts payable and accrued liabilities 12,804 ----------- Cash used in operating activities (460,312) ----------- INVESTING ACTIVITIES Exploration and acquisition of properties (Note 3) (5,740,011) Non-cash portion of oil and gas property expenditures (1,811,098) Issuance of common shares for properties (Note 5) (1,145,000) Acquisition of corporate assets (53,065) ----------- Cash used in investing activities (8,749,174) ----------- FINANCING ACTIVITIES Issuance of common shares (Note 5) 7,833,500 Share issue expenses (Note 5) (616,560) Issuance of common share for properties (Note 5) 1,145,000 ----------- Cash provided by financing activities 8,361,940 ----------- NET DECREASE IN CASH AND SHORT-TERM INVESTMENTS (847,546) Cash and short-term investments, beginning of period 3,573,368 ----------- Cash and short-term investments, end of period $ 2,725,822 ===========
The accompanying notes are an integral part of these financial statements. 3 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) (All amounts as at September 30, 1998 and for the nine months then ended are unaudited) 1. BASIS OF PRESENTATION On February 16, 1997, GHP Corporation, a company incorporated in the United States, was acquired by a newly-incorporated Canadian shell company, GHP Exploration Corporation, in exchange for 12,385,496 common shares. Since both entities were under common control, this transaction did not constitute a business combination under accounting principals generally accepted in Canada, and has been accounted for to recognize the continuity of interests of the shareholders of GHP Corporation in the consolidated assets, liabilities and operations of GHP Exploration Corporation. On April 17, 1997, GHP Exploration Corporation amalgamated with Laverty Industrial Development Inc., a company whose shares were quoted on the Canadian Dealing Network ("Laverty"), to form a new British Columbia corporation named "GHP Exploration Corporation". Under the terms of the amalgamation agreement, each common share of the Company and each 15 common shares of Laverty were exchanged into one common share of the amalgamated company. A total of 465,392 common shares were issued to the former Laverty shareholders. The amalgamated entity was continued into the Yukon Territory on April 30, 1997. This amalgamation was accounted for as an acquisition of Laverty by GHP Exploration Corporation using the purchase method of accounting; however, the fair market value of the acquired net assets of Laverty was nominal. On September 30,1998, the Company agreed to merge with Profco Resources Ltd. ("Profco") by way of a share exchange transaction, subject to the satisfaction of certain conditions including regulatory and court approvals and approval by the Company's shareholders. This merger was completed in the fourth quarter of 1998, with GHP shareholders receiving .87 of a common share of Profco for each common share of GHP. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS GHP Exploration Corporation ("GHP" or the "Company") is a junior oil and gas company incorporated under the laws of the Yukon Territory for the purpose of exploring for, developing and producing crude oil, natural gas and natural gas liquids in the United States and internationally. The Company's U.S. exploration and production activities are focused along the Texas and Louisiana gulf coast, both onshore and offshore, and in the Delaware Basin of West Texas. The Company's international activities are currently focused in Egypt and Tunisia. The Company's future financial condition, including the recoverability of the Company's oil and gas investments, and the results of its operations is dependent upon the discovery of economically recoverable reserves, its ability to obtain the necessary financing complete development of the reserves and the future profitable production from its developed reserves. 4 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) Inherent in these requirements is the importance of product prices and the costs of acquiring, finding, developing and producing crude oil and natural gas reserves. The prices received by the Company from the sale of its crude oil and natural gas production are subject to fluctuation in response to changes in supply, market uncertainty and a variety of factors beyond the Company's control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the level of consumer demand, and the price and availability of alternative fuels. PRINCIPLES OF CONSOLIDATION 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; GHP Corporation (a Colorado corporation), GHP Exploration (Tunisia) Ltd. (a Bermuda corporation), GHP Exploration (Egypt) Ltd. (a Bermuda corporation) and GHP Exploration (West Gharib) Ltd. (a Bermuda corporation). A substantial portion of the Company's activities are conducted jointly with industry partners and the accompanying consolidated financial statements reflect only the Company's proportionate interest in such activities. OIL AND GAS PROPERTIES In connection with the events described in Note 1, the Company changed its method of accounting for oil and gas exploration and development activities from the successful efforts method to the full cost method. Due to the limited operating history of the Company, no adjustment to historical results was required. 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 centres on a country-by-country basis. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from the sale of oil and gas properties are accounted for as reductions to 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, depletion and amortization (DD&A) of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities as determined by independent reservoir engineers. Unevaluated costs are excluded from the amortization base until the properties associated with these costs are evaluated and determined to be productive or become impaired. The net carrying value of the Company's oil and gas properties is limited to an estimated recoverable amount. This amount is determined by estimating the amount of future net revenues from proved properties based on period-end prices less future production, general and administrative, financing and site-restoration costs and production and income taxes, together with the value of unproved properties at the lower of cost and realizable value. When it is determined that the net realizable value is less than the carrying value of the oil and gas properties the impairment is charged to income. Provision is made in the accounts for estimated future net costs of well abandonments and site restoration, including removal of production facilities at the end of their useful life. Costs are based on estimates valued at year-end prices and in accordance 5 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) with the current legislation and industry practices. The annual provision is computed on a unit-of-production basis and is recorded as an expense for the year. CORPORATE ASSETS Corporate assets consists primarily of furniture, fixtures and computer equipment. Depreciation of these, 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. NET INCOME (LOSS) PER SHARE Net income (loss) per share is determined based on the weighted average number of common shares outstanding for the period. Common equivalent shares relating to options and warrants to purchase common shares were not included in the weighted average number of shares since their inclusion would not have been dilutive. FINANCIAL INSTRUMENTS The fair value of cash and short-term investments, receivables and accounts payable and accrued liabilities approximates their carrying value. The Company has no derivative financial instruments. INTERIM FINANCIAL STATEMENTS In the opinion of management, the unaudited interim consolidated financial statements reflect all adjustments, which consist only of normal and reoccurring adjustments, necessary to present fairly the financial position at September 30, 1998 and the results of operations and the changes in financial position for the nine-month period ended September 30, 1998, in accordance with accounting principles generally accepted in Canada. 3. PROPERTY AND EQUIPMENT As at September 30, 1998:
Accumulated Net Book SUMMARY Cost DD&A Value ------- ------------ ------------- ------------ Crude oil & natural gas properties Proved properties (U.S. only) $ 12,144,429 $ (4,653,471) $ 7,490,958 Unproved properties and properties under development: (not being amortized) United States 2,636,932 - 2,636,932 Egypt 1,780,442 - 1,780,442 Tunisia 1,197,615 - 1,197,615 Corporate assets 189,749 (47,257) 142,492 $ 17,949,167 $ (4,700,728) $ 13,248,439 ============ ============ ============
6 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) The net recoverable amount calculated under the Company's ceiling test exceeded the carrying value of the Company's proved crude oil and natural gas holdings for the periods ended September 30, 1998, on both an undiscounted and a 10% discounted value basis. The carrying value of capital assets are subject to uncertainty associated with the quantity of oil and gas reserves, future production rates, commodity prices and other factors. Future events could materially change the carrying values recognized in the accompanying consolidated financial statements. On August 31, 1998, the Company sold its interest in a non-producing oil and gas property for cash, an overriding royalty interest and other consideration equal to approximately $600,000. It is undeterminable whether the Company will be required to record a loss on the sale of this asset until the results from two wells the Company is currently drilling are known. 4. INCOME TAXES The Company has accumulated losses for income tax purposes in Canada and in the United States that may be applied to reduce future years' income tax liabilities. Such losses in Canada of $274,000 expire commencing in 2004 and such losses in the United States of$2.8 million expire commencing in 2008. No recognition has been given in these consolidated financial statements to the future tax benefits that may result from the utilization of these losses for income tax purposes. The benefit, if any, of the application of these losses will be recognized when and to the extent they are realized. 5. SHAREHOLDERS' EQUITY SHARE CAPITAL AUTHORIZED: GHP's authorized capital consists of an unlimited number of common shares without par value. 7 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) The Company's share capital for the nine months ended September 30, 1998 is set forth below:
Common Net Shares Consideration ------ ------------- (No. of shares) Common shares outstanding at December 31, 1997 17,415,888 14,659,806 ----------- ----------- Shares issued for cash 3,888,000 7.159,440 Shares issued for oil and gas properties 514,592 1,145,000 Shares issued to the GHP Corporation 401 (k) Plan 25,000 57,500 ----------- ----------- Common shares outstanding at September 30, 1998 21,843,480 $23,021,746 ----------- -----------
STOCK OPTIONS The Company has a Director's and Management Stock Option Plan under which 2.277 million shares were reserved for issuance as at September 30, 1998. These options are exercisable until varying dates ranging from 2001 until 2003 at prices ranging from $.50 to $3.00 per share. Details of options outstanding are as follows:
Nine Months Ended September 30,1998 ----------------- (Unaudited) Balance, beginning of period 1,930,000 Granted during the period 397,000 Expired during the period (50,000) --------- Balance, end of period 2,277,000 =========
WARRANTS As at September 30,1998, the Company had 2,144 million warrants outstanding at an exercise price of $2.50 per share and which are exercisable until March 1, 1999. 8 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) 6. SEGMENT INFORMATION As at December 31, 1997, the Company and its subsidiaries operated in the United States, Egypt, Tunisia and Canada within one industry segment; the exploration for, and the development and production of crude oil and natural gas. Identifiable assets, revenues and net loss in each of these geographic areas are as follows:
IDENTIFIABLE ASSETS REVENUES NET LOSS ------------ -------- -------- United States $13,248,752 $523,328 $(5,483,097) Egypt 2,030,442 - 10,638 Tunisia 1,197,615 - (17,093) Canada - - (273,861) ------------ -------- ----------- $16,476,809 $523,328 $(5,784,689)
7. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES These financial statements have been prepared in accordance with accounting principles generally accepted in Canada ("Canadian GAAP"). In certain aspects, Canadian GAAP differs from accounting principles generally accepted in the United States ("U.S. GAAP") and from policies prescribed by the U.S. Securities and Exchange Commission. If U.S. GAAP had been followed, net income (loss) for each period and net income (loss) per share would have been the same as determined under Canadian GAAP. 9 GHP EXPLORATION CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (In U.S. Dollars) 8. OTHER MATTERS PRIVATE PLACEMENT In February 1998 the Company issued 3.888 million special warrants ("Special Warrants") at a price of$2.00 per Special Warrant. Each Special Warrant was exchangeable, without further payment, into one common share and one-half of one common share purchase warrant. Each whole common share purchase warrant entitles the holder to acquire an additional common share of the Company for a period of one year at a price of $2.50 per share. In addition, the Company granted to the agent of the Special Warrant placement 200,000 Agent's Special Warrants entitling the agent to acquire, without any payment, 200,000 share purchase warrants. In June 1998, the Company filed a final prospectus for the purpose of qualifying 3,888,000 common shares and 1,944,000 common share purchase warrants to be issued upon the exercise or deemed exercise of the 3,888,000 Special Warrants previously issued by the Company. EGYPT In March 1998, the Company entered into a Participation Agreement to acquire a 25% working interest in a 4.5 million acre block in Egypt's Sinai Peninsula ("Sinai Concession"). The minimum work requirement on the Sinai Concession totals $6 million to the 100% interest. The Company is required under its agreement to post a $2.4 million letter of guaranty for its share of the initial work requirements. Pursuant to the terms of the Participation Agreement, the Company was required to repay $1million of the concession holder's cost incurred to date. In 1998, the Company paid the concession holder $500,000 in cash and issued 214,592 common shares having a value of $500,000. In Apri1 1998, the Company entered into a Farmout Agreement to acquire a 30% working interest in the West Gharib Concession consisting of 2,530 square kilometres located on the Western shore of the Gulf of Suez basin. The application for the concession was accepted by the Egyptian government on November 17, 1997, and was ratified by the Egyptian government on June 1, 1998. The minimum work requirement on the concession totals $5 million to the 100% interest. The Company is required under its agreement to post a $1.5 million letter of guaranty for its share of the minimum work requirement. Pursuant to the terms of the Farmout Agreement, the Company was also required to repay $303,000 of the concession holder's cost incurred to date. SHARES ISSUED TO GHP CORPORATION 401 (k) RETIREMENT PLAN On March 30, 1998, the Company issued 25,000 Common Shares to the GHP Corporation 401 (k) Retirement Plan. 10