Annual Report Submitted on a Form 20-F

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

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

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

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:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Not applicable ¨

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

This annual report on Form 20-F includes audited consolidated financial statements of OAO Tatneft (“Tatneft”) and its consolidated subsidiaries as at December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, 2001 and 2000. These financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“U.S. GAAP”), and the information contained in such financial statements is expressed in constant rubles of December 31, 2002 purchasing power, except as otherwise indicated.

On December 31, 2002, the official ruble/U.S. dollar exchange rate reported by the Central Bank of the Russian Federation (the “Central Bank”) was US$1.00 = RR31.78. On June 25, 2003 the official ruble/U.S. dollar exchange rate reported by the Central Bank was US$1.00 = RR30.35. The Federal Reserve Bank of New York does not report a noon buying rate for rubles. In providing an exchange rate, we do not represent that ruble amounts have been, could have been or could be converted into U.S. dollars at that or any other exchange rate on that or any other date. See “Item 3—Key Information—Exchange Rates.”

Our records and financial statements for Russian purposes are prepared in accordance with the Regulations on Accounting and Reporting of the Russian Federation (“RAR”). RAR differ in significant respects from U.S. GAAP, and financial statements prepared in accordance with RAR are not included in this annual report.

Unless the context otherwise requires, in this annual report all references to the “Company” or “Tatneft” are to OAO Tatneft, and all references to “we,” “us” or “our” are to Tatneft and its consolidated subsidiaries and references to “you” or “your” are to holders of our ADSs.

Certain information presented in this annual report is presented on the basis of official public documents published by Russian federal, regional and local governments and federal agencies, and has been presented on the authority of such documents. In addition, certain information presented herein is based on other third-party published sources. We have not independently verified the accuracy of such information.

This annual report contains information concerning our oil and gas reserves derived from the report of Miller and Lents, Ltd. (“Miller and Lents”), oil and gas consultants based in Houston, Texas, dated May 16, 2003 (the “Reserves Report”), included as Appendix A to this annual report. While the Reserves Report has been prepared in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a), it is based on economic assumptions that may prove to be incorrect. In particular, the Russian economy is more unstable and subject to more significant and sudden changes than the economies of many other countries and, therefore, economic assumptions in the Russian Federation (“Russia”) are subject to a high degree of uncertainty. Readers should not place undue reliance on the forward-looking statements in the Reserves Report, on the ability of the Reserves Report to predict actual reserves or on comparisons of similar reports concerning companies established in countries with more mature economic systems. As indicated in the Reserves Report, the reserves information is based on the reserves of 63 developed and producing and seven undeveloped oil fields covered by exploration, production or combined exploration and production licenses as of January 1, 2003.

Like many other Russian and European oil companies, we use the metric ton as the standard unit of measurement for quantities of crude oil. For convenience, certain amounts of crude oil have been translated from tons to barrels. These translations were made at the rate of 7.123 barrels per ton of crude oil, reflecting the weighted average density of our crude oil reserves. However, the actual density of our crude oil reserves may vary by approximately 10% above and below this weighted average, such that actual barrel amounts may vary from this convenience translation.

On June 27, 1997, the annual shareholders’ meeting approved a 100:1 share split, (the “Share Split”), which the Federal Commission on the Securities Market of the Russian Federation (the “FCSM”) approved on April 15, 1998 and which became effective in our register on April 30, 1998. Accordingly, figures given herein relating to ordinary shares, nominal value one ruble per share, of Tatneft (the “Ordinary Shares”) for periods prior to April 30, 1998 have been adjusted to give effect to the share split. In conjunction with the issue of the new Ordinary Shares in connection with the share split, the ratio of Ordinary Shares to ADSs was changed from 1/5:1 to 20:1. Thus, each ADS represents the right to receive 20 post-share split Ordinary Shares. Except as otherwise indicated herein, the numbers of ADSs are also expressed by giving retroactive effect to the share split.

Prior to December 20, 2001, the nominal value of our shares was 10 kopeks per share. On June 22, 2001, the annual shareholders’ meeting approved a ten-fold increase in our charter capital by increasing the nominal value of both classes of our shares from 10 kopeks to 1 ruble. The FCSM approved the charter capital increase on November 20, 2001, and the charter capital increase became

effective on December 20, 2001 upon state registration of the correspondent amendments to our Charter. The ratio of Ordinary Shares to ADSs remained unchanged.

Certain statements in this annual report are not historical facts and are “forward-looking” (as such term is defined in the United States Private Securities Litigation Reform Act of 1995). We may from time to time make written or oral forward-looking statements in reports to shareholders and in other communications. This annual report contains forward-looking statements under the headings “Item 4—Information on the Company,” “Item 5—Operating and Financial Review and Prospects” and “Item 11—Quantitative and Qualitative Disclosures About Market Risk.” Examples of such forward-looking statements include, but are not limited to:

Words such as “believes,” “anticipates,” “expects,” “intends” and “plans” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks exist that the predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers that a number of important factors could cause actual results to differ materially from the plans, objectives, expectations, estimates and intentions expressed in such forward-looking statements. These factors include:

This list of important factors is not exhaustive; when relying on forward-looking statements to make decisions with respect to our ADSs, investors and others should carefully consider the foregoing factors and other uncertainties and events, especially in light of the difficult political, economic, social and legal environment in which we operate. Such forward-looking statements speak only at the date on which they are made, and we do not undertake any obligation to update or revise any of them, whether as a result of new information, future events or otherwise. We do not make any representation, warranty or prediction that the results anticipated by such forward-looking statements will be achieved, and such forward-looking statements represent, in each case, only one of many possible scenarios and should not be viewed as the most likely or standard scenario.

The selected consolidated financial data set forth below have been derived from our audited consolidated financial statements for each of the years in the five year period ended December 31, 2002. The selected consolidated financial data as at December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002 should be read in conjunction with, and are qualified in their entirety by reference to, our consolidated financial statements and the notes thereto included elsewhere in this annual report. The information below should be read in conjunction with “Item 5—Operating and Financial Review and Prospects.”

U.S. GAAP recognizes that the degree of inflation in a country’s economy may become so great that conventional financial statements prepared in historical local currency lose much of their significance and general price-level financial statements become more meaningful. General price-level financial statements are financial statements that have been restated to account for inflation, and such financial statements are required by U.S. GAAP when a country’s economy experiences “hyperinflation.”

As measured by Russia’s consumer price index (“CPI”), annual inflation in Russia was 15.1%, 18.8% and 20.1% in 2002, 2001 and 2000, respectively. Given Russia’s past inflation history, Russia’s economy is considered hyperinflationary for purposes of our 2002 consolidated financial statements. Accordingly, the following selected consolidated financial data and our consolidated financial statements have been prepared in accordance with Accounting Principles Board Statement 3, Financial Statements Restated for General Price-Level Changes. These figures are thus expressed in millions of constant rubles as of December 31, 2002 purchasing power. All other financial amounts are also expressed in these terms, unless otherwise stated. As of January 1, 2003, Russia’s economy ceased to be considered hyperinflationary for accounting purposes.

The monetary gain included in our consolidated statement of operations reflects gains attributable to the effect of Russian inflation on the monetary liabilities we owed during each period, net of the loss attributable to the effect of inflation on monetary assets held. Assets and liabilities are called “monetary” for purposes of general price level accounting if their amounts are fixed by contract or otherwise in terms of numbers of currency units regardless of changes in specific prices or in the general price level. Examples of monetary assets and liabilities include accounts receivable, accounts payable and cash.

The following tables show, for the periods indicated, certain information regarding the exchange rate between the ruble and the U.S. dollar, based on the official exchange rate quoted by the Central Bank of Russia. These rates may differ from the actual rates used in the preparation of our consolidated financial statements and other financial information appearing herein.

On June 25, 2003, the ruble to U.S. dollar exchange rate reported by the Central Bank was US$1.00 = RR30.35. The Federal Reserve Bank of New York does not report a noon buying rate for rubles. No representation is made that ruble or U.S. dollar amounts stated herein could have been converted into U.S. dollars or rubles, as the case may be, at any particular rate or at all. The ruble is generally not convertible outside Russia. A market exists within Russia for the conversion of rubles into other currencies, but the limited availability of other currencies may inflate their value relative to the ruble. See “Item 10—Additional Information—Exchange Controls” for a description of Russian currency exchange controls.

We have described below the risks and uncertainties that our management believes are material, but these risks and uncertainties may not be the only ones we face. Additional risks and uncertainties, including those we currently do not know or deem immaterial, may also result in decreased revenues, increased expenses, or other events that could result in a decline in the price of our ADSs.

Since 1991, Russia has sought to transform itself from a one-party state with a centrally planned economy to a pluralist democracy with a market-oriented economy. As a result of the sweeping nature of the reforms, and the failure of some of them, the Russian political system remains vulnerable to popular dissatisfaction, as well as to unrest by particular social and ethnic groups. Significant political instability could have a material adverse effect on the value of foreign investments in Russia, including the value of our ADSs.

Governmental instability could adversely affect the value of investments in Russia and the value of our ADSs.

The composition of the Russian government—the prime minister and the other heads of federal ministries—has at times been highly unstable. Six different prime ministers, for example, headed governments between March 1998 and May 2000. On December 31, 1999, President Yeltsin unexpectedly resigned and Vladimir Putin was subsequently elected President on March 26, 2000. While President Putin has maintained governmental stability and the general direction of reform, he may adopt a different approach over time. Future changes in the government, major policy shifts or disagreements between President Putin and Russia’s parliament could also disrupt or reverse economic or regulatory reforms. The next elections to the State Duma, the lower house of the Russian parliament, are scheduled for December 2003, and the next presidential elections are scheduled for March 2004. Any disruption or reversal of the reform policies or the recurrence of governmental instability could have a material adverse effect on our company and the value of investments in Russia, and the value of our ADSs could be reduced.

Conflicts between federal and regional authorities and other political conflicts could create an uncertain operating environment that could hinder our long-term planning ability and could adversely affect the value of investments in Russia.

The Russian Federation is a federation of republics, territories, regions, cities of federal importance and autonomous areas. The delineation of authority among the members of the Russian Federation and the federal governmental authorities is often unclear. Some of these sub-federal political units, such as Tartarstan, exercise considerable power over their internal affairs pursuant to the Russian Constitution or, in certain cases, pursuant to agreements with the federal authorities. See “Appendix C—The Republic of Tartarstan—History of Relationship with Russia.” The Russian political system is therefore vulnerable to tension and conflict between federal and regional authorities, and between different authorities within the federal government over various issues, including tax revenues, authority for regulatory matters and regional autonomy. Our operations may be adversely affected by these tensions and conflicts.

Additionally, ethnic, religious, historical and other divisions have, on occasion, given rise to tensions, and in certain cases, to military conflict. Russian military forces have been engaged in Chechnya in the past and are currently involved in ground and air operations there, and the Chechen separatists have conducted terrorist attacks throughout Russia. The spread of this conflict, or its intensification, could have significant political consequences, including the imposition of a state of emergency in some or all of the Russian Federation. These events could materially adversely affect the value of investments in Russia, including the value of our ADSs.

Crime and corruption could disrupt our ability to conduct our business and could adversely affect our financial condition and results of operations.

The political and economic changes in Russia since 1991 have resulted in reduced policing of society and increased lawlessness. The Russian and international press have reported high levels of organized criminal activity and official corruption in Russia and other countries of the former Soviet Union, including the bribing of officials. Press reports have also described instances in which government officials have engaged in selective investigations and prosecutions to further commercial interests of select constituencies. Additionally, published reports indicate that a significant number of Russian media regularly publish slanted articles in return for payment. Our financial condition and results of operations could be adversely affected by illegal activities, corruption or by claims alleging our involvement in illegal activities, which, in turn, could adversely affect the value of our ADSs or Ordinary Shares.

Social instability in Russia could lead to increased support for renewed centralized authority and a rise in nationalism or violence, which could harm our ability to conduct our business effectively.

Social instability in Russia, coupled with difficult economic conditions, could lead to increased support for centralized authority and a rise in nationalism. The failure of the government and many private enterprises to pay full salaries on a regular basis and the failure of salaries and benefits generally to keep pace with the rapidly increasing cost of living have led in the past, and could lead in the future, to labor and social unrest and increased support for a renewal of centralized authority, increased nationalism, restrictions on foreign involvement in the economy of Russia, and increased violence. These sentiments could lead to restrictions on foreign ownership of Russian companies in the oil and gas industry or large-scale nationalization or expropriation of foreign-owned assets or businesses. Any of these could restrict our operations and lead to the loss of revenue, adversely affecting us.

Since the dissolution of the Soviet Union, the Russian economy has experienced at various times:

The Russian economy has been subject to abrupt downturns. In particular, on August 17, 1998, in the face of a rapidly deteriorating economic situation, the Russian government defaulted on its ruble-denominated securities, the Central Bank stopped its support of the ruble, and a temporary moratorium was imposed on certain hard currency payments. These actions resulted in an immediate and severe devaluation of the ruble and a sharp increase in the rate of inflation; a dramatic decline in the prices of Russian debt and equity securities; and an inability of Russian issuers to raise funds in the international capital markets.

These problems were aggravated by the near collapse of the Russian banking sector after the events of August 17, 1998, as evidenced by the revocation of the banking licenses of a number of major Russian banks. This further impaired the ability of the banking sector to act as a consistent source of liquidity to Russian companies, and resulted in the losses of bank deposits in some cases.

There can be no assurance that recent trends in the Russian economy—such as the increase in the gross domestic product, a relatively stable ruble, and a reduced rate of inflation—will continue or will not be abruptly reversed. Moreover, the recent fluctuations in international oil and gas prices, the strengthening of the ruble in real terms relative to the U.S. dollar and the consequences of a relaxation in monetary policy, or other factors, could adversely affect Russia’s economy and our business in the future.

Russia’s physical infrastructure is in very poor condition, which could disrupt normal business activity.

Russia’s physical infrastructure largely dates back to the Soviet times and has not been adequately funded and maintained over the past decade. Particularly affected are the rail and road networks; power generation and transmission; communication systems; and building stock. During the winter of 2000-2001, electricity and heating shortages in Russia’s far-eastern Primorye region seriously disrupted the local economy. In August 2000, a fire at the main communications tower in Moscow interrupted television and radio broadcasting and the operation of mobile telephones for several weeks. Road conditions throughout Russia are poor,

with many roads not meeting minimum quality requirements. The federal government is actively considering plans to reorganize the nation’s rail and telephone systems, and restructuring of the electricity sector is in progress. Any such reorganization, and the restructuring, may result in increased charges and tariffs while failing to generate the anticipated capital investment needed to repair, maintain and improve these systems.

The deterioration of Russia’s physical infrastructure harms the national economy, disrupts the transportation of goods and supplies, adds costs to doing business in Russia and can interrupt business operations, and this could have a material adverse effect on our business and the value of our ADSs.

Fluctuations in the global economy may adversely affect Russia’s economy and our business.

Russia’s economy is vulnerable to market downturns and economic slowdowns elsewhere in the world. As has happened in the past, financial problems or an increase in the perceived risks associated with investing in emerging economies could dampen foreign investment in Russia and adversely affect the Russian economy. Additionally, because Russia produces and exports large amounts of oil and gas, the Russian economy is especially vulnerable to changes in the prices of such commodities on the world market and a decline in their prices could slow or disrupt the Russian economy. These developments could severely limit our access to capital and could adversely affect the purchasing power of our customers and thus our business.

Weaknesses relating to the Russian legal system and Russian legislation create an uncertain environment for investment and for business activity and thus could have a material adverse effect on an investment in our ADSs.

The following aspects of the Russian legal system create uncertainty with respect to many of the legal and business decisions that we make:

All of these weaknesses could affect our ability to enforce our rights under our licenses and under our contracts, or to defend ourselves against claims by others. Furthermore, we cannot assure you that regulators, judicial authorities or third parties will not challenge our compliance with applicable laws, decrees and regulations.

Russian laws and regulations may change in ways that adversely affect our business.

The Russian legal system and the body of laws on private enterprises continue to experience frequent changes. We cannot assure you that the legislature, federal or local regulators, or the president will not issue new edicts, decrees, laws or regulations adversely affecting our business, including:

Lack of independence and inexperience of the judiciary and the difficulty of enforcing court decisions and governmental discretion in instigating, joining and enforcing claims could prevent us or you from obtaining effective redress in a court proceeding, materially adversely affecting an investment in our ADSs.

The independence of the judicial system and its immunity from economic, political and nationalistic influences in Russia remain largely untested. The court system is understaffed and underfunded. Judges and courts are generally inexperienced in the area of business and corporate law. As in other civil law countries, judicial precedents generally have no binding effect on subsequent decisions. Not all Russian legislation and court decisions are readily available to the public or organized in a manner that facilitates understanding. The Russian judicial system can be slow. Enforcement of court orders can in practice be very difficult in Russia. All of these factors make judicial decisions in Russia difficult to predict and effective redress uncertain. Additionally, court claims are often used in furtherance of political aims. We may be subject to such claims and may not be able to receive a fair hearing.

These uncertainties also extend to property rights. During Russia’s transformation from a centrally planned economy to a market economy, legislation has been enacted to protect private property against expropriation and nationalization. However, it is possible that due to the lack of experience in enforcing these provisions and due to potential political changes, these protections would not be enforced in the event of an attempted expropriation or nationalization. Some government entities have tried to renationalize privatized businesses. Expropriation or nationalization of any of our entities, their assets or portions thereof, potentially without adequate compensation, would have a material adverse effect on us.

Unlawful or arbitrary government action may have an adverse affect on our business and the value of investment in our ADSs.

Government authorities have a high degree of discretion in Russia and at times exercise their discretion arbitrarily, without hearing or prior notice, and sometimes in a manner that is contrary to law. Moreover, government authorities also have the power in certain circumstances to interfere with the performance of, nullify or terminate contracts.

Unlawful or arbitrary governmental actions have included withdrawal of licenses, sudden and unexpected tax audits, criminal prosecutions and civil actions. Federal and local government entities have also used common defects in matters surrounding share issuances and registration as pretexts for court claims and other demands to invalidate such issuances and registrations and/or to void transactions, often for political purposes. Unlawful or arbitrary government action, if directed at us, could have a material adverse effect on our business and on the value of our ADSs.

Russia’s developing corporate and securities laws and regulations may limit our ability to attract future investment.

The regulation and supervision of the securities market, financial intermediaries and issuers is considerably less well developed in Russia than in the United States and Western Europe. Disclosure and reporting requirements, anti-fraud safeguards, insider trading restrictions and fiduciary duties are relatively new to Russia and are unfamiliar to most Russian companies and managers. While some important areas are subject to virtually no oversight, the regulatory requirements imposed on Russian issuers in other areas result in delays in conducting securities offerings and in accessing the capital markets. It is often unclear whether, or how, regulations, decisions and letters issued by the various regulatory authorities apply to our company. As a result, we may be subject to fines or other enforcement measures despite our best efforts at compliance, which could cause our financial results to suffer and harm our business.

Shareholder liability under Russian legislation could cause us to become liable for the obligations of our subsidiaries.

The Civil Code and the Russian Federal Law on Joint-Stock Companies (“Joint-Stock Companies Law”) generally provide that shareholders in a Russian joint stock company are not liable for the obligations of the joint stock company and bear only the risk of loss of their investment. This may not be the case, however, when one company is capable of determining decisions made by another company. The company capable of determining such decisions is called an “effective parent.” The company whose decisions are capable of being so determined is called an “effective subsidiary.” The effective parent bears joint and several responsibility for transactions concluded by the effective subsidiary in carrying out these decisions if:

In addition, an effective parent may be secondarily liable for an effective subsidiary’s debts if it becomes insolvent or bankrupt as a result of actions of such an effective parent. This is the case without regard to how the effective parent’s capability to determine decisions of the effective subsidiary arises. For example, this liability could arise through ownership of voting securities, by contract or otherwise. Shareholders (other than the effective parent) of the effective subsidiary may claim compensation for the effective subsidiary’s losses from the effective parent that caused the effective subsidiary to take action(s) or fail to take action(s) knowing that such action(s) or failure to take action(s) would result in losses. Accordingly, in our position as an effective parent, if so deemed, we could be liable in some cases, for the debts of our effective subsidiaries. This liability could materially adversely affect us.

A shareholder of an effective parent should not itself be liable for the debts of the effective parent’s effective subsidiary, unless that shareholder is itself an effective parent of the effective parent. Accordingly, a shareholder of ours is not personally liable for our debts or those of our effective subsidiaries unless it controls our business.

In general, minority shareholder protection under Russian law derives from supermajority shareholder approval requirements for certain corporate action (including “interested party” transactions discussed in more detail below), as well as from the ability of a shareholder to demand that the company purchase the shares held by that shareholder if that shareholder voted against or abstained from voting on certain types of action. While these protections are similar to the types of protections available to minority shareholders in U.S. corporations, in practice corporate governance standards for many Russian companies have proven to be poor, and minority shareholders in Russian companies have suffered losses due to abusive share dilutions, asset transfers and transfer pricing practices. Shareholders’ meetings have been irregularly conducted, and shareholder resolutions have not always been respected by management.

In addition, where they apply, the supermajority shareholder approval requirement is met by a vote of 75% of all voting shares that are present at a shareholders’ meeting. Thus, controlling shareholders owning less than 75% of outstanding shares of a company may have a 75% or more voting power if certain minority shareholders are not present at the meeting. In situations where controlling shareholders effectively have 75% or more of the voting power at a shareholders’ meeting they are in a position to approve measures requiring supermajority shareholder approval, which could be prejudicial to the interests of minority shareholders.

Disclosure and reporting requirements and anti-fraud legislation have been enacted in Russia only recently. Most Russian companies and managers are not accustomed to restrictions on their activities arising from these requirements. The concept of fiduciary duties of management or directors to their companies or shareholders is also relatively new and is not well developed. Violations of disclosure and reporting requirements or breaches of fiduciary duties to us and our subsidiaries or to our shareholders could materially adversely affect the value of your investment in our ADSs.

While the Joint-Stock Companies Law provides that shareholders owning not less that one percent of our stock may bring an action for damages on behalf of the company, Russian courts to date have very limited experience with respect to such suits. Russian law does not contemplate class action litigation. Accordingly, your practical ability to pursue legal redress against us may be limited, reducing the protections available to you as a holder of ADSs.

Some transactions between us and interested parties require the approval of disinterested directors or shareholders and our failure to obtain approvals could cause our business to suffer.

We are required by Russian law and our Charter and Provisions on the Board of Directors to obtain the approval of disinterested directors or shareholders for certain transactions with “interested parties.”

Under Russian law, the definition of an “interested party” includes members of our Board of Directors, our CEO, members of any management body of a company, and any person that owns, together with that person’s close relatives and affiliates, at least 20% of our voting shares or a person who otherwise has the right to give mandatory instructions to the company if any of the above listed persons, or a close relative or affiliate of such person, is:

Due to the technical requirements of Russian law, entities within our consolidated group and other entities with which we deal on a regular basis may be deemed to be “interested parties” with respect to certain transactions between themselves. The failure to obtain approvals for interested party transactions when required to do so could adversely affect our business.

In addition, the concept of “interested parties” is defined with reference to the concepts of “affiliated persons” and “group of persons” under Russian law. These terms are subject to many different interpretations. Moreover, the provisions of Russian law defining which transactions must be approved as “interested party” transactions are subject to different interpretations. Although we have generally taken a reasonably conservative approach in applying these concepts, we cannot be certain that our application of these concepts will not be subject to challenge. Any such challenge could result in the invalidation of transactions that are important to our business.

Uncoordinated regulation of Russian capital markets could lead to insufficient protection of your rights as an investor in our ADSs.

The Russian securities market is in the early stages of development and is regulated by several different authorities which are often in competition with each other. These include:

The regulations of these various authorities are not always coordinated and may be contradictory. This could reduce the protection available to you as a holder of our ADSs, and reduce the value of your investment in our ADSs.

Russia’s share registration system may provide less protection than registration systems in other countries.

Currently in Russia there is no central registration system for ownership of shares, and the registration of share ownership is performed by commercial registrar companies that are not necessarily subject to effective government supervision. Existing licensing conditions and regulations governing the activities of registrar companies have not been strictly enforced, and registrars generally have relatively low levels of capitalization and inadequate insurance coverage. Consequently, our registrar’s conduct may put our shareholders at risk and our registrar may not have assets sufficient to compensate our shareholders for its errors or mistakes. Although under Russian law we remain liable to our shareholders for any errors or mistakes made by our registrar that affect our shareholders, this safeguard may be inadequate to protect our shareholders from loss.

You may be subject to Russian tax that might be withheld on trades of our Ordinary Shares, reducing their value.

Russian withholding tax on capital gains may arise from the disposition of non-residents of Russian shares and securities, such as Ordinary Shares, by non-resident holders. Russian tax authorities may attempt to apply withholding tax on capital gains derived from trading our shares (but not ADSs which are listed and traded on the exchange outside Russia). However, no procedural mechanism currently exists to collect any tax from capital gains with respect to sale of shares made between non-resident holders.

The Russian tax authorities require Russian residents currently to withhold 20% of the entire disposal proceeds or 24% of disposal proceeds less the original cost and certain expenses (in case of holders that are legal entities) or 30% (in case of holders who are individuals) of the capital gain earned by a non-resident on any shares sold by such non-resident to a Russian resident if more than 50% of the assets in the Russian company whose securities are being sold consist of immovable property and such Russian company’s shares are not listed and sold on exchanges outside Russia. A refund of all or a portion of the tax withheld may be available if an applicable tax treaty provides for an exemption or lower rate of withholding tax. However, obtaining the refund under of any relevant tax treaties can be difficult due to the documentary requirements imposed by the Russian tax authorities. If any such tax is assessed, the value of our shares could be materially adversely affected. See “Item 10—Additional Information—Taxation.”

The Russian market for our securities is substantially smaller and less liquid, and as a result is significantly more volatile, than major equity markets in the United States and elsewhere.

The principal market for our shares is the Russian Trading System (“RTS”), a screen-based over-the-counter trading system, where shares are traded primarily by a network of broker-dealers. Liquidity in most traded instruments fluctuates and bid/ask spreads advertised or offered by dealers can vary substantially. Due to low liquidity and lack of effective regulation of insider trading and market making, the prices of Russian equity securities may be affected by practices that are less prevalent in other markets. Accordingly, there can be no assurance that the price of shares of Russian companies reflects the operation of a fair or efficient market.

The Russian securities market, including the market for Russian equity securities, experienced a significant downturn in 1998. In 1998, the RTS Index, an index of the shares of leading Russian companies (including Tatneft), fell by approximately 85%. This severe decline, resulting from the financial crisis in Russia in 1998, investor concerns with investments in emerging markets in general and in Russia in particular, and concerns about the further devaluation of the ruble, inflation and other factors, adversely affected the ability of Russian companies to raise capital through the sale of equity or debt securities and created renewed concerns about the stability and liquidity of the Russian financial markets. Although the Russian securities market has experienced a significant upward trend since 1998, this trend may not continue.

Restrictive currency regulations may adversely affect our business and financial condition.

We have significant ruble revenues. The ruble is generally not convertible outside of Russia and the conversion of rubles into foreign currency in Russia is subject to Russian currency regulations. Russian currency regulations allow businesses to convert rubles into foreign currency only for certain purposes and require certain regulatory steps to be taken before conversion. Changes to the rules governing the conversion of rubles into foreign currency could make it more difficult for us to effect conversion.

We are currently required to repatriate our proceeds from export sales and convert into rubles 50% of such proceeds. The percentage of proceeds we are required to convert into rubles may be increased or decreased from time to time by the Russian authorities. The restrictions on our ability to convert our ruble revenues into foreign currencies, or to reconvert to foreign currency the rubles we obtain pursuant to the mandatory repatriation and conversion requirements, may adversely affect our ability to pay overhead expenses outside Russia, meet debt obligations and efficiently carry on our business.

Additionally, any delay or other difficulty in converting rubles into a foreign currency to make a payment or any practical difficulty in the transfer of foreign currency could limit our ability to meet our payment and debt obligations, which could result in the acceleration of debt obligations and cross-defaults.

Restrictions on investments outside of Russia or in hard-currency-denominated instruments in Russia expose our cash holdings to devaluation.

Currency regulations established by the Central Bank restrict investments by Russian companies outside of Russia and in most hard-currency-denominated instruments in Russia, and there are only a limited number of available ruble-denominated instruments in which we may invest our excess cash. Any balances maintained in rubles will give rise to losses if the ruble devalues against the U.S. dollar. Moreover, the obligors of our ruble-denominated investments may default, resulting in substantial losses for us.

Relations between Tatarstan and Russia may deteriorate, adversely affecting our business.

After the dissolution of the Soviet Union in 1991, certain politicians in Tatarstan, which has a significant non-Russian ethnic population, which is predominantly Muslim, called for an independent Tatarstan state. In February 1994, Tatarstan and Russia signed a treaty under the terms of which Tatarstan enjoys a high degree of autonomy. Since the treaty was signed, Tatarstan has existed peacefully within the Russian Federation. Russian authorities have repeatedly insisted on the revision of the treaty, claiming that it gives too much power to Tatarstan. No assurance can be given that Tatar nationalism or other political, economic or religious tensions will not cause the relationship between Tatarstan and Russia to deteriorate, which would likely have a negative impact on us. For example, because Tatarstan is entirely surrounded by other regions of Russia and our principal markets are located outside of Tatarstan in Russia and in Europe, we ship substantially all of our crude oil to or through Russia and therefore rely on the cooperation of Russian authorities and the maintenance of good relations between Tatarstan and Russia.

The Tatarstan government may exercise significant influence over our operations.

The Tatarstan government is able to exercise considerable influence over our operations through its ownership interest in Tatneft, its legislative, taxation and regulatory powers, and significant informal pressures. As of May 12, 2003, the Ministry of Land and Property Relations of Tatarstan (“Tatarstan MLPR”) held approximately 30.44% of our capital stock and 32.51% of our Ordinary Shares. As of June 28, 2003, five members of our Board of Directors are members of the Tatarstan Government.

Tatarstan also owns a “Golden Share” – a special governmental right – in Tatneft. The exercise of its powers under the Golden Share would enable the Tatarstan government to appoint one representative to our Board of Directors and Revision Committee and to veto certain major decisions, including those relating, to changes in our share capital, amendments to our Charter, our liquidation or reorganization and “major” and “interested party” transactions as defined under Russian law. See “Item 7—Major Shareholders and Related Party Transactions—Major Shareholders” for a description of the Golden Share rights of the Tatarstan government. Currently, the Tatarstan government is not entitled under Russian law to exercise rights attaching to the Golden Share because it holds more than 25% of our capital stock. However, the Tatarstan government has announced plans to transfer

some or all of our shares that it holds to a newly-formed company, Svyazinvestneftekhim, which will also hold shares of other oil, petrochemicals and telecommunications companies currently owned by the Tartarstan government. In the event of such a transfer, the rights attaching to the Golden Share may become exercisable. The term of the Golden Share is indefinite.

We may face pressures from the Tatarstan government to engage in certain business practices that we may not have independently chosen and that may not maximize shareholder value.

The President of Tatarstan has publicly encouraged us to construct an oil refinery in Tatarstan, and we have made significant investments in new refining facilities in Nizhnekamsk, Tatarstan. The Tatarstan government has also actively encouraged us to create a vertically integrated oil company in Tatarstan. The Tatarstan government also controls a number of our suppliers and contractors, such as the electricity producer Tatenergo and the petrochemicals company Nizhnekamskneftekhim. Consequently, we may be subject to pressures to enter into transactions that we might not otherwise contemplate with such suppliers and contractors. Although we believe that our relations with the Tatarstan government are currently good, the Tatarstan government has in the past and may in the future cause us to take actions that may not maximize shareholder value, such as maintaining employment levels, increasing expenditure on social assets, selling oil to certain customers, transferring exploration or production licenses to small Tatarstan oil companies (including companies not affiliated with Tatneft), acquiring specified companies or taking actions to raise funds for the benefit of Tatarstan.

Tatarstan legislation may be inconsistent with Russian legislation, and resolution of these inconsistencies is uncertain.

During the period from 1991 until February 1994, when the treaty between Russia and Tatarstan was signed, Tatarstan issued privatization and other legislation that was inconsistent with Russian legislation. The treaty gives Tatarstan law precedence over Russian legislation on certain matters. Recently, Tatarstan adopted a number of legislative acts intended to bring Tatarstan law generally into conformity with Russian legislation. However, there is continuing uncertainty about the application of Russian and Tatarstan law in Tatarstan in circumstances where there was in the past or currently remains a conflict between Russian and Tatarstan law. For example, our privatization was conducted primarily in accordance with Tatarstan law, even though there was conflicting Russian legislation under which we conceivably should have been privatized. We are not aware of any challenge to our privatization, but if challenged, our privatization might not be deemed valid under Russian law. Moreover, recently adopted Federal legislation on the Golden Share is in several respects inconsistent with pre-existing Tatarstan legislation. The Tatarstan legislation attaches broader powers to the Golden Share than the Federal legislation. See “Item 7—Major Shareholders and Related Party Transactions—Major Shareholders.” Although under current Federal legislation the Tatarstan government may not exercise its rights the Golden Share while it holds over 25% of our capital stock, it is not clear whether a court would adhere to the Federal or Tatarstan legislation if in the future the Tatarstan government would attempt to exercise the broader powers attaching to the Golden Share pursuant to the Tatarstan legislation. In addition, we cannot be certain that we will not become subject to inconsistent regulatory demands in the future.

We have experienced liquidity problems in the past and could experience them in the future.

As of December 31, 2002, our total indebtedness other than promissory notes, banking deposit certificates and banking customer deposits was RR31,240 million, of which approximately RR14,622 million was long-term indebtedness and RR16,618 million was short-term indebtedness. As of December 31, 2002, RR25,728 million of our indebtedness was denominated in U.S. dollars and was incurred under loan facilities with various foreign banks. Of this amount, approximately 55% was long-term indebtedness and approximately 45% was short-term indebtedness (including current portion of long-term indebtedness). At December 31, 2002, we had outstanding RR4,348 million in promissory notes, RR11,992 million in banking certificates of deposit and RR1,152 million in banking customer deposits. A substantial portion of the revenues from our crude oil sales outside the Commonwealth of Independent States (“CIS”), our primary source of hard currency revenues, is pledged as collateral for our long-term hard currency indebtedness.

In mid-1998, we began to experience liquidity problems which intensified in subsequent months, causing us to suspend certain payments of interest and principal to certain short-term hard currency creditors. This was primarily due to (i) the significant decrease in world crude oil prices which began in 1997 and continued throughout 1998 reducing our cash flow from exports; (ii) the turmoil in the Russian and international financial markets which had a negative impact on the liquidity of our investments in Russian securities; and (iii) lending by us to Tatarstan, further reducing our available cash. Our suspension of payments to certain creditors resulted in export proceeds being temporarily retained by those creditors under security agreements in place, causing further cash flow difficulties.

In October 2000, we restructured RR13,635 million (US$354 million) of our hard currency indebtedness, including the principal and capitalized deferred interest. All remaining amounts due under the restructuring agreement were repaid in the first quarter of 2002.

In 2001 and 2002, we entered into secured loans with Commerzbank, BNP Paribas and Credit Suisse First Boston for an aggregate amount of US$725 million. These loans are currently collateralized by aggregate oil exports of 450,000 tons per month (subject to increases depending on crude oil prices). We have also entered into a number of short-term loans collateralized by crude oil export contracts.

Although we believe that the loan agreements were executed on terms beneficial to us, our level of hard currency indebtedness, combined with the uncertainty of world oil prices and instability in the Russian and international financial markets, could have material adverse consequences for us, including:

The terms of the loan agreements also impose certain financial ratios and constrain our ability to pledge our crude oil sales, which may limit our access to additional financing.

We sell a significant portion of our crude oil and refined products in the Russian market, where prices have historically been lower than in the international markets. These sales may adversely affect our revenues.

In 2002, we sold approximately 26.6% of our crude oil volumes (including purchased crude oil) and 58.6% of our refined products volumes (including purchased refined products) within Russia. Russian crude oil prices remain below international spot market price levels primarily due to large regional surpluses in Russia and increasing domestic supplies. Domestic Russian prices for refined products also remain below international spot market prices for refined products.

We are dependent on Transneft, a state-owned company that controls the monopoly pipeline system, for the transport of nearly all of our crude oil, and our ability to export crude oil is limited by the system for allocating access to Transneft’s pipelines.

Over 90% of the crude oil produced in Russia, and substantially all of our crude oil, is transported through the Transneft system of trunk pipelines. Transneft is a state-owned oil pipeline monopoly. The Transneft pipeline system is subject to breakdowns and leakage. By using multiple pipelines, however, Transneft has generally avoided serious disruptions in the transport of crude oil, and to date, we have not suffered significant losses arising from the failure of the pipeline system. A significant disruption in the pipeline system would, however, have a material adverse effect on our results of operations and financial condition.

Russian government authorities regulate access to Transneft’s pipeline network. Pipeline capacity, including export pipeline capacity, is allocated quarterly to oil producers, generally in proportion to the amount of oil produced and delivered to Transneft’s pipeline network in the prior quarter. Generally, a Russian oil company is given an allocation for export to non–CIS countries equal to approximately one-third of its total crude oil so produced and delivered to Transneft. Limitations on access to the export pipelines constrain the ability of producers to export crude oil, and limited port, shipping and railway facilities represent further constraints on the export of crude oil. These constraints have had, and may continue to have, a significant impact on our cash flows and results of operations, since export prices are generally higher than domestic prices. Furthermore, we must pay taxes to the Russian government in order to maintain our access to export pipelines and seaports and pay transportation expenses to Transneft for crude oil exports. Our failure to pay such taxes and expenses could result in the termination or temporary suspension of our access to the export pipelines, which would materially adversely affect our results of operations and financial condition.

In 2001, a Russian court ruled that Transneft stop accepting shipments of crude oil by one of our competitors in response to a lawsuit filed by one of that oil company’s shareholders. In 2002, Russian courts on several occasions granted similar requests in lawsuits against other Russian companies. Such rulings were overturned quickly. However, we cannot be certain that similar lawsuits will not be filed against us in the future or that any such lawsuits will be resolved in our favor. Any interruption in access to Transneft’s pipeline network resulting from any such lawsuits could have a material adverse effect on our results of operations and financial condition.

A significant proportion of our crude oil production and reserves consists of high sulfur content oil, for which we receive a lower price and which has lower marketability than lower-sulfur content crude oil.

As of January 1, 2003, most of our proved oil reserves had a high sulfur content, defined as greater than 1.8% sulfur content by mass.

A significant proportion of our crude oil production (approximately 41.1% in 2002, 40.9% in 2001 and 40.6% in 2000) consists of this high sulfur content oil, and we expect this proportion to continue to increase in the future. Our high sulfur content

crude oil, which has an average sulfur content of approximately 3.5% by mass, typically commands a lower price than low sulfur content crude oil. Currently, however, approximately 60% of our high sulfur content crude oil is blended with low sulfur content crude oil produced by us and by other companies when it is transported through the Transneft pipeline system. The blended crude oil sells for a single uniform price. Although we pay Transneft a premium of US$3.00 per ton of such blended and transported crude oil, we currently benefit overall from Transneft’s practice of blending deliveries, as we generally receive a higher price for our blended crude oil than we would if either (i) the higher sulfur content crude oil were transported and sold separately or (ii) Transneft charged a premium for transporting high sulfur content crude that more closely matched the differential in world market price between high sulfur content crude oil and the blended crude oil that Transneft currently carries. In the past, Transneft and members of the Russian government have raised the possibility that the oil companies whose high sulfur content oil is blended with lower sulfur content oil in the pipelines should pay compensation to owners of the lower sulfur content oil for the difference in price between crude oils of different qualities. If these proposals are adopted, the current system will be changed to our significant detriment and our business and results of operations would be adversely affected.

Our arrangements for deliveries of high sulfur content crude oil have historically been subject to payment delays, and we do not have long-term contracts for such deliveries.

We deliver a significant portion of the approximately 40% of our high sulfur content crude oil that is not blended in the Transneft system via dedicated pipelines owned by Transneft to the Nizhnekamsk oil refinery, the Ufa refinery in Bashkortostan and other refineries capable of refining such oil.

We do not have long-term arrangements with any refineries with respect to our shipments of high sulfur content crude oil, and the refineries could cease accepting such crude oil from us at any time. We have taken steps to diversify our outlets for high sulfur content crude oil, including by developing our relationships with refineries in Nizhnekamsk and Bashkortostan, and believe that sufficient refining facilities for this oil will be available to us on acceptable terms in the future. We have made a significant investment in construction of the Nizhnekamsk refinery partly in order to ensure our continued access to facilities for refining high sulfur crude oil. No assurance can be given, however, that we will succeed in following this strategy or that adequate refining facilities will continue to be available to us.

We face inflation risks that could adversely affect our results of operations.

The Russian economy has been characterized by high rates of inflation, including a rate of 84.4% in 1998, which had subsided to 15.1% in 2002. Certain of our costs, such as salaries, are sensitive to increases in the general price level in Russia. A significant portion of our revenues is either denominated in U.S. dollars or tightly linked to the U.S. dollar, and is affected primarily by the international oil prices. Accordingly, our operating margins could be adversely affected if the inflation of our ruble costs in Russia is not balanced by a corresponding devaluation of the ruble against the U.S. dollar or an increase in oil prices.

The Russian and Tatarstan governments can mandate deliveries of crude oil and refined products at less than market prices, adversely affecting our revenue and relationships with other customers.

The Russian and Tatarstan governments have the authority to direct us to deliver crude oil or refined products to certain government-designated customers, which generally take precedence over market sales. Government-directed deliveries may take several forms. We may be directed to make export sales for the purpose of obtaining foreign currency for government use, or to make deliveries to government agencies, the military, agricultural producers or remote regions, or to specific consumers or refineries, such as Nizhnekamskneftekhim, or to domestic refineries in general. For example, in November 1998 the Russian government threatened to revoke the export rights of four Russian oil companies, including Tatneft, for failing to provide domestic refineries with steady supplies of oil. After receiving confirmation from us that we had been providing more than 50% of our crude oil to refineries located in the Russian Federation, the Russian government elected not to interrupt our exports. Government-directed deliveries may disrupt our relations with our customers, lead to delays in payments for crude oil and refined products or result in sales at below market prices. See “Item 4—Information on the Company—Refining and Marketing—Crude Oil—Government-Directed Deliveries.”

Any failure to make government-directed deliveries may affect our ability to export our crude oil. Any limitation of export rights could materially adversely affect our results of operations and financial condition.

The Russian tax system imposes substantial burdens on us and is subject to frequent change and significant uncertainty.

We are subject to a broad range of taxes imposed at the federal, regional and local levels, including but not limited to excise and export tariffs, income tax, unified natural resources production tax, regional sales tax (to be abolished from January 1, 2004), property tax, social tax and pension contributions, among others. We were subject to an effective income tax rate (current and deferred income tax expense/benefit as a percentage of income before income taxes and minority interest) of 16.7% in 2002 and a total tax burden of 24% (income taxes and taxes other than income taxes as a percentage of sales and other operating revenue).

Laws related to these taxes, such as the Tax Code, have been in force for a short period relative to tax laws in more developed market economies, and the government’s implementation of these tax laws is often unclear or inconsistent. Accordingly, few precedents with regard to the interpretation of these laws have been established. Often, differing opinions regarding legal interpretation exist both between companies subject to such taxes and the government and within government ministries and organizations, such as the Ministry of Taxes and Duties and its various inspectorates, creating uncertainties and areas of conflict. Generally, tax declarations remain open and subject to inspection by tax and/or customs authorities for a period of three years following the tax year. The fact that a year has been reviewed by tax authorities does not close that year, or any tax declaration applicable to that year, from further review by an upper level of the tax authorities during the three-year period. These facts create tax risks in Russia substantially more significant than typically found in countries with more developed tax systems.

The taxation system in Russia is subject to inconsistent enforcement at the federal, regional and local levels, which complicates our tax planning and related business decisions. For example, tax laws are unclear with respect to the deductibility of certain expenses. This uncertainty exposes us to significant fines and penalties and to enforcement measures despite our efforts at compliance, and could result in a greater than expected tax burden.

Financial statements of Russian companies are not consolidated for tax purposes. Therefore, each of our Russian entities pays its own Russian taxes and may not offset its profit or loss against the loss or profit, respectively, of another of our entities. Because Russian legislation contains no consolidation provisions, dividends within the entities comprising our group are subject to Russian taxes at each level. Currently, dividends payable to a Russian entity are taxed at 6%, and the payer is required to withhold the tax when paying the dividend.

Until the adoption of the new Tax Code, the system of tax collection was relatively ineffective, resulting in the continual imposition of new taxes in an attempt to raise government revenues. There can be no guarantee that the Tax Code will not be changed in the future in a way that reverses recent positive changes. These factors, together with the possibility of government deficits, raise the risk of a sudden imposition of additional taxes on us. This could adversely affect us.

The Russian government has recently revised the Russian tax system. The new tax system is intended to reduce the number of taxes and the overall tax burden on businesses and to simplify the tax laws. However, the revised tax system relies heavily on the judgments of local tax officials and fails to address many of the existing problems. Even in the event of further reforms to tax legislation, they may not result in a reduction of the tax burden on Russian companies and the establishment of a more efficient tax system. Conversely, they may introduce additional tax collection measures. Accordingly, we may have to pay significantly higher taxes, which could have a material adverse effect on our business.

We must pay transportation expenses and tariffs to Transneft in order to maintain pipeline access, and these expenses and tariffs may be raised in the future, which could increase our costs.

We must pay transportation expenses to Transneft in order to maintain our access to export pipelines and seaports. The loss of such access would adversely affect our results of operations and financial condition. For example, in October 1998, as a result of our significant liquidity problems, we interrupted payments of transportation expenses to Transneft. Consequently, our export capacity was suspended until we resumed such payments. Further, if the tariffs that we pay for the transportation by pipeline of our crude oil were raised, our costs would increase, which could adversely affect our revenues, cash flows and results of operations.

As is common with many Russian enterprises, from time to time we experience difficulties in receiving payment for services and goods that we supply domestically. As a result, in such circumstances we may depend on various forms of non-cash settlement, including barter and promissory notes. Even though the level of cash settlements in the Russian economy has increased in the last three years, we continue to engage in barter transactions. In the year ended December 31, 2002, barter transactions represented approximately 4% of our total sales and other operating revenues (6% in 2001 and 11% in 2000). Such transactions are inherently less efficient than cash transactions, as the proceeds cannot be used to fund operational or capital expenditures that are required to be made in cash. There can be no assurance that the use of barter arrangements will not increase in the future.

We maintain insurance against some, but not all, potential risks and losses affecting our operations. We cannot assure you that our insurance will be adequate to cover all of our losses or liabilities. Also, we cannot predict the continued availability of insurance at an acceptable cost.

Oil drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil reserves will be found. The cost of drilling and completing wells is often uncertain. Oil drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

We only have a certain and perhaps insufficient level of insurance coverage for expenses and losses that may arise in connection with property damage, work-related accidents and occupational disease, natural disasters and environmental contamination. We have no insurance coverage for loss of profits or other losses caused by death or incapacitation of our senior managers. Accordingly, losses or liabilities arising from such events could increase our costs and have a adverse effect on our operations and financial condition.

Our main oil fields are considered “mature” and require increased capital expenditures to maintain production levels. Inability to finance these and other expenditures could have a material adverse effect on our financial condition and the results of our operations.

One of our key strategies has been to focus on rehabilitating existing wells to stabilize and optimize production. We anticipate that substantial expenditures will be required to maintain reservoir pressure in our key fields and otherwise to optimize production. Our business also requires other significant capital expenditures, including in exploration and development, production, transport, refining, and to meet our obligations under environmental laws and regulations. We expect to finance a substantial part of these capital expenditures out of cash flows from our operating activities. If international oil prices fall, however, we will have to finance our planned capital expenditures increasingly through bank borrowings and offerings of debt or equity securities in the international capital markets. If necessary, these financings may be secured by our exports of crude oil. Currently, approximately 50% of our approximately 905,000 tons per month of non-CIS crude oil exports has been pledged as security for existing borrowings. No assurance can be given that we will be able to raise the financings required for our planned capital expenditures, on a secured basis or otherwise, on acceptable terms or at all. If we are unable to raise the necessary financing, we will have to reduce our planned capital expenditures. Any such reduction could adversely affect our ability to expand our business, and if the reductions are severe enough, could adversely affect our ability to maintain our operations at current levels.

Our exploration, development and production licenses may be suspended, amended or revoked prior to their expiration, and we may not be able to extend our licenses at their scheduled expiration although we currently expect to do so.

The licensing regime in Russia for the exploration, development and production of oil and gas is governed primarily by the Federal Law on Use of Subsoil of February 21, 1992 and March 3, 1995, as amended (the “Subsoil Law”) and regulations issued thereunder. Most of our licenses provide that they may be terminated if we fail to comply with license requirements, including the conditions that we make timely payments of levies and taxes for the use of the subsoil, if we systematically fail to provide information, if we go bankrupt or if we fail to fulfill any capital expenditure and/or production obligations or to meet certain environmental requirements. Article 10 of the Subsoil Law also provides that a license to use a field may be extended at the initiative of the license holder where the license holder complies with the terms of the license and where the development of the field requires completion or liquidation operations. We believe that we will be able to extend our licenses on commercially reasonable terms at their scheduled expiration, and plan to do so.

We may not be able to, or may voluntarily decide not to, comply with the license conditions for some or all of our license areas, and we may not be able to renew our licenses at their scheduled expiration. If we fail to fulfill the specific terms of any of our licenses or if we operate in the license areas in a manner that violates Russian or local law, government regulators may impose fines on us or suspend or terminate our licenses, or we may not be able to extend our licenses. Any of these events could have a material adverse effect on our operations and the value of our assets, or cause the price of our ADSs to decline.

Our inability to replace current production with new reserves will result in reduced production and will have a material adverse impact on our financial condition and results of our operations.

Since 1996, our oil production has generally remained stable. Increasing our crude oil production by developing our non-producing and undeveloped reserves will require significant capital expenditure. Though we believe that our current production levels are stable and sustainable as a result of our current development program, our exploration and production programs may not result in the replacement of current production with new reserves, such programs may not result in new, commercially viable operations and we may not be able to extend the life of our existing reserves.

We depend on our senior managers and other key personnel, the loss of any of whom could have an adverse impact on our business.

We depend on the continued services and performance of our senior management and other key personnel. If we lose the services of our senior managers or if any of our other executive officers or key employees should cease to take an active role in

managing our affairs, we may not be able to operate our business as effectively as we anticipate and our operating results may suffer. In particular, we are heavily dependent upon our General Director, Shafagat F. Takhautdinov, and certain other key managers. We cannot assure you that their services, or those of other key managers, will continue to be available to us, and the loss of any one of these could have a material adverse on our business.

Failure to carry out our corporate reorganization program in its entirety or for it to have the desired effects may adversely affect our expected financial and operational results.

We have adopted a corporate reorganization program as part of our strategy for reducing costs and improving production efficiency. This program faces numerous difficulties, including local opposition to the transfer of social assets, such as schools and medical facilities, from our ownership or management to local jurisdictions. These have prevented or delayed and may well continue to prevent or delay the implementation of certain aspects of the corporate reorganization program. Moreover, it is not anticipated that the corporate reorganization program will result in a significant reduction in the aggregate number of our and our subsidiaries’ employees.

Significant expenditures and senior management time may be required with respect to our internal controls to ensure that we will be in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 when the SEC’s regulations thereunder come fully into effect.

Section 404 of the Sarbanes-Oxley Act and the SEC’s regulations thereunder, upon becoming effective, will require our senior executive and senior financial officers to assess on a regular basis our internal controls for financial reporting, evaluate the effectivness of such internal controls and disclose any material weaknesses in such internal controls. Our external auditors will also be required to provide an attestation of management’s evaluation. The rules regarding our management’s report on internal controls and attestation will apply to us from the fiscal year ending December 31, 2005. Material weaknesses in the design and operation of our internal controls were identified with respect to prior years and we believe that significant expenditures, as well as the time of senior management, may well be required to ensure that management’s report and the attestation can be provided when required.

We expect the oil industry in Russia and Tatarstan to become increasingly competitive.

We expect that the ongoing liberalization of the oil and gas industry in Russia will lead to increased competition for new exploration and production licenses, access to capital resources, transportation infrastructure, sales and other aspects of the production and transportation process. Recently, the Russian oil industry has experienced significant consolidation, including the privatization sale of Slavneft, a large Russian oil company, to a consortium of shareholders who also control Tyumen Oil Company (TNK) and Sibneft, Russia’s third and fifth largest oil companies, respectively; establishment of a strategic joint venture between BP and TNK on the basis of their respective Russian assets; and the announcement of a merger of YUKOS and Sibneft to create the largest Russian and one of the largest international oil companies by annual production. These and other companies may have better access to financial and other resources than we do, and this may give them a competitive advantage. In addition, our domestic competitors may be strengthened through strategic acquisitions of additional assets and, in Tatarstan, through the establishment of new oil companies that could increase the level of competition in Tatarstan. See “Item 4—Information on the Company—Competition.”

A substantial or extended decline in prices for crude oil and petroleum products could adversely affect our business, results of operations, financial condition, liquidity and our ability to finance planned capital expenditures.

Our revenues, profitability and future rate of growth depend substantially upon prevailing prices of crude oil and petroleum products. Historically, prices for oil have fluctuated widely in respect to changes in many factors. Factors that can cause this fluctuation include:

The decline in world oil prices from October 1997 to December 1998 by more than 54% to less than US$10 per barrel was one of the primary reasons for our significant liquidity problems in the second half of 1998. See “—Risks Relating to the Company” under this Item. While oil prices remain volatile, average price levels since 1998 have been consistently above the low levels reached in 1998. The average prices of Brent crude, an international benchmark oil price, for the three years ended December 31, 2002, 2001 and 2000, were approximately US$24.98, US$24.46 and US$28.50 per barrel, respectively. Crude oil prices increased slightly in 2002 after declining significantly in 2001 as a result of export restrictions imposed by OPEC and certain other crude oil producing nations, including Russia, in the first half of 2002, improving global economic conditions and heightened tensions in the Middle East, particularly around Iraq, and domestic unrest in Venezuela that temporarily restricted production. However, there can be no assurance that oil prices will not decline again. Because our crude oil export sales are the primary source of our hard currency revenues, including revenues needed to repay lines of credit from foreign lenders, and an important source of our earnings and cash flows, any decline in international crude oil or refined product prices is likely to have a material adverse effect on our financial position and results of operations.

Lower prices may also reduce the amount of oil that we can produce economically or reduce the economic viability of projects planned or in development. We may reduce our planned capital expenditures if international crude oil or petroleum product prices fall below the price assumptions used in our internal estimates.

We do not currently engage in any hedging transactions or other derivatives trading to reduce the impact of fluctuations of crude oil prices on our company.

The crude oil and natural gas reserves data in the Reserves Report are only estimates and are inherently uncertain, and our actual production, revenues and expenditures with respect to our reserves may differ materially from these estimates.

The crude oil and natural gas reserves data set forth in the Reserves Report included as Annex A to this annual report are estimates based primarily on internal engineering analyses that were audited by Miller and Lents, Ltd., independent petroleum engineering consultants. The most recent reserves estimates were calculated using oil and gas prices in effect on December 31, 2002. Any significant price changes could have a material effect on the quantity and present values of our proved reserves.

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of the value and quantity of economically recoverable oil and gas reserves, rates of production, future net revenues and cash flows and the timing of development expenditures necessarily depend upon a number of variable factors and assumptions, including the following:

Because all reserves estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves as set forth in the Reserves Report:

Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time. This is especially true in Russia, where there has been political and economic uncertainty in the recent past. Results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserves data. Furthermore, different reservoir engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material. Any downward adjustment could lead to lower future production and thus adversely affect our financial condition, future prospects and market value.

We may incur material costs to comply with, or as a result of, health, safety and environmental laws and regulations.

We incur, and expect to continue to incur, substantial capital and operating costs in order to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety.

The level of pollution and potential clean up is impossible to assess without an environmental audit (which we have not undertaken) and consistent interpretation and enforcement of environmental laws by the federal, regional and local authorities (which has not occurred). In connection with our application for licenses to explore and develop oil resources, we are generally required to make significant commitments concerning levels of pollutants that we release and remediation in the event of environmental contamination.

New laws and regulations, the imposition of tougher requirements in licences, increasingly strict enforcement of, or new interpretations of, existing laws, regulations and licences, or the discovery of previously unknown contamination may require further expenditures to:

Under existing legislation, we believe that there are no significant environmental liabilities, beyond the amounts accrued in the financial statements, that will have a material adverse effect on our operating results or our financial position.

Although the costs of the measures taken in relation to environmental regulations have not had a material adverse effect on our financial condition or results of operations to date, in the future the costs of such measures and liabilities due to environmental damage caused by us may be material. Furthermore, we do not have any insurance for environmental damage caused by our activities.

It may be difficult for the depositary to convert any dividends paid by us into U.S. dollars.

Russian currency control legislation pertaining to payment of dividends currently provides that ruble dividends on ordinary shares may be paid to the depositary or its nominee and converted into U.S. dollars by the depositary for distribution to owners of ADSs without restriction.

The ability of the depositary and other persons to convert rubles into U.S. dollars (or another hard currency) is also subject, however, to the availability of U.S. dollars (or such other hard currency) in Russia’s currency markets. Although there is an existing market within Russia for the conversion of rubles into U.S. dollars, including the interbank currency exchange and over-the-counter currency futures markets, the further development of the market is uncertain. At present, there is no market for the conversion of rubles into foreign currencies outside of the CIS and no viable market in which to hedge ruble and ruble-denominated investments. See “Item 10—Additional Information—Exchange Controls.”

Our ability to pay dividends is constrained by Russian accounting practices and our loan agreements with creditors.

We are permitted to pay dividends on our Ordinary Shares out of net profits, and dividends on Preferred Shares out of net profits and special funds designated for such purposes, in each case calculated in accordance with RAR, which differ in significant respects from U.S. GAAP. Any amounts available for distribution as dividends on our shares as determined under RAR may be significantly lower than the amounts that would have been determined under U.S. GAAP. Our loan agreements with some of our hard currency lenders contain similar restrictions on the payment of dividends. See “Item 8—Financial Information—Dividends and Dividend Policy.”

We have historically had commercial relations with certain countries, including Iran, Iraq, Libya and Sudan, that are currently or have been until recently the subject of economic sanctions imposed by the United States and international organizations. Violations of existing international or U.S. sanctions could subject us to penalties that would have a material adverse affect on our results of operations.

International and U.S. sanctions have been imposed on companies engaging in certain types of transactions with specified countries or companies in those countries. The Tatarstan government and we have held discussions regarding possible transactions involving such countries, including Iran, Libya and Sudan. We have opened a representative office in Iran. In 2002, we continued work under a contract for demercaptanization (a process in which mercaptans—sulfur compounds—are removed from hydrocarbons) of refined products and oxidized gas in Iran and are currently performing contracts for testing microbiological bed stimulation technology in Iran. In addition, we have recently signed a contract to implement well casing technology in Iran and submitted proposals to participate in tenders to provide engineering services and to obtain production licenses for a group of Iranian oil fields. We and/or our affiliates have also discussed proposals for business projects with parties in Libya and Sudan.

Although most of the U.N. and U.S. sanctions against Iraq have been lifted subsequent to the military action in Iraq in 2003, prior to lifting of the sanctions we exported Iraqi oil under the U.N. oil-for-food program, participated in a consortium that includes Rosneft, a major state-owned Russian oil company, to develop Iraqi oil fields, drilled a number of oil wells in Iraq under U.N.-approved contracts and opened a representative office in Iraq. We also entered into certain other transactions with the Iraqi government and its agencies or instrumentalities. We believe that none of our activities in Iraq was prohibited by U.S. or international sanctions.

In the future, we may enter into permitted transactions with other countries against which sanctions have been applied. If we violate existing international or U.S. sanctions, penalties could include a prohibition or limitation on our ability to obtain goods and services on the international market or to access the U.S. or international capital markets. However, we believe that we are not currently, nor have we in the past been, involved in any transactions with Iraq, Iran, Libya or Sudan that could result in sanctions against us, and we intend to comply with international sanctions law in the future.

The market price of our shares and ADSs could be adversely affected by potential future sales.

The trading price of our shares and ADSs could be adversely affected as a result of sales of substantial numbers of our shares in the public market, or by the perception that this could occur. These factors could also make it more difficult to raise capital through equity or equity-linked offerings.

As of May 12, 2003, Tatarstan, through the Tatarstan MLPR, held approximately 30.44% of our capital stock and 32.51% of our Ordinary Shares. An additional 5.32% of our capital stock was held by OAO Tataro-American Investments and Finance (“TAIF”). Both the Tatarstan MLPR and TAIF are free to dispose of the Ordinary Shares they hold at any time. Significant dispositions of these shares could adversely affect the price of our ADSs.

The rights of non-Russian residents to own or vote our shares or ADSs may be subject to restrictions.

Although there are currently no restrictions under our Charter or under Russian or Tatarstan law that limit the right of non-Russian residents or persons to own or vote our shares either directly or through an ADR program, the Tatarstan government issued a decree in December 1997 directing its representatives on our board of directors and several other enterprises of “strategic importance” to Tatarstan to amend their respective charters and to incorporate restrictions on ownership of shares in those enterprises by non-Tatarstan enterprises. As of June 27, 2003, the Tatarstan government had not issued any more specific guidance, either to Tatneft or to other enterprises affected by the decree, and we are uncertain as to whether or when such restrictions will be imposed. Imposition of such restrictions on the ownership of Ordinary Shares or ADSs may have a material adverse effect on the market for the Ordinary Shares or ADSs.

According to the regulations of the Russian Federal Commission on the Securities Market (the “FCSM”), the deposit of shares of a Russian company into an ADR program requires the permission of the FCSM. Such permission may be denied if more than 40% of the class of shares eligible for deposit into the ADR program will circulate outside Russia or if the ADR program contemplates the voting of the shares underlying the ADSs other than in accordance with the instructions of the ADS holders. Our ADR program has no express limitations on the deposit of our Ordinary Shares into the program, and it contemplates that, in the absence of instructions from ADS holders, the depositary will give a proxy to vote the shares underlying such ADRs to our representative. There is uncertainty as to whether the FCSM regulation applies to ADR programs into which additional shares have been deposited exceeding the aggregate number of shares in the ADR program at the time of enactment of the regulation, or only to ADR programs established after the time of its enactment. Furthermore, the FCSM regulation does not specify the consequences of a violation of the regulation. We have not obtained FCSM permission for our ADR program. An assertion that

the FCSM regulation applies to our ADR program could have a material adverse effect on the market price of our Ordinary Shares or ADSs.

Voting rights with respect to ADSs are further limited by the terms of the relevant deposit agreement, which may prevent or delay the ability of ADS holders to exercise their rights.

ADS holders may exercise voting rights with respect to the Ordinary Shares represented by ADSs only in accordance with the provisions of the relevant depositary agreement. However, there are practical limitations with respect to their ability to exercise their voting rights due to the additional procedural steps involved in communicating with them. For example, our charter requires us to notify shareholders at least 20 days in advance of any general meeting. Holders of our ordinary shares receive notice directly from us and are able to exercise their voting rights either by attending the meeting in person or voting by proxy.

By comparison, an ADS holder will not receive notice directly from us. Rather, in accordance with the deposit agreement, we will provide the notice to the depositary. The depositary has undertaken in turn, as soon as practicable thereafter, to mail to ADS holders the notice of such meeting, voting instruction forms and a statement as to the manner in which instructions may be given by holders. To exercise his or her voting right, the ADS holder must then instruct the depositary how to vote its shares. Because of this extra procedural step involving the depositary, the process for exercising voting rights may take longer for the ADS holder than for holders of Ordinary Shares. If this occurs, ADS holders may not be able to exercise voting rights attaching to the ADSs with respect to the Ordinary Shares that underlie them.

Russian legislation regarding nominee holders and depositaries and the concepts of legal and beneficial ownership are underdeveloped, which could adversely affect the holders of our ADSs.

Regulations governing nominee holders, including global custodians and ADS depositaries in their custodial capacity, are underdeveloped and subject to varying interpretations. For example, it is unclear whether global custodians and ADS depositaries that are acting outside of Russia for non-Russian clients and investors but who are holding in Russia through a Russian licensed custodian, on behalf of their clients and investors, securities issued by Russian companies, including our ordinary shares underlying our ADSs, are required to obtain a license from the Russian Federal Commission on the Securities Market to hold Russian securities on behalf of these clients and investors. If they do not obtain this license, their “nominee holder” status in Russia might not be recognized and therefore they may be viewed under Russian law as the beneficial owner.

This is different from the way some other jurisdictions, such as most U.S. states, treat nominee and custodial relationships, including ADSs. In those jurisdictions, although shares may be held in the nominee holder’s name or to its order and it is therefore a “legal” owner of the shares, the depositor, such as an ADS holder, would be considered the “beneficial” or real owner. In those jurisdictions, actions against the nominee holder or the legal owner should not result in the beneficial owners losing their shares. Because Russian law may not make the same distinction between legal and beneficial ownership, a Russian court might find that the ADS depositary in whose name the ordinary shares are held, and not the ADS holder, is the owner of the underlying shares for purposes of Russian law. Thus, in proceedings brought against a depositary, whether or not related to shares underlying ADSs, Russian courts may treat those underlying shares as the assets of the depositary, open to seizure and arrest. If the ordinary shares are seized or arrested, the holders involved would lose their rights to the underlying shares.

In addition, the State Duma, Russia’s lower house of parliament, and the Russian Federal Commission on the Securities Market have been reviewing the activities of ADS depositaries in Russia. Additional regulation of ADR programs and uncertainty among investors relating to nominees or depositaries could discourage foreign investors from investing in our securities.

Given that under Russian law the depositary may also be viewed as the owner of the shares underlying the ADSs, the depositary may need to comply with various Russian legal requirements regarding aggregate share ownership in a Russian company. For example, under Russian law, a person must receive the prior approval of the Russian Ministry for Antimonopoly Policy and Support of Entrepreneurship before holding more than 20% of a company the size of Tatneft. As of May 12, 2003, the depositary for our ADR program held approximately 18.25% of our Ordinary Shares.

You may have limited recourse against us and our officers and directors because we conduct our operations outside the United States and all of our officers and directors reside outside the United States.

Our presence outside the United States may limit the legal recourse against us by you. We do not have any presence in the United States and are incorporated under the laws of the Russian Federation. All of our directors and executive officers reside outside the United States, in Russia. All or a substantial portion of our assets and the assets of our officers and directors are located outside the United States.

As a result, you may not be able to effect service of process within the United States on us or on our officers and directors. Similarly, you may not be able to obtain or enforce U.S. court judgments against us, our officers or directors, including actions based on the civil liability provisions of the federal securities laws of the United States. There is no treaty between the United States and Russia providing for reciprocal recognition and enforcement of foreign court judgments in civil and commercial

matters. Similarly, you may not be able to obtain or enforce foreign judgments against us on the same basis. These limitations may deprive you of effective legal recourse for claims related to your investment in our ADSs.

The deposit agreement provides for controversies, claims and causes of action brought thereunder by any party thereto against us to be settled by arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association; provided that any controversy, claim or cause of action relating to or based upon the provisions of the federal securities laws of the United States or the rules or regulations promulgated thereunder may, but need not, be submitted to arbitration. The Russian Federation is a party to the United Nations (New York) Convention on the Recognition and Enforcement of Foreign Arbitral Awards. However, it may be difficult to enforce arbitral awards in the Russian Federation due to a number of factors, including the inexperience of Russian courts in international commercial transactions, official and unofficial political resistance to enforcement of awards against Russian companies in favor of foreign investors, Russian courts’ inability to enforce such orders, and corruption.

You may not be able to benefit from the United States-Russia double tax treaty.

The Russian tax rules applicable to U.S. holders of our ADSs are characterized by significant uncertainties and by an absence of interpretive guidance. Russian tax authorities have not provided any guidance regarding the treatment of ADS arrangements, and there can be no certainty as to how the Russian tax authorities will ultimately treat those arrangements. In particular, it is unclear whether Russian tax authorities will treat U.S. holders as the beneficial owners of the underlying shares and dividends and other proceeds relating to the underlying shares and, therefore, persons entitled to the underlying shares, for the purposes of the United States-Russia double tax treaty. If the Russian tax authorities do not treat U.S. holders as the beneficial owners of such dividends and proceeds, then the U.S. holders would not be able to benefit from the provisions of the United States-Russia double tax treaty. In this event, dividends paid to U.S. holders generally will be subject to Russian withholding tax at a rate of 15% for holders that are legal entities and 30% for individual holders rather than the reduced rate of 5% for corporate legal entities owning at least 10% or more of our outstanding voting shares and the rate of 10% for all other entities and individual holders under the United States-Russia double tax treaty. See “Item 10—Additional Information—Taxation.”

Investors in emerging markets, such as the Russian Federation, are subject to greater risks than investors in more developed markets, including significant legal, economic and political risks.

Investors in emerging markets, such as the Russian Federation, should be aware that these markets are subject to greater risk than more developed markets, including in some cases significant legal, economic and political risks. Investors should also note that emerging economies, such as the Russian Federation’s, are subject to rapid change and that the information set out herein may become outdated relatively quickly. Accordingly, investors should exercise particular care in evaluating the risks involved and must decide for themselves whether, in light of those risks, their investment is appropriate. Generally, investment in emerging markets is only suitable for sophisticated investors who fully appreciate the significance of the risks involved and investors are urged to consult with their own legal, financial and tax advisors before making an investment in our ADSs.

Terrorist activity and global instability could have an adverse effect on our business and share price.

On September 11, 2001, terrorist attacks were carried out against multiple targets in the United States causing the loss of many lives and extensive property damage. These events and their aftermath have had a significant effect on international financial and commodities markets. Any future acts of terrorism of such magnitude could have an adverse effect on the international financial and commodities markets and the global economy.

Tatneft is one of the largest producers of crude oil in Russia. Substantially all of our production and other operations are located in Tatarstan, a republic of Russia situated between the Volga River and the Ural Mountains and located approximately 750 kilometers southeast of Moscow. We currently hold most of the exploration and production licenses and produce substantially all the crude oil in Tatarstan. As of January 1, 2003, our total Proved Reserves of crude oil were approximately 838.4 million tons (5,972.0 million barrels (“mmbbl”)). In addition to crude oil production, in recent years we have diversified our operations by building up our refining capabilities, developing a network of retail service stations, creating a petrochemicals holding division centered around Russia’s largest tire producer OAO Nizhnekamskshina (“Nizhnekamskshina”) and providing banking services through our subsidiaries OAO Bank Zenit (“Bank Zenit”) and Commercial Bank Devon-Credit (“Bank Devon-Credit”). Our sales and other operating revenues were RR145,483 million, RR155,511 million and RR199,503 million for the years ended December 31, 2002, 2001 and 2000, respectively. Together with our principal subsidiaries (other than agricultural subsidiaries), we employed approximately 95,000 persons as of December 31, 2002.

OAO Tatneft is an open joint-stock company organized under the laws of Russia and Tatarstan. Our principal business is to explore for, develop, produce and market crude oil. Our registered office is located at 75 Lenin Street, Almetyevsk, Tatarstan 423450, Russian Federation (telephone: 7-8553-250-700). Our main offices and virtually all of our administrative staff are located in Almetyevsk, a city located approximately 950 kilometers southeast of Moscow and 250 kilometers southeast of Kazan, the capital of Tatarstan. Our agent for service of process in the United States is CT Corporation System, located at 850 Library Avenue, Suite 204, P.O. Box 885, Newark, Delaware 19715, United States of America.

Tatneft is the legal successor to the Soviet-era production association “PA Tatneft,” which was formed in 1950, along with several other oil production-related state enterprises. As part of the process of privatization of state-owned enterprises following the dissolution of the Soviet Union, substantially all of the assets of these enterprises were transferred to us, and we became an open join-stock company in January 1994. For the history of our privatization, see “Item 7-Major Shareholders and Related Party Transactions—Major Shareholders—Shareholding Structure.”

The first oil was discovered in Tatarstan in 1943, when the Romashkinskoye oil field, the largest oil field in Tatarstan, was discovered. PA Tatneft received the right to develop the Romashkinskoye field in 1950 when PA Tatneft was first formed. It was soon thereafter given the right to develop what is now Tatneft’s second largest oil field, the Novo-Yelkhovskoye field. Tatneft still produces most of its crude oil from these two fields. PA Tatneft subsequently also acquired licenses to numerous smaller fields in Tatarstan. See “—Exploration and Production” under this Item.

Tatneft’s core exploration and production, or “E&P,” activities are currently organized along geographic lines, although a number of exploration and production support functions have been centralized. Our core E&P activities are carried out by 11 units known as the Oil and Gas Production Departments, or by their Russian acronym “NGDUs.” Each NGDU is responsible for the exploration and production of crude oil on specified sections of oil fields. Each NGDU historically combined E&P activities (production wells, oil preparation and storage units, maintenance units, automation shops and research units) with E&P support capabilities (transport and construction) and certain “social” activities (housing and agriculture). As part of a reorganization program, our exploration and production support capabilities and certain social assets have been transferred into separate service companies (in the areas of drilling, well rehabilitation, production services, construction and assembly) and other companies (e.g., road construction and maintenance companies and collective farms). Certain other social assets are being transferred to local authorities (e.g., housing) in order to allow Tatneft to focus on its core E&P functions. We intend to retain control over the new E&P service companies but may not retain control over the other companies. See “—Corporate Reorganization” under this Item for more information.

Our other business segments are refining and marketing (including our interests in the Nizhnekamsk and Kichuyi oil refineries, our gas production, transportation and refining division “Tatneftegaspererabotka,” interests in oil trading companies and gas stations), petrochemicals (including our interests in the largest Russian tire producer, Nizhnekamskshina, and its technologically-integrated enterprises and management company OOO Tatneft-Neftekhim) and banking operations (including majority stakes in Bank Devon-Credit, an Almetyevsk-based retail and commercial bank that serves southeastern Tatarstan, and Bank Zenit, the nineteenth largest Russian bank by assets and eighteenth by net profit as of January 1, 2003, as calculated under RAR, according to the magazine Expert).

We have three exploration and production joint ventures with western and Russian partners:

In 2000, we purchased from the Tatarstan government a 34.6% share in Nizhnekamskshina, the largest tire producer in the Russian Federation, and also purchased additional shares in a new issuance by Bank Zenit, thereby increasing our holding to 50% plus one share and resulting in the consolidation of Bank Zenit for the first time in 2000.

Other transactions in 2000 included the acquisitions of 12.8% of Tatfondbank, a Tatarstan regional bank; 100% of Radio Telefonnye Tehnologii, a mobile communications provider in northwest Tatarstan, in return for oil and oil products deliveries to TAIF; 77.1% of OAO Nizhnekamsk Industrial Carbon Plant (“Nizhnekamsk Industrial Carbon Plant”), from the Tatarstan government; and 8.6% of ZAO Ukrtatnafta (“Ukrtatnafta”), which holds a 100% interest in the Kremenchug oil refinery in Ukraine. We also formed Tatneft-Europe, our marketing agent, and established control over OAO Tatneftekhimservice which, following its reorganization into the department Neftekhimservice, is currently being wound up. See “—Organizational Structure—Joint Ventures, Subsidiaries and Associated Companies” under this Item for additional information on these acquisitions.

In 2001, we increased our shareholdings in Nizhnekamskshina from 34.6% to 51.7%, in Bank Devon-Credit from approximately 27% to approximately 51%, in ZAO IFK Solid (“IFK Solid”), a Russian broker-dealer, from approximately 55% to approximately 60% and in Bank Ak Bars, a commercial bank registered in the Russian Federation, from approximately 10% to approximately 12%. In the second quarter of 2001, we acquired approximately 40% of the shares of the Minnibaevsk Gas Refinery, which we had held as collateral for a loan to the government of Tatarstan. We also acquired an approximately 27% interest in OAO Health Recovery Complex Zelenaya Rostsha, a company operating a resort and recovery center on the shores of the Black Sea, and established ZAO Yarpolymermash-Tatneft (“Yarpolymermash-Tatneft”), formed on the basis of the assets of Yaroslavl Polymer Machine Plant, to produce equipment for processing materials for tire production. In the course of 2001, our major divestitures included the sale of our 5.5% stake in OAO Norsi Oil, the operator of the NORSI oil refinery in Nizhny Novgorod.

In 2002, a reverse stock split carried out by the Minnibaevsk Gas Refinery resulted in our ownership of 100% of its outstanding shares, the minority shareholders having been cashed out. Subsequently, we merged the Minnibaevsk Gas Refinery into our newly-formed unincorporated gas production, transportation and refining division Tatneftegaspererabotka. We also increased our stake in Bank Devon-Credit to approximately 92.2% and in Bank Ak Bars to approximately 17.9% and divested our approximately 12.8% interest in Tatfondbank.

In the first half of 2003, we reached an agreement in principle to acquire the 50% of Kalmtatneft that we do not currently own and divested our interests in 21 agricultural companies. In the same period we allowed our stake in OAO Tatnefteotdacha, a joint venture that specializes in recovering hard-to-extract oil and increasing oil production efficiency, to decline from 14.5% to 3.5% following an additional share issuance in which we did not participate, following a prior reduction in 2001 from 49% to approximately 14.5%. We also plan to participate fully in a charter capital increase at Nizhnekamskshina approved by its shareholders at the June 11, 2003 annual shareholders’ meeting. Each shareholder of Nizhnekamskshina may subscribe for new shares in proportion to its holding as at the relevant record date. If some of the Nizhnekamskshina shareholders do not participate in the share capital increase, our ownership percentage in the company will increase.

We anticipate total capital expenditures for 2003 of approximately RR13,000 million, which will be financed through debt and operating cash flows. Our most significant current capital commitment is for the Nizhnekamsk refinery. Acting at the urging of Tatarstan President Shaimiev, in 1999 we entered into an agreement with Nizhnekamskneftekhim and TAIF, both related parties. We agreed to form a joint venture company, OAO Nizhnekamsk Oil Refinery, to expand, upgrade, and operate the refinery in Nizhnekamsk. Our total investment in the refinery amounted to approximately RR6,833 million (US$215 million) as of December 31, 2002 and we have budgeted capital expenditures of RR1,736 million for work on the refinery during 2003. This investment is reflected in our balance sheet as assets under construction and buildings and construction. We currently own 63% of OAO Nizhnekamsk Oil Refinery, the company that operates all the facilities at the refinery. However, we have not yet reached a final agreement with our partners on the contribution of various assets that we and they own at the Nizhnekamsk refinery to the charter capital of OAO Nizhnekamsk Oil Refinery. Since it is unknown how the contributions of the parties will be valued, it remains unclear whether our eventual interest in the company will adequately reflect our investments in and contributions to the joint venture.

We remain significantly leveraged, and as a result a substantial portion of our cash flow is required for debt service. In addition, cash flow from operations is dependent on the level of oil prices, which are historically volatile and significantly impacted by the proportion of production that can be sold on the export market. Historically, we have supplemented the cash flow

from operations with additional borrowings and may continue to do so. Should oil prices decline for a prolonged period and should we not have access to additional capital, we would need to reduce our capital expenditures, which could limit our ability to maintain or increase production and in turn meet our debt service requirements.

We also continued our program of transferring our social assets to public ownership. We transferred to public ownership assets with a net book value of RR1,293 million, RR593 million and RR128 million in the years ended December 31, 2002, 2001 and 2000, respectively.

We have not been the subject of any public takeover offers by third parties in the past two years.

Our consolidated group currently consists of over 100 companies with various organizational and legal forms, and we hold minority stakes in a number of other legal entities. OAO Tatneft directly controls or holds interest in 86 companies, including 39 companies that were separated from Tatneft during our restructuring, ten oil and oil-product sales companies, ten exploration, geological and drilling companies, four oil refining companies, two petrochemicals companies, 29 service and production companies, and 12 financial services institutions.

Our exploration and production segment is the largest segment, and comprises the majority of our structural subdivisions. It consists of 11 oil and gas production subdivisions, a natural gas production, transportation and refining subdivision, four well repair and reservoir oil yield improvement subdivisions, a chemical production subdivision (Neftekhimservis), two pumping equipment repair centers, a research and development institute and subdivisions responsible for geological exploration, communications and information support, drilling fluid delivery, security and logistics, foreign economic activities and other matters. This segment also includes service subsidiaries over which we continue to retain control.

Our refining and marketing segment consists of our interests in the Nizhnekamsk and Kichuyi refineries; OOO Tatneft-Resource, a management company for our gas stations network; and certain other oil trading and ancillary companies.

Our petrochemicals segment has been consolidated into a management company, OOO Tatneft-Neftekhim, which manages OAO Nizhnekamskshina, and the companies technically integrated with it, including Nizhnekamsk Industrial Carbon Plant, Efremovsk Synthetic Rubber Plant, Yarpolymermash-Tatneft and Nizhnekamsk Mechanical Plant. OOO Tatneft-Neftekhimsnab and OOO Trading House Kama are responsible for procuring supplies and marketing products produced by the companies of this segment.

Bank Zenit and Bank Devon-Credit constitute the banking segment. We also hold stakes in ten other financial services institutions.

We also have non-core assets, such as social and cultural facilities, road construction companies, transportation companies, telecommunications companies and other ancillary enterprises, most of which we plan to sell in the course of our continuing reorganization.

We have two oil production joint ventures with Western partners and participate in an exploration and production joint venture, Kalmtatneft, with the regional oil company Kalmneft. These Joint Ventures are included in our consolidated financial statements on an equity basis except for Tatoilgas, in which we currently own 52.5% and which is consolidated.

Currently, oil production by the Joint Ventures is limited. We believe that the primary benefits of the Joint Ventures are their contribution to us of new technologies and techniques which increase productivity and well recoverability and the introduction of new approaches to improve our organization and efficiency.

With the exception of Tatneft Oil AG and its subsidiaries, which are incorporated in Switzerland, including our Western European marketing agent Tatneft-Europe, all of our significant joint ventures, subsidiaries and associates are incorporated in the Russian Federation.

We control a number of subsidiary companies and have minority stakes in a number of associated companies, including those described below. We do not believe that any of these companies is material to our financial condition or results of operations.

Our strategic objectives are to enhance our position as a leading crude oil producer in Russia and to become an internationally recognized oil company. We seek to fulfill these objectives by (i) creating a vertically integrated oil company, (ii) maintaining production from our existing crude oil reserves base in Tatarstan and (iii) expanding and diversifying our reserves base outside Tatarstan, through the following strategic initiatives:

Shaping and improving our structure as a vertically integrated oil company. We intend to increase our refining capacity and to expand our petrochemicals activities and retail gasoline operations in order to become a vertically integrated oil company. The government of Tatarstan is actively encouraging this approach. We believe that increasing our presence in these market sectors is the most effective strategy for mitigating the potential risks presented by possible fluctuations in global crude oil prices and demand.

We intend to continue to develop our relationships with refineries that have installed, or plan to install, the equipment necessary to convert heavy fraction high sulfur content crude oil, which constitutes a large proportion of our production, into higher-value products such as gasoline, jet fuel and diesel. Together with TAIF and OAO Nizhnekamskneftekhim, the leading petrochemicals company in Tatarstan, we formed a new enterprise, OAO Nizhnekamsk Oil Refinery, which is expected to expand, upgrade, and operate the refinery in Nizhnekamsk. The first two units of the refinery were brought on stream in 2002, completing the Phase I Base Complex, and we intend to expand and upgrade this facility in the future together with our partners. Once the refinery begins to operate at its full rated capacity, this will decrease our dependence on refineries outside of Tatarstan and will enable us to produce more environmentally friendly oil products from high sulfur crude oil.

In addition to investing in our refining activities, we own a 51.7% stake in Nizhnekamskshina, the largest tire-producing factory in the Russian Federation, located in the city of Nizhnekamsk. We also own a 77.7% share of Nizhnekamsk Industrial

Carbon Plant, a major supplier of technical carbon to tire manufacturers in Russia, including Nizhnekamskshina. We also formed Yarpolymermash-Tatneft, of which we own 51%, in 2001 based on the assets of Yaroslavl Polymer Machine Plant to construct equipment for processing materials for tire production. In 2000, we established control over a large producer of chemical reagents, OAO Tatneftekhimservice, and began construction of a plant in Nizhnekamsk for the production of synthetic lubricants for engines and machinery. We plan to complete the construction and launch production at the plant in the summer of 2003. To increase the efficiency of our petrochemicals operations, in 2002 we created the management company OOO Tatneft-Neftekhim (“Tatneft-Neftekhim”) and transferred control over our shares in Nizhnekamskshina, Nizhnekamsk Industrial Carbon Plant, Yarpolymermash-Tatneft and other petrochemicals companies to it.

In order to improve our structure as a vertically integrated oil company, in 2002 we merged our natural gas production, refining and transportation assets into one division (“Tatneftegaspererabotka”), established OOO Tatneft-Bureniye, a drilling management company, and continued our restructuring in order to optimize costs and improve management efficiencies. See “—Corporate Reorganization” under this Item.

We are also currently expanding our network of retail gasoline sales outlets both inside and outside Tatarstan, particularly in Moscow and the Moscow, Vladimir, Volga, Urals, Leningrad and Nizhny Novgorod regions in Russia. We are conducting this expansion both directly and through our subsidiaries and affiliates. Tatneft owned or operated 342 gas stations in Russia at the end of 2002.

Maintain crude oil production from existing fields. We plan to maintain production from our existing fields at approximately the current level, given the absence of significant changes in taxation or production sharing legislation. We believe that this level of production will optimize the long-term value of the reserves base while generating cash flows to support our current operations. We expect to continue to implement our well rehabilitation program to increase the use of secondary and tertiary recovery methods in order to maintain production levels. Our ability to carry out these programs will be limited by the extent to which we can obtain the necessary financing. We also are actively pursuing opportunities to use new technologies in order to maximize the recovery from our existing reserves base.

Expansion of reserves base outside Tatarstan. We intend to expand and diversify our reserves base by gaining access to reserves outside Tatarstan, particularly in Kalmykia, the Ulyanovsk, Orenburg, Saratov and Murmansk regions, and the Chuvash Republic. We intend selectively to establish strategic alliances to develop and operate oil fields in order to facilitate this process. Outside the Russian Federation, we participate or intend to participate in projects in Iraq, Iran and Syria, where both we and Russia have strong historical ties, subject to compliance with applicable international sanctions regimes.

The following table presents our net proved reserves at January 1, 2003, 2002 and 2001. Net reserves are defined as the allocated portion of the gross reserves to a particular economic interest on a property. Unless otherwise noted, all presentations of reserves in the following section are with respect to net reserves.

The proved reserves may be further divided into volumes estimated to be produced before and after the expiration dates of their respective field production licenses. Article 10 of the Russian Federal Law on Subsoil, dated February 21, 1992 and March 3, 1995 (as amended), provides that a license to use a field may be extended at the initiative of the license holder where the license holder complies with the terms of the license and where the development of the field requires completion or liquidation operations. Our most significant licenses expire in 2013, but we believe that we would be able to extend them at our initiative on commercially reasonable terms and plan to extend them. The tables below illustrate the division of our reserves for the periods up to and following the license expiration dates.

As we believe that we would be able to extend our licenses subsequent to their expiration dates, the discussion below includes quantities expected to be produced assuming renewal of the licenses. The following table presents, by major field, our net proved reserves, at January 1, 2003, 2002 and 2001.

According to an appraisal of our reserves performed by the engineering firm Miller and Lents, Ltd., as of January 1, 2003 our reserves base had increased by 9.5%, bringing the total volume of proved developed and undeveloped reserves to 838.4 million tons (5,972.0 mmbbl). We had 774.8 million tons (5,519 mmbbl) of Proved Developed Reserves at January 1, 2003, of which Proved Developed Producing Reserves accounted for approximately 478.3 million tons (3,406.7 mmbbl) or 57.0% of the total. The increase in our reserves during 2002 is primarily attributable to fluctuations in price and cost levels that impact the economic viability of recovering oil from certain of our fields. Most of our reserves consist of crude oil with a high sulfur content (over 1.8% sulfur by mass), and the average sulfur content of the high sulfur content crude oil that we produce is approximately 3.5% by mass. This high sulfur content crude oil typically commands a lower price in the market, although the impact of this is mitigated by Transneft’s practice of blending high and low-sulfur crude oil. In 2002, approximately 41.1% of our total oil production volume was high sulfur crude oil. See “—High Sulfur Content Crude Oil” under this Item for additional information.

Our crude oil reserves currently have a water cut of approximately 82.8% when produced, meaning that 82.8% of the fluid produced is water. The crude oil and extracted water are separated in field separation facilities. The crude oil is then transferred into the Transneft pipeline system for further distribution and the remaining water is re-injected into our wells to maintain reservoir pressure.

We have preliminary plans to expand our reserves outside Tatarstan by various means. We are considering expanding our operations in other regions of Russia, including Kalmykia and Siberia. In May 2000, in conjunction with the regional oil company Kalmneft, we established Kalmtatneft, of which we own 50%. Kalmtatneft currently holds four exploration and production licenses for oil fields in Kalmykia. Tatneft itself currently holds licenses for exploration in the Ulyanovsk region and the Chuvash Republic and a joint exploration and production license for the Matrosovskoye oil field, located in both Tatarstan and the Orenburg region. Moreover, in 2002 we found oil in the Medovoye oil field in the Orenburg region and expect to receive a production license for it.

We also have plans to acquire exploration, development or production rights in Iran, Iraq and Syria. Although most of the U.N. and U.S. sanctions against Iraq have been lifted subsequent to the military action in Iraq in 2003, prior to the lifting of the sanctions we exported Iraqi oil under the U.N. oil-for-food program, participated in a consortium that includes Rosneft, a major state-owned Russian oil company, to develop Iraqi oil fields, drilled a number of oil wells in Iraq under U.N.-approved contracts and opened a representative office in Iraq. The status of these existing agreements to develop Iraqi oil fields is at present uncertain, but we are actively involved in negotiations with respect to their future status. We have also opened a representative office in Iran and have submitted proposals to participate in tenders to provide engineering services and to obtain production licenses for a group of Iranian oil fields. We believe that our operations in Iran have been conducted in full compliance with applicable Russian, U.S. and international law. We are also planning to participate in tenders for the development of oil fields in Syria.

Since January 1, 2002, we have funded our exploration operations, including exploratory drilling, from internal funds. Prior to 2002, we funded these activities primarily through funds that we received from the Tatarstan Mineral Restoration Fund (the “Restoration Fund”). We were required to contribute to the Restoration Fund an amount equal to 8.0% of our total expected sales proceeds (net of VAT and excise tax) for all crude oil that we extracted, and received back from the Tatarstan government each year a portion of our required contribution. In 2001, we received back approximately RR563.5 million, or 9.6% of our required contribution. We could carry-forward to subsequent years any amounts received but not used in the year of receipt. These funds had to be used to conduct exploration activities in Tatarstan relating to increasing recoverability of oil from existing deposits, certain purchases of new equipment, and certain research and development activities. The Tatarstan government had to approve the use of these funds. Due to a change in Russian legislation, since January 1, 2002 we no longer make contributions to the Restoration Fund.

High sulfur content crude oil, defined as crude oil containing more than 1.8% sulfur by mass, represents most of our total proved reserves. Our high sulfur content crude oil contains on average 3.5% sulfur by mass. We believe that high sulfur content crude oil as a proportion of our production will increase in the future due to the maturation of our low sulfur content crude oil fields and the resulting decrease in production volumes. The amount of high sulfur content crude oil as a percentage of our crude oil production steadily increased from 1986 (20.2%) to 1992 (28.1%). In 1993 and 1994, high sulfur content crude oil represented a smaller portion of our crude oil production (26.1% in 1993 and 22.9% in 1994), as we experienced difficulties in exporting high sulfur content crude oil to the Kremenchug refinery in Ukraine due to the temporary disruption of trading relations between Russia and other parts of the CIS. Our production of high sulfur content crude oil increased to approximately 41.1% in 2002 as a result of renewed shipments to Kremenchug starting in 1995, the establishment of new arrangements with refineries in Bashkortostan, Nizhnekamsk and elsewhere that are capable of refining high sulfur content crude oil and our ability to transport our high sulfur oil through the national pipeline system.

In the year ended December 31, 2002, we produced approximately 24.9 million tons (177.3 mmbbl) of crude oil, not including our share of production by non-consolidated Joint Ventures (as defined under “—Joint Ventures, Subsidiaries and Associated Companies” under this Item). This represented approximately 6.6% of the total crude oil production in Russia in 2002, making Tatneft the sixth largest crude oil producer in Russia.

Our largest oil field is the Romashkinskoye field, from which we produced approximately 14.4 million tons (102.6 mmbbl) of crude oi1 in 2002. We produced approximately the same quantities of crude oil from the field in prior years, 14.5 million tons (103.2 mmbbl) in 2001 and 14.3 million tons (101.9 mmbbl) in 2000. The field was discovered in 1943, began producing in 1945, and reached peak production levels in 1970. The field is one of the largest in Russia in terms of reserves and physical size, covering an area of approximately 520,309 hectares (approximately 2,000 square miles).

Our second largest oil field is the Novo-Yelkhovskoye field, from which we produced approximately 2.4 million tons (17.1 mmbbl) of crude oi1 in 2002. We also produced approximately 2.4 million tons from the field in 2001 and 2000. The field was discovered in 1956, began producing in 1958, and reached peak production levels in 1976. The field covers an area of approximately 124,543 hectares (approximately 479 square miles).

Our third largest oil field is the Bavlinskoye field, which was first discovered in 1946 and began production in the same year. Production from the field was approximately 779,600 tons (5.7 mmbbl) in 2002, approximately 773,000 tons (5.5 mmbbl) of crude oil in 2001 and approximately 478,500 tons (5.3 mmbbl) in 2000. The field reached peak production levels in 1957. The field covers an area of 46,989 hectares (approximately 181 square miles).

We reached our peak production levels of approximately 100 million tons (712.0 mmbbl) of crude oil per year in the mid-1970s. Our production declined from 1980 to 1993 due to the maturation of production from the Romashkinskoye and Novo-Yelkhovskoye fields. The reduction in output was compounded by the Russian economic recession of the early 1990s following the dissolution of the Soviet Union, which led to a downturn in demand for crude oil in Russia and a lack of capital investment. Since 1994, our production, combined with that of our Joint Ventures, has stabilized at approximately 24 million tons per year and increased slightly since then. We achieved this stabilization of production by utilizing a broad range of advanced oil extraction techniques, including hydrodynamic, geophysical, chemical, thermal, gas and microbiological technologies. Other factors contributing to the stabilization of production volumes since 1994 have included:

Tax benefits. In 1999 and 2000, we benefited from certain tax reductions and exemptions granted by Tatarstan with respect to some of the revenues derived from low-productivity wells. Other Tatarstan laws provided additional benefits, including:

Tatarstan had in the past granted to us tax benefits with respect to some of the revenues derived from wells on newly exploited oil fields and from crude oil produced using secondary and tertiary crude oil recovery techniques, including an exemption from payments to the Restoration Fund in respect of such crude oil. Certain other Tatarstan tax benefits also aided us in the past in maintaining production volumes, including the return to us of up to 80% of the amount otherwise allocable to the Restoration Fund in 1995 and 1996, approximately 42% to 49% from 1997 through 1999, approximately 13.5% in 2000 and approximately 9.6% in 2001. As a result of reconciling the Russian and Tatarstan tax regimes, we no longer enjoy any specific tax benefits in Tatarstan. Although the Tatarstan government set for us the minimum rates permitted by Russian legislation for the payments for the right to explore and appraise oil fields and prospect for natural resources in 2002, effective from January 1, 2003, the Tatarstan government raised the rates to the maximum level permitted by the legislation. Our rates for 2003 in Tatarstan are 360 rubles/sq. km. for the right to explore and appraise oil fields (compared to 120 rubles/sq. km. in 2002) and 20,000 rubles/sq. km. for the right to prospect for natural resources (compared to 5,000 rubles/sq. km. in 2002).

Prior to January 1, 2002, we benefited from tax reductions granted by Russian Government Regulation No. 1213 of November 1, 1999. This regulation allowed the Ministry of Natural Resources to exempt oil companies from payments for oil production and royalties for the use of subsoil due to the federal budget with respect to oil produced from rehabilitated and temporarily inactive wells as of January 1, 1999.

Well rehabilitation. Well rehabilitation primarily involves replacing or reconditioning pumps, replacing corroded pipes, and clearing well bores in order to bring wells back into production. In 1994, we launched a well rehabilitation program that was designed to reduce the number of non-operational production wells. By December 31, 2002, we had reduced this proportion to approximately 17% of production wells, compared to approximately 18.2% as of December 31, 2001 and 23.9% as of December 31, 2000.

Secondary and tertiary recovery. As most of our oil fields, including Romashkinskoye, our largest, are in a mature stage of development, we have designed and successfully implemented a range of measures aimed at maintaining and even increasing production volumes from these mature fields. The amount of our total crude oil production (excluding production attributable to Tatoilgas) resulting from the use of advanced secondary and tertiary crude oil recovery techniques has increased from approximately 7.4 million tons (52.7 mmbbl) in 1994 to approximately 11.4 million tons (81.2 mmbbl) in 2002, currently representing 46.5% of all oil extracted (including approximately 11% from the use of tertiary recovery techniques). These advanced techniques include flow rate and water injection pattern management, horizontal drilling, hydraulic rupture of formations and chemical, microbiological and thermal recovery techniques.

Production costs. Our overall crude oil production costs have generally increased in recent years. However, in 2002 our “lifting costs” per barrel—costs directly associated with the extraction of crude oil—decreased by approximately 9.9% from US$2.74 in 2001 to US$2.47 in 2002, primarily as a result of our cost-savings program. These effects, however, were offset by increased overhead costs in the production departments, increases in transportation costs attributable to increased Transneft tariffs and greater volumes of CIS exports, the introduction of the unified natural resources production tax and higher depreciation, depletion and amortization expenses due to our investments in oil field development, resulting in an overall increase in per barrel production costs of 16% from US$8.20 in 2001 to US$9.51 in 2002.

As of December 31, 2002, Tatneft possessed a total of 41,923 wells. Of these, 19,832 were active production wells and 8,259 were active injection wells. Production wells are used to extract oil, while injection wells are used to pump water or other agents into the reservoir in order to maintain pressure and to enhance crude oil recovery.

The table below sets forth information on our wells as at December 31, 2002, 2001 and 2000.

The table below sets out the drilling activity of Tatneft and our Joint Ventures in the years ended December 31, 2002, 2001 and 2000.

Tatneft drilled 417 new production wells in 2002, 580 new production wells in 2001 and 357 new production wells in 2000. Our Joint Ventures drilled 175, 95 and 119 new production wells in 2002, 2001 and 2000, respectively. We generally drill more wells in the second half of each year than in the first half of each year, as weather conditions and poor roads make it difficult to drill during the spring. Most exploration activities conducted in the years ended December 31, 2002, 2001 and 2000 took place in the southern and eastern parts of Tatarstan.

In the year ended December 31, 2002, approximately 531 production wells were taken out of operation. We rehabilitated 2,745 production wells in 2002, accounting for 13.8% of the active producing wells as of December 31, 2002. In the year ended December 31, 2001, approximately 392 wells were taken out of operation. We rehabilitated 2,491 wells last year, accounting for approximately 12.6% of the active producing wells as of December 31, 2001. In the year ending December 31, 2000, approximately 514 wells were taken out of operation. We rehabilitated 3,227 wells in 2000, accounting for approximately 17.1% of the active producing wells as of December 31, 2000.

In 2002, we improved production at 1,497 production wells, representing approximately 7.5% of the active production wells as of December 31, 2002. In the year ended December 31, 2001, we improved production at 3,309 production wells, accounting for approximately 17% of active production wells as of December 31, 2001. In the year ended December 31, 2000, we improved production at 2,237 production wells, approximately 11.8% of active production wells as of December 31, 2000.

We plan to continue our well stimulation program, subject to obtaining necessary financing. We produced approximately 11.4 million tons (81.5 mmbbl), or 45.8% of our crude oil, in 2002 using these secondary and tertiary recovery techniques (including approximately 10.9% from the use of tertiary recovery techniques). We intend to continue to use these and other enhanced recovery techniques to optimize our production of crude oil and expect that crude oil produced using these methods will increase as a percentage of our total production.

The Federal Law on Production Sharing Agreements (the “PSA Law”) established the principal legal framework for state regulation of PSAs relating to oil field development and production. It came into force in January 1996, and was subsequently amended on January 7, 1999 and on June 18, 2001. PSAs are commercial arrangements between a government and private investors with respect to the production of oil or other mineral resources. Under a PSA, all or part of the tax burden on the investors is replaced by a share of production either in cash or in kind, generally after development costs have been recovered, as agreed between the parties. Under the PSA Law, both the Russian government and the local authorities of the region where an oil field is located represent Russia in the agreement. The PSA Law contains stabilization rules purporting to protect investors against adverse changes in federal and local laws and regulations. However, a number of related regulations (e.g. customs regulations) need to be adopted before investors are likely to use the PSA Law to enter into a PSA. Though the Tatarstan law on PSAs was abolished on March 23, 2001 as part of the process of reconciling the Russian and Tatarstan tax regimes, some uncertainty remains

regarding the relationship between similar Tatarstan legislation and federal rules. For example, Tatarstan Law No. 2147 of May 20, 1999 that approved the list of subsoil fields eligible for PSAs continues to exist in parallel with federal legislation.

The PSA Law only applies to oil fields on a list approved by the State Duma. The Romashkinskoye oil field, our largest producing field, is among the natural resources deposits on this approved list.

We transport most of our crude oil through the pipeline system operated by Transneft, Russia’s monopoly pipeline operator. The Ministry of Energy allocates usage of the pipeline network for domestic deliveries to oil producers on a quarterly basis. The Ministry’s allocation of pipeline capacity for export deliveries is supervised by a Russian government commission (the “Pipeline Commission”) initially established in 1995 with overall responsibility for the distribution of pipeline export capacity to producers. The Pipeline Commission includes representatives of a wide range of federal ministries and agencies. We do not believe that our share of pipeline export capacity will be materially adjusted in the near future.

Currently, the pipeline capacity, including non-CIS export pipeline capacity, and sea terminal access are allocated among oil producers on a quarterly basis in proportion to the volume of oil produced and delivered to the Transneft pipeline system in the previous quarter. Our non-CIS export pipeline allocation is equivalent to approximately one-third of the oil we produce and deliver to Transneft. We are required to pay taxes owed to the Russian government in order to maintain our access to export pipelines and seaports. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company.”

Transneft sets the tariff rates for using its pipelines subject to the oversight of the Federal Energy Commission. The Federal Energy Commission is authorized to regulate the activities of natural monopolies in the petroleum and energy transmission networks. Pipeline transportation costs have risen substantially over the past several years. The overall price to transport crude oil depends on the number of Transneft “districts” through which the oil is transported. Currently, the pipeline tariff (determined using the Central Bank’s ruble/U.S. dollar exchange rate at June 1, 2003 and exclusive of VAT) for us to transport crude oil to Moscow is approximately US$3.60 per ton; to the Kremenchug refinery, approximately US$5.93 per ton; to Novorossisk, approximately US$7.92 per ton; to Ventspils, approximately US$8.88 per ton and to Germany approximately US$7.00 per ton. In addition, Transneft charges a premium of US$3.00 per ton to deliver high sulfur content crude oil when it is mixed with other, low sulfur content crude oil. See “—Exploration and Production—Reserves and Fields—High Sulfur Content Crude Oil” under this Item.

Transportation costs for the shipment of our crude oil are covered out of the price of crude oil exported to both CIS and non-CIS countries. We pay these rates in advance. Domestic prices do not include transportation costs, because we charge domestic buyers separately for the cost of transportation. We pay transportation costs with respect to tolling arrangements, as crude oil delivered under such contracts remains our property.

In 2002, we started shipping crude oil by railroad from the Nizhnekamsk oil refinery’s oil-loading platform, and our total rail shipments in 2002 were approximately 48,400 tons of crude oil.

Historically, we have sold the crude oil that we produced ourselves or purchased from other producers on the domestic Russian market, exported it to other countries in the CIS, primarily Ukraine, or exported it to non-CIS countries. Domestic crude oil prices have traditionally been lower than prices that we are able to realize on our export sales. Since we own and lease limited refining capacity, we generally either sell crude oil to intermediaries and then purchase refined products produced from our oil for further resale, or transfer oil to refineries for refining under tolling arrangements and receive in return refined products for sale into the market. We are trying to reduce our dependence on third parties for refining of our oil by building up our own refining capacity in Nizhnekamsk. In recent years, we have shifted the focus of our domestic Russian market activities to selling refined products instead of selling primarily crude oil. We have also been developing a network of service stations from which to sell our refined products to end consumers.

We have three markets for the crude oil that we produce ourselves or purchase from other producers: (i) the domestic Russian market; (ii) the market for exports to the CIS; and (iii) the market for exports to non-CIS countries. In recent years, we have shifted the focus of our domestic Russian market activities to selling refined products instead of selling primarily crude oil. Since we own and lease limited refining capacity, we generally either sell crude oil to intermediaries and then purchase refined products produced from our oil for further resale, or transfer oil to refineries for refining under tolling arrangements and receive in return

refined products for sale into the market. Starting from 2001, we shifted our emphasis from using intermediaries to tolling arrangements. See “—Refined Products—Refining” under this Item.

The table below sets forth certain data with respect to the sales and transfer volumes of crude oil that we produced and purchased from other producers for the years ended December 31, 2002, 2001 and 2000.

Our export volumes in 2002 increased in comparison to those in 2001 primarily due to a significant increase in CIS exports. Export sales are generally made at a higher price, and we are required to export certain volumes of crude oil in connection with our obligations under some of our loan agreements (see “Item 5—Operating and Financial Review and Prospects—Liquidity and Capital Resources—Debt”). Revenues from sales of crude oil accounted for approximately 55.9% of total sales revenues in 2002, compared to 61.2% in 2001.

We charge world market prices for crude oil exported to non-CIS countries, including the Baltic states. Although the average price for non-CIS exports is considerably higher than CIS and domestic prices, we are prevented from exporting additional amounts of oil to non-CIS countries due to our limited access to the Transneft pipeline network. See “—Transportation” under this Item.

In 2002, we supplied approximately 38.1% of our non-CIS deliveries to customers located in Germany, Poland, the Czech Republic and Slovakia via the Druzhba pipeline. We exported most of the remainder via the ports of Novorossisk, Ventspils, Primorsk, Tuapse and Butinge, primarily to customers located in Turkey, France and Germany, or via the Transneft pipeline system to the Baltic states.

We sell most of the oil that we export to international oil traders. We generally conclude export sales for delivery at the relevant port (in the case of shipment by oil carrier) or for delivery at the Russian border (in the case of cross-border pipeline transport) and usually receive payment for exports to non-CIS countries within one month of delivery. The price of non-CIS exports generally must cover transportation costs that we pay to Transneft. See “—Transportation” under this Item. In 2002, our non-CIS crude oil prices per ton averaged RR5,330, slightly less than the 2001 average of RR5,549.

We make our non-CIS export sales for hard currency. A substantial portion of our non-CIS foreign currency export volumes are pledged as security for our foreign currency loans. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company,” “—Relationship with Tatarstan” under this Item and “Item 5—Operating and Financial Review and Prospects—Liquidity and Capital Resources—Debt.”

We currently do not hedge our foreign currency exposure (except, to a certain extent, for Bank Zenit, our principal banking subsidiary, in connection with its own operations), but may do so in the future to the extent that we are able to do so. See “Item 10—Additional Information—Exchange Controls” and “Item 11—Quantitative and Qualitative Disclosures about Market Risk—Derivatives.”

CIS exports comprise exports to member nations of the CIS other than Russia, and represent primarily exports to the Kremenchug refinery in Ukraine. CIS crude oil prices have historically been lower than the prices we are able to realize on our

non-CIS exports but higher than domestic prices. In 2002, we delivered approximately 4.0 million tons of crude oil to the Kremenchug refinery, representing approximately 99.4% of our CIS crude oil sales. The price of CIS exports generally must cover transportation costs that we are required to pay to Transneft. See “—Transportation” under this Item. CIS average crude oil prices per ton decreased to RR2,823 in 2002 from RR4,078 in 2001, a 30.8% decrease, due to the decline in market prices in the CIS.

Domestic crude oil prices are normally lower than world market prices, and are only weakly correlated with them. Domestic crude oil prices result from the supply and demand imbalance within the domestic market which, owing to the limitations on export, is generally significantly oversupplied. In 2002, our domestic prices per ton averaged RR2,203, compared to the average price of RR3,036 per ton in 2001, representing a 27% decrease.

We conclude a significant portion of our domestic crude oil sales with a number of domestic oil dealers, who then sell oil to refineries. We have long-standing relationships with many of the domestic oil dealers, but do not currently maintain any material long-term contractual commitments. We also transfer oil under tolling arrangements with third parties, under which we receive refined products for sale into the market.

Much of the crude oil sold to domestic oil dealers or transferred by us under tolling arrangements is ultimately delivered to the Nizhnekamsk oil refinery, the Moscow oil refinery and Yaroslavl oil refinery. In 2002, approximately 96.3% of our total domestic crude oil shipment volumes were ultimately delivered to these three refineries, including approximately 52.6% to the Nizhnekamsk oil refinery. Deliveries were also made to other refineries located throughout European Russia, including in Ufa, Saratov, Samara and Ryazan. In total, approximately 9.1 million tons were delivered to domestic refineries, representing approximately 44.7% of all our deliveries (excluding purchased oil) in 2002.

We conduct a small portion of our crude oil sales through barter transactions. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company—Barter transactions may adversely affect our cash flows” and “Item 5—Operating and Financial Review and Prospects—Overview—Factors Affecting Crude Oil and Refined Products Sales—Barter Transactions.”

High sulfur content crude oil has a lower market value than crude oil with a low sulfur content. The national pipeline operator, Transneft, charges a premium of US$3.00 per ton for blending and transporting crude oil with a sulfur content of more than 1.8%, which includes our high sulfur content crude. The fee is payable in rubles, converted at the exchange rate in effect on the first day of each month. Because the blended crude oil sells for a uniform price and the US$3.00 premium is less than the market discount that we would receive for our high sulfur crude oil, Transneft’s current practice of blending our high sulfur content crude oil benefits us. Although Transneft limits the amount of high sulfur content crude oil that we can ship in this way, we blended and shipped approximately 6.1 million tons (43.1 mmbbl) of the high sulfur content crude oil we produced in 2002 through the Transneft pipeline system, constituting approximately 59.8% of our high sulfur content crude oil production. We ship the balance of our high sulfur content crude oil via dedicated Transneft pipelines to refineries able to process high sulfur content crude oil including refineries located in Moscow, Ryazan, Ufa, Yaroslavl and Nizhnekamsk.

The Russian and Tatarstan governments can—and in the past have—mandated certain deliveries of crude oil and oil products by us through either formal or informal pressure. Government-directed deliveries take precedence over market sales, and may be, and in the past have been, compensated at less than market prices. Government-directed deliveries are sometimes made in order to effect export sales to obtain foreign currency for government use, while in other cases deliveries are directed to government agencies, the military, agricultural producers, to remote regions or to specific refineries such as Nizhnekamskneftekhim refinery in Tatarstan. Government-directed deliveries may disrupt our relations with clients and result in sales at prices lower than what we could otherwise receive. See “Item 3—Key Information—Risk Factors—Risks Relating to Tatarstan—The Tatarstan government may exercise significant influence over our opportunities” and “Item 5—Operating and Financial Review and Prospects—Overview—Factors Affecting Crude Oil and Refined Products Sales—Government-Directed Deliveries.”

Tatneft did not receive any refining capacity as a result of the privatization of the Russian oil and gas sector. However, we have increasingly been developing our refining capabilities, and reducing our reliance on purchases of refined products from third parties.

In August 1997, Tatarstan President Shaimiev announced plans to expand and upgrade the petrochemicals complex at Nizhnekamsk, owned by Nizhnekamskneftekhim, in order to enable Tatarstan to become independent from refineries located elsewhere. Towards this end, we entered into discussions with Nizhnekamskneftekhim and TAIF, both of which are related parties under the influence of the Tatarstan government. These discussions resulted in an agreement to form a joint venture company OAO Nizhnekamsk Oil Refinery that would expand, upgrade and operate the Nizhnekamsk refinery. Our total investment in the refinery amounted to approximately RR6,800 million (US$215 million) as of December 31, 2002, and we own 63% of OAO Nizhnekamsk Oil Refinery. OAO Nizhnekamsk Oil Refinery currently operates all the facilities at the refinery, though it does not own those facilities. Our and our partners’ interests in the joint venture are still under negotiation, however, pending the valuation of the assets we and our partners are planning to contribute to it. We currently ship the principal refined products from Nizhnekamsk oil refinery to the Nizhnekamskneftekhim chemical complex and sell the by-products to various other customers.

The expansion and upgrade of the Nizhnekamsk oil refinery is being made on the basis of a feasibility study, prepared with the assistance of consultants ABB Lumus Global Inc., which examined various refining methods in order to determine the best way to produce higher-value products from our high sulfur content oil. Completion of these facilities will decrease our dependence on refineries outside of Tatarstan and will enable us to produce more environmentally-friendly oil products from high sulfur crude oil, including diesel fuel that adheres to European environmental standards, and ultimately with an output of light fractions of between 82% and 84%. Operations on our first production line (the Unoxidized Bitumen Line) at the Nizhnekamsk refinery commenced in March 2002, and in December 2002 the Phase I Base Complex of the oil refinery became operational. This Base Complex is designed to process seven million tons of crude oil per year and will eventually allow for producing aviation kerosene, diesel fuel and fuel oil, unoxidized bitumen, vacuum gasoil and other refined products. We own these facilities directly, and separately from our interest in OAO Nizhnekamsk Oil Refinery.

As a result of measures that we undertook in recent years in the areas of sales and marketing of refined products, our sales structure has undergone significant changes. Increased sales of refined products in domestic markets resulted from further development of our retail network. Due to the fact that we own and lease limited refining capacity, we sell crude oil to intermediaries, who then refine oil in domestic refineries, following which we purchase refined products processed from our oil. In 2002, we purchased refined products totaling approximately 4.5 million tons, of which we exported 2.2 million tons. We sold refined products totaling 12.6 million tons, 13.4 million tons and 13.7 million tons, and earned revenue of RR44,876, RR43,859 and RR65,121 million from these sales for the years ended December 31, 2002, 2001 and 2000, respectively. The decreasing volume of these sales is attributable to a shift away from purchases and resales of refined products in favor of an increased emphasis on selling our own refined products.

We own a small oil refinery in Kichuyi, Tatarstan, that began operating in 1995. This refinery is one of the most technologically modern in Russia. It has an annual refining capacity of 400,000 tons (approximately 7.8 mbpd), produces gasoline and diesel fuel and serves primarily our fuel needs and those of local residents of the Almetyevsk region.

We also own the Minnibaevsk Gas Refinery. Deliveries from the Minnibaevsk Gas Refinery in 2002 totaled 565,943 thousand tons of gas products, of which approximately 43.8% were delivered to Nizhnekamskneftekhim, 17.4% exported, and the balance sold to other domestic customers.

We own an 8.6% interest in Ukrtatnafta, a company with a 100% ownership interest in the Kremenchug refinery in Ukraine, one of the largest refineries for high sulfur crude oil in the CIS. The government of Tatarstan owns 28.8% of the outstanding share capital of Ukrtatnafta. The Ukrainian government owns approximately 43.1% of Ukrtatnafta’s shares and announced plans to privatize this stake in the Fall of 2003. Along with other Ukrtatnafta shareholders we have the right of first

refusal with respect to such shares and may exercise this right if the privatization proceeds as planned. We also own approximately 8% of the Moscow oil refinery, which entitles us to a share of its capacity in proportion to our shareholding, or approximately 120,000 tons per month. We may become involved in additional alliances and equity participations with certain refineries to which we deliver crude oil. See “—Organizational Structure—Joint Ventures, Subsidiaries and Associated Companies” under this Item.

Tolling arrangements accounted for a significant portion of our crude oil product sales in 2002. Under a tolling arrangement, a refinery processes crude oil for us in exchange for either a proportion of the crude oil, a proportion of the refined products, or a payment made by us. We retain ownership of the crude oil and of the related derivative products throughout the refining process.

We are also actively engaged in developing our retail sales network for refined products. As of December 31, 2002, Tatneft owned or operated 342 service stations throughout Russia including 114 in Tatarstan, 114 in Moscow and the Moscow region and 56 in the Chuvash Republic. In 2002, we also won tenders for delivery of oil products to the Ministry of Defense, to which we delivered 121,500 tons of refined products, and to the Ministry of Extraordinary Situations, to which we delivered 9,800 tons of refined products.

We did not receive any petrochemicals companies in connection with the privatization of the Russian oil and gas sector. However, in an attempt to create a vertically integrated company, starting in 2000 we have been increasing our petrochemicals capabilities. Thus, in 2000 we purchased approximately 34.6% in Nizhnekamskshina from the Tatarstan government and increased our stake to 51.7% in 2001. Nizhnekamskshina has been consolidated in our consolidated financial statements from September 30, 2001.

Nizhnekamskshina is the largest tire manufacturer in Russia, accounting for approximately 28% of all tires produced in Russian in 2002 and supplying its products to both domestic and foreign markets. Nizhnekamskshina consists of two division, a mass tires plant producing tires for light-weight vehicles and a truck tires plant. Approximately 25.9% of the tires produced by Nizhnekamskshina in 2002 were supplied to car manufacturers (29.1% in 2001), 60.3% were sold on the secondary market (65.7% in 2001) and 13.7% were exported (5.2% in 2001), including approximately 10.3% (1.4% in 2001) to customers in the CIS. We intend to renovate the manufacturing facilities at Nizhnekamskshina, and to attract investment and know-how from Western partners. To this end, in May 2002 Nizhnekamskshina entered into an agreement with Italian tire producer Pirelli to use Pirelli’s know-how and equipment to produce up to two million high-efficiency radial tires for light passenger cars. We expect to start producing such tires in 2004.

We also acquired approximately 77.1% of the Nizhnekamsk Industrial Carbon Plant in 2000 from the Tatarstan government. Nizhnekamskshina obtains raw materials from the Nizhnekamsk Industrial Carbon Plant. Nizhnekamsk Industrial Carbon Plant also sells its products to other Russian tire manufacturers and exports its products to Poland, Bulgaria, India, China, Vietnam, Indonesia, Turkey and other countries. In addition, we formed ZAO Yarpolymermash-Tatneft, of which we own 51%, based on the assets of the Yaroslavl Polymer Machine Plant, in order to manufacture equipment for processing materials for tire production. In the summer of 2003, we plan to commence production at OOO Tatneft-Nizhnekamskneftekhimoil, a polialphaolefin-based synthetic lubricants plant and the only such enterprise in Russia.

In 2002, we created Tatneft-Neftekhim as a management company for our petrochemicals operations, and transferred to it our holdings in Nizhnekamskshina, Nizhnekamsk Industrial Carbon Plant, Yarpolymermash-Tatneft, Tatneft-Nizhnekamskneftekhimoil, Trading House “Kama,” OAO Plant Elastic and other petrochemicals companies.

We own shares in a number of banking and financial entities, and have recently increased our activities in these market sectors. The banks in which we hold significant stakes are:

We conduct our banking operations through, and consolidate the results of, Bank Zenit and Bank Devon-Credit.

Our principal banking business activity is commercial banking operations within the Russian Federation. The number of employees engaged in our banking activities was 1,273 and 974 at December 31, 2002 and 2001, respectively: Bank Zenit employed 782 and 639 persons at December 31, 2002 and 2001, respectively, and Bank Devon-Credit employed 491 and 335 persons at December 31, 2002 and 2001, respectively.

Because Bank Zenit is the only significant banking subsidiary of ours, unless otherwise indicated, all information provided in the following sections is solely with respect to Bank Zenit. Information provided is presented after elimination of intercompany balances and transactions between Bank Zenit and other members of our consolidated group.

Banking activities in the Russian Federation are regulated by the Constitution of the Russian Federation, Federal Law on the Central Bank of the Russian Federation, Federal Law on Banks and Banking Activities and other federal laws and the Central Bank regulatory rules.

The Federal Law on the Central Bank of the Russian Federation establishes the legal status of the Central Bank and regulates matters such as its organization, its main tasks and functions, its relations with the bodies of state power, the system of the executive bodies of the Central Bank and their areas of competence, the Central Bank’s reporting and accounting procedures, principles for organizing cash circulation, implementation of monetary policy and its major instruments, the range of Central Bank operations, the main principles and methods of banking regulation and supervision and procedures for enforcing Central Bank regulations.

The Federal Law on Banks and Banking Activities defines credit institutions, banks, and non-bank credit institutions, as well as the banking system of the Russian Federation. It also establishes the range of banking operations that must be licensed and those that do not need to be licensed, a number of special conditions for conducting banking operations, the principles of organizing savings business and the organization of accounting and reporting by a credit organization.

Credit institutions are subdivided into banks and non-bank credit institutions, depending on the range of operations they conduct. A bank is a credit institution that has the exclusive right to conduct the following banking operations: to take on deposit funds from individuals and legal entities; to invest such funds on its own behalf and for its own account on a refundable and paid basis and for a specific term; and to open and keep individual and corporate bank accounts.

The Central Bank is legally and financially independent from the Russian government. The Central Bank consists of the Moscow Head Office with a Board of Directors, a number of regional branches in constitutive subjects of the Russian Federation (in some of the Russian republics the Central Bank’s regional branches are called National Banks) and local branches. The Governor of the Central Bank is appointed for a fixed term of four years by the State Duma (the lower chamber of the Russian Parliament) on the nomination of the Russian President and can be replaced by the same procedure.

The Central Bank conducts the state registration, maintains the state register of credit institutions, and issues licenses to credit institutions to conduct banking operations. A credit institution may be founded by a legal entity or individual not prohibited by the applicable legislation from participating in a credit institution. A corporate founder of a credit institution must be registered in accordance with the procedure established by law. To found a credit institution, a legal entity should be in operation for no less than three years; should be in a stable financial condition; and have a three-year record of meeting its obligations to the federal, regional and local budgets. The founders (members) of a credit institution must pay the authorized capital with funds that meet the Central Bank requirements.

The Central Bank considers questions pertaining to the granting of banking licenses to credit institutions and approves amendments to the founding documents of credit institutions, changes in the shareholders of credit institutions and candidates for appointment as chief executive officers and chief accountants of credit institutions.

A credit institution is subject to a mandatory annual audit in accordance with Article 42 of the Federal Law on Banks and Banking Activities. Article 43 of this Law requires a credit institution to publish its annual reports in the general press. A credit institution’s annual report is made public after an auditor has confirmed its correctness.

Generally, other institutions have only indirect influence over banks. The Federal Securities Commission issues permits for banking institutions acting as professional participants in the Russian securities market. Tax authorities supervise tax assessments.

Fiscal authorities (e.g., the Ministry of Finance) are largely inactive in relation to banks. The Association of Russian Banks, consisting of 476 banks and credit organisations (as of April 1, 2003) and established pursuant to the provisions of the Banking Law, is a self-regulatory body. It offers various technical support to its members and lobbies the interest of commercial banks in all branches of power.

The activities of foreign banks have been restricted because of concerns that they may overwhelm the nascent Russian banks. Moreover, foreign-owned banks face additional requirements in connection with obtaining a license; for example, there must be a degree of reciprocity in the specific bank’s home country and the Central Bank’s board of directors has established limits on the aggregate level of foreign capital participation within the Russian banking system.

In late 2001, the Government of the Russian Federation and the Central Bank issued a joint declaration setting out the strategy for banking reform in Russia and calling for certain legislative steps and structural changes to be taken during the next five years. Among other measures aimed at increasing the stability of the Russian banking sector, the strategy envisages (i) an increase in capital adequacy requirements, (ii) the introduction of amendments to the Russian Civil Code prohibiting the early withdrawal of funds held on deposit accounts opened for a certain term, (iii) the acceptance of International Financial Reporting Standards by all Russian banks and (iv) the gradual implementation of a mandatory system of insuring private depositors’ funds in the banks. A draft law “On Mandatory Insurance of Individuals’ Deposits” that would establish a deposit insurance scheme for retail depositors is currently being considered by the State Duma.

The following table shows major assets and liabilities as at December 31, 2002 and 2001, together with their respective interest amounts and rates earned or paid during 2002 and 2001 by Bank Zenit.

Comparative information for the year 2000 has not been presented, since we have controlled Bank Zenit only since November 2000, and inclusion of that information would not materially alter our financial results for the year 2000.

Bank Zenit is exposed to interest rate risk, principally as a result of making fixed interest rate loans and extending credit lines to corporate clients and other banks, in amounts and at maturities that differ from those of the amounts and maturities of Bank Zenit’s fixed interest rate term deposits and other borrowings. Due to changes in interest rates and maturities, Bank Zenit’s liabilities may have disproportionately high interest rates compared to the interest rates of its assets and vice versa. Interest margins on assets and liabilities having different maturities may increase as a result of changes in market interest rates, but unexpected interest rate movements may also reduce interest rate margins or result in losses. With the consent of the relevant borrower, Bank Zenit may reset fixed interest rates on the relevant loans, to reflect current market conditions. In such cases, Bank Zenit and the relevant borrower sign an addendum to the relevant credit agreement, which sets forth the new interest rate.

Bank Zenit analyzes interest rate risks by major currencies in which it executes transactions (U.S. dollar and ruble) in terms of maturity and the expected and unexpected changes in interest rates. In order to avoid interest rate risk, Bank Zenit strives to allocate funds into assets, the terms of which correspond to the terms of Bank Zenit’s liabilities.

Bank Zenit has developed a methodology for the evaluation of interest rate risk by reference to its consolidated balance sheet and the sensitivity of particular line items to interest rate changes. This methodology will aid in internal repricing of assets and liabilities in accordance with market interest rates. Currently, Bank Zenit is taking measures to implement the methodology into its existing systems. According to this methodology, Bank Zenit will estimate the amount of interest income and expenditure resulting from anticipated changes in market rates for given periods, sensitivity levels and liquidity gaps.

The tables below summarize the effective average period-end interest rates, by major currencies, for monetary financial instruments outstanding as at December 31, 2002 and 2001. The analysis has been prepared for the various instruments using period end contractual rates.

The following table sets forth the book value of trading securities as at December 31 2002, 2001 and 2000:

Corporate bonds held at December 31, 2002 consist of ruble-denominated bonds issued by large Russian companies engaged primarily in the energy, telecommunications and chemical industries and maturing from October 2003 to November 2005. The annual coupon rates on these securities range from 11.8% to 24.0%, and yields to maturity from 3.9% to 19.5%.

Promissory notes held at December 31, 2002, are ruble-denominated promissory notes of major Russian companies engaged primarily in energy and banking purchased at a discount to nominal value and maturing from January 2003 to May 2004. Average yield to maturity on these promissory notes is 15.5%.

Municipal bonds held at December 31, 2002, are ruble-denominated bonds issued by the Moscow government. Bank Zenit’s portfolio of municipal bonds matures from March 2004 to September 2005. The annual coupon rate on these bonds is 15.0%, and yield to maturity is 13.3%.

OFZ bonds held at December 31, 2002, are ruble-denominated government securities issued by the Ministry of Finance of the Russian Federation and are stated at market value. OFZ bonds are issued at a discount to face value, and have maturity from May 2003 through January 2004, and an average coupon rate of 10.0%.

Corporate Eurobonds held at December 31, 2002, are U.S. dollar-denominated and other currency denominated securities issued by Russian and Kazakh companies and banks and are freely tradable internationally. The annual coupon rates on the corporate Eurobonds vary from 10.0% to 11.5%. The corporate Eurobonds mature from June 2004 to January 2009, and the average yields to maturity vary from 7.2% to 11.0%.

VEB bonds held at December 31, 2002, are U.S. dollar-denominated securities that are commonly referred to as “MinFin bonds.” The bonds are purchased at a discount to nominal value and carry an annual coupon of 3.0%. The bonds mature from May 2008 to May 2011, and have a yield to maturity of 9.5%.

Russian Federation Eurobonds held at December 31, 2002, are U.S. dollar-denominated securities. These bonds are purchased at a discount to nominal value and carry an annual coupon of 5.0%. The bonds mature in March 2030, and have a yield to maturity of 7.2%.

Since 2001, Bank Zenit has been involved in underwriting corporate bond issues. In 2002 and the first six months of 2003, Bank Zenit acted as a lead manager or an underwriter in a number of domestic bond issuances by leading Russian companies, as well as in municipal bond issuances. In addition to Russian bond issuances, Bank Zenit participates in the underwriting of Eurobond issuances and participated in a lending syndicate for one major client. The total amount of domestic bond issuances and Eurobond issuances, in which Bank Zenit took part, exceeds RR35 billion.

All trading securities are included in the “on demand and less than one month” category, as the nature of the portfolio is that of a trading portfolio and Bank Zenit believes that this is more accurate portrayal of its liquidity position.

As at December 31, 2002 there were no holdings of securities of an individual issuer that exceeded 10% of Bank Zenit’s shareholders’ equity.

The following table summarizes the book value of available-for-sale securities as at December 31, 2002, 2001 and 2000:

Corporate shares held at December 31, 2002 include unquoted shares of Russian companies owned by Bank Zenit through other companies that hold the legal title for those shares.

As at December 31, 2002 there were no holdings of securities of an individual issuer that exceeded 10% of Bank Zenit’s shareholders’ equity.

Our loans and advances to customers as at December 31, 2002, 2001 and 2000 are as follows:

Economic sector risk concentrations within the customer loan portfolio as at December 31, 2002, 2001 and 2000 are summarized in the table below:

As at December 31, 2002 our banking operations had seven borrowers with aggregated loan amounts above RR300 million. The aggregate amount of these loans was RR2,573 million or 21% of the loan portfolio.

The following table summarizes loans and advances to customers at December 31, 2002, by maturity:

The majority of loans and advances to customers have been issued to customers located in Russia, except for RR45 million of loans issued to foreign borrowers.

Provisioning policy. Within our banking operations, loan officers regularly review the quality of loans for which they are responsible. Specific provisions are made against loans when, as a result of a detailed appraisal of the loan portfolio, it is considered that full recovery is doubtful, which depends in each case on the individual circumstances of the loan, including, among other things, the adequacy of any collateral securing the loan. Provisions made during a year (less amounts released and recoveries of amounts charged-off in previous years) are charged against income. In addition to individual loan underwriting criteria management of Bank Zenit has enforced portfolio exposure limits for each class of borrower, geographical area within the Russia and the composition of loan amounts in the portfolio.

In addition, collective impairment provisions are maintained at levels considered appropriate by management to cover losses from loans, which have not been separately identified but are known from experience to be present in any portfolio of bank loans. Reviews of the level of collective impairment provisions are conducted throughout the year. A factor in establishing the level of collective impairment provisions is the scope and detail of the specific provisioning procedures in place at the time of the review, historical patterns of losses in each component and the current economic environment in which the borrowers operate.

Interest receivable on doubtful loans is brought into the consolidated income statement as it accrues only so long as its collectibility is not subject to significant doubt.

When a loan is uncollectable, it is written off against the related provision for loan impairment. Such loans are written off after all the necessary legal procedures have been completed and the amount of the loss has been determined. Recoveries of amounts previously written off are treated as other income.

Movements in loan impairment provisions. The following table shows movements in loan impairment provisions for each of the three years ended December 31, 2002:

In addition, a further RR4 million (2001: RR19 million, 2000: RR16 million) of loan impairment provisions is held in respect of amounts due from banks.

Summary of loan impairment provisions by economic sector. The following table summarizes loan impairment provisions on loans to customers by economic sector as at December 31, 2002, 2001 and 2000.

The main sources of Bank Zenit’s funding are deposits from corporate clients and other banks, promissory notes and other debt securities issued by Bank Zenit and inter-bank borrowings.

The following table summarizes customer deposit accounts as at December 31, 2002, 2001 and 2000.

The following table summarizes borrowed funds by type as at December 31, 2002, 2001 and 2000.

In 2001, Bank Zenit entered into a term loan facility of RR694 million (US$20 million nominal amount) in the form of a syndicated loan provided by a consortium of foreign banks. The contractual maturity of the syndicated loan was June 7, 2002, and the annual interest rate was 6.03%. The loan was collateralised by Tatneft Finance PLC Eurobonds held in trust on behalf of a non-resident third party. In June 2002, the syndicated loan was fully repaid.

Bank Zenit engages in derivative financial transactions, including forward contracts involving foreign currencies, securities and precious metals. Foreign exchange and other derivative financial instruments are generally traded in an over-the-counter market with professional market counterparties on standardized contractual terms and conditions.

The table below includes contracts with a maturity date subsequent to December 31, 2002. These contracts were entered into in December 2002 and are short term in nature, except for contracts with precious metals, which have a longer-term nature.

The unrealized gain/loss in the table above reflects the fair value adjustment of outstanding derivatives as at December 31, 2002.

We currently hold substantially all of the licenses for oil exploration and production within Tatarstan. We consider all other major Russian oil companies, including in particular YUKOS, LUKOIL, Surgutneftegas, Sibneft and Tyumen Oil Company (TNK), to be our principal competitors in our core business segments. We compete with these and other oil companies for customers both within Russia and internationally, primarily for sales of crude oil.

We believe that our drilling costs are less than those for oil companies operating in Siberia. Our oil reserves are generally closer to the surface than in Siberia, and are located in more geographically accessible terrain. While the main productive horizons in Siberia are found at a depth of approximately 2,300 to 2,400 meters, our main productive horizons lie at a depth of approximately 1,200 to 1,700 meters. We also believe our location gives us a transportation cost advantage over companies operating in Siberia, as we are located closer to major markets in Moscow and eastern and western Europe.

We expect to experience increasing levels of competition in the industry. A number of other Russian oil companies, as well as foreign oil companies, compete on bids for licenses and offer services in Russia, increasing the competition that we face. Foreign-owned companies in particular may have access to greater financial and other resources than we do, which may give them a competitive advantage. We also expect to experience increasing competition due to the limited quantities of unexploited and unallocated oil reserves remaining in Russia, and the effects of, and financial resources provided by, increased foreign investment into the Russian oil industry. Full implementation of the PSA Law could substantially increase levels of interest of foreign and domestic companies in oil production in Russia and further increase the level of competition we face even within Tatarstan. Our domestic competitors may also be strengthened through strategic acquisitions of additional assets, such as by mergers or other forms of combination. For example, in 2002 and the first half of 2003 the Russian oil industry has experienced substantial consolidation, including the privatization sale of Slavneft, a large vertically-integrated oil company, to the shareholders of TNK and Sibneft, Russia’s third and fifth largest oil companies, respectively; the announcement of the formation of a joint venture between TNK and BP that would combine the assets of TNK, Sidanko and Onako oil companies with the Russian assets of BP; and the announcement of a merger between YUKOS and Sibneft that would result in the creation of the largest Russian and one of the largest international oil companies by annual production. These competitors may have better access to financial and other resources and greater political influence than we do.

In the petrochemicals sector we compete for the Russian and CIS tire markets primarily with other Russian tire manufacturers, such as the Yaroslavl, Omsk, Moscow, Kirov, Krasnoyarsk, Voronezh and Volzhsky tire companies, as well as Ukrainian tire manufacturers. The Omsk and Yaroslavl tire companies are controlled by Sibur, a petrochemicals subsidiary of Gazprom, Russia’s natural gas production and transportation monopoly. The Kirov, Krasnoyarsk and Voronezh tire companies are controlled by Amtel, a Russian petrochemicals holding company. Several of our competitors have entered into joint ventures with major international tire manufacturers, and several international tire manufacturers, including Goodyear, Michelin, Continental, Pirelli and Nokian Tires, have announced plans or taken steps to enter the Russian market. We expect to experience increasing levels of competition in the petrochemicals segment in the coming years.

The Russian market for financial and banking services is also highly competitive. Although the Russian banking industry is dominated by a few Moscow-based banks, according to the Central Bank of Russia, 1,773 banks were licensed to conduct banking transactions in Russia as of January 1, 2003. Due to the large number of banks in Russia and the varying focuses of many of those banks, our primary banking subsidiary, Bank Zenit, faces competition from different banks in each of the business sectors and various regions of Russia in which it operates. In the corporate banking sector, Bank Zenit’s primary competitors are OAO Alfa Bank (“Alfa Bank”), MDM Bank (“MDM Bank”) and OAO Uralsib Bank. In the investment banking sector, Bank Zenit’s primary competitors are Alfa Bank, MDM Bank and Investment Bank “Trust.” In the private banking sector, Bank Zenit’s primary competitors are Financial Corporation NIKoil, Rosbank, Alfa Bank, ING Bank (Eurasia) ZAO and Raiffeisen Bank Austria LLC. Currently, we do not view Bank Zenit as having a competitive position in the Russian retail banking sector. Our banking subsidiaries expect to face increased competition as a result of recent and proposed Russian banking reforms and with the

continued entry of experienced international banks into the Russian market. In addition, many of our banking competitors possess greater resources, both in terms of assets and business volume, and have better access to funding, making them less vulnerable to economic downturns.

We are currently subject to environmental legislation enacted by both Russia and Tatarstan. Although Russian legislation provides a basis for requiring polluters to clean up environmental pollution, to date there have been few attempts to enforce these requirements. Instead, environmental authorities have imposed relatively low fines for breaches of environmental and sanitation standards in what is effectively a “pay-to-pollute” scheme. We actively pursue policies, however, that are designed to reduce pollution and its effects, particularly with respect to water, soil and air.

All four of the major rivers located near our operations previously tested positive for chlorides (chemicals derived from the oil production process) in excess of safe levels. Levels of chloride contamination in local rivers peaked in 1986, have recently dropped below the maximum allowable concentrations, and continue to decrease. We now recycle by-product water from our extraction operations following purification at oil/water purification facilities.

We have responded to problems of pipeline corrosion by implementing a technology, which we have developed, for coating pipes on the inside with corrosion-resistant material (polyethylene). Our waste water carrying pipelines have now been completely replaced with such polyethylene-coated pipes and we continue to replace our oil-gathering networks. Along with other corrosion control methods, we have successfully used corrosion inhibitors. Where the use of such piping is technically impossible, we use pipes with an internal polymer coating. We have also arranged to use “smart-pig” technology for early detection of pipeline corrosion. Our pipeline safety program has successfully reduced the numbers of pipeline leaks and resulting soil pollution.

To protect underground drinking water sources we have engaged in a well rehabilitation program involving liquidation of old wells, drilling of stand-by wells, construction of more environmentally safe wells and hydroisolation of storage pits during well drilling and repair work.

We are committed to engaging in soil remediation as is required. One of our joint ventures, Tatoilgas, also successfully recovers oil from sludge that is stored in sludge ponds.

Through our joint venture TATEX we have been installing vapor recovery equipment on our oil storage tanks. In 2002, one additional vapor recovery system became operational and now virtually all of our storage tanks have such equipment. This program has helped to reduce substantially emissions of hydrocarbons from our facilities. We have reduced sulfur dioxide emissions by installing modular compressors.

Following the dissolution of the Soviet Union and due to the subsequent disruption of relations with the oil industry equipment manufacturers located within the CIS, most of which were located outside Russia, our predecessor production associations created internal service enterprises such as the Central Production Service Department, the Electric Equipment Service Department and the Subsoil and Wells Repair Service Department. At the same time, in response to disruptions in other sectors of the economy, they increased the number of non-core activities, such as production and processing of agricultural products.

In order to reduce our operating costs and to improve our focus on our core business of exploration and production, we are currently implementing a program of corporate reorganization initially approved by our Board of Directors in 1996. The key tasks of the reorganization program were:

The first stage of the corporate reorganization program concentrated on transferring certain support services that had been provided within each NGDU or by other departments into newly formed subsidiaries expected to provide services on an independent and competitive basis and on divesting social assets and responsibilities by gradually transferring these to local authorities.

We have now completed the first stage of the reorganization by separating out more than 40 former departments engaged in oil production services and transferring a number of social assets to local authorities. We have now initiated the second stage of our reorganization, in which we are seeking to transform our company into a vertically integrated holding company and improve management efficiencies. To this end, we are acquiring and increasing our interests in petrochemical and oil-refining enterprises, such as Nizhnekamskshina, Nizhnekamsk Oil Refinery, Yarpolymermash-Tatneft and Nizhnekamsk Industrial Carbon Plant, enterprises that sell crude oil and oil products or provide oil services, such as Tatneft-Europe, and enterprises that provide financial services, such as Bank Zenit.

In order to improve our vertically integrated structure, in 2002 we created Tatneft-Neftekhim, a management company for our petrochemicals operations, and transferred to it our holdings in Nizhnekamskshina, Nizhnekamsk Industrial Carbon Plant, Yarpolymermash-Tatneft and other petrochemicals companies. We also proceeded with a merger of our natural gas and natural gas products collection, refining and transportation assets into the Tatneftegaspererabotka division, established a drilling management company OOO Tatneft-Bureniye, and continued with our internal restructuring in order to optimize costs and corporate governance. As part of our internal restructuring, we took additional steps in 2002 to streamline management and improve efficiency by centralizing and restructuring our logistics services and reducing the number of employees engaged in general construction, machine tool, special-purpose machinery and related services. In the first half of 2003, we divested our stakes in 21 agricultural companies.

We are now reviewing a plan of further restructuring our company for the next three years that has been prepared by a team of our specialists. We intend to develop the crude oil production services market by separating out some of our small service units into economically independent operations in an effort to reduce our costs. In so doing, we intend to take advantage of the tax benefits available to small businesses. At this stage, we will continue with our program of divesting non-core assets.

We do not plan to retain a controlling interest in all the newly created service companies and, where we do retain a controlling interest, we expect to transfer minority interests in these companies either to the management and workers of each company or to outside investors. We do not expect to realize significant proceeds from these sales. We also plan to retain legal title to certain of the property to be used by the new service companies and to lease it to these companies. The service companies are expected to compete to provide services to Tatneft, and to market their services to other exploration and production companies. We do not intend to retain control of the road construction companies, or maintenance companies, and these entities may become independent of our group. The road construction, maintenance and agricultural companies have already been registered as limited liability companies.

We do not expect that any significant financial charges will arise as a result of such reorganization.

We currently own certain social assets, including sports and leisure facilities. We manage other social assets, such as housing and kindergartens, which are the property of Tatarstan but have been provided to us under the principle of “economic management” pursuant to agreements with the Tatarstan government. At December 31, 2002 and 2001, we held social assets with a net book value of RR5,833 million and RR5,831 million, respectively. We transferred social assets with a combined net book value of RR1,293 million, RR593 million and RR128 million in the years ended December 31, 2002, 2001 and 2000 respectively, to public ownership.

We have also developed a long-term home construction program, which is aimed at reducing housing shortages in the region through 2005. One of the most important aspects of the program is the provision of non-interest bearing loans to employees for home and apartment purchases. In 2002, we issued RR54.2 million in housing loans, which enabled more than 5% of our employees who qualified as in need of improved housing to acquire new homes. We also financed the construction of 39,500 square meters of housing for our employees.

As of May 12, 2003, the Tatarstan MLPR held approximately 30.44% of our capital stock and 32.51% of our Ordinary Shares, either directly or indirectly. Tatarstan also holds the Golden Share, which, if conditions for exercising the powers attaching to it are satisfied, would give it the power to appoint a representative to our Board of Directors and revision committee and veto certain corporate decisions. Currently, this right is not exercisable because Tatarstan holds more than 25% of our shares. The Golden Share currently has an indefinite term. For a description of the Golden Share rights see “Item 7—Major Shareholders and Related Parties—Major Shareholders” and “Item 3—Risk Factors—Risk Relating to Tatarstan—Tatarstan legislation may be inconsistent with Russian legislation, and resolution of these inconsistencies is uncertain.” Through its participation in Tatneft, its legislative, taxation and regulatory powers, and also through significant informal pressures, the Tatarstan government is able to exercise

considerable influence over us. The Tatarstan government has used its influence in the past to mandate oil sales (see “Item 3—Key Information—Risk Factors—Risks Relating to the Company”) and to cause us to raise capital for the benefit of Tatarstan or to pay the debts of Tatarstan when independently we may not have entered into such transactions. See “Item 3—Key Information—Risk Factors—Risks Relating to Tatarstan.”

Tatarstan continues to own controlling or substantial minority stakes in virtually all of the major enterprises in Tatarstan. The specific nature of Tatarstan’s interest in each enterprise cannot be determined, however, and therefore detailed information is not available to us about the extent of Tatarstan’s involvement in certain transactions into which we may enter. Nonetheless, we are aware that, as a result of Tatarstan’s involvement in other enterprises, Tatarstan has an interest in a number of transactions involving us, including the following:

In the mid-1990s, we informally agreed with the Tatarstan government that we would use up to 50% of our export receivables to secure loans for the benefit of the Tatarstan government. See “Item 3—Key Information—Risk Factors—Risks Relating to Tatarstan.” Tatarstan received several such loans in 1997 and in 1998. In general, we received funds under these loans and then on-loaned them to the Tatarstan government (and in certain cases retained a portion of the funds with respect of amounts then owed to us by the Tatarstan government). These on-loans were to be repaid directly by the Tatarstan government, or indirectly through a reduction in our obligations to Tatarstan. Our own loans obtained in order to make these on-loans to Tatarstan were restructured through the Restructuring Agreement we and our creditors entered into on October 31, 2000 (and we repaid all amounts under the Restructuring Agreement in 2002). The Tatarstan government reduced its outstanding obligation to us under these on-loans by transferring controlling interests in a local telecommunications company, Tatincom-T, and a geophysical services company, Tatneftegeofizika, in 1999 and discharged RR73 million and RR4,368 million in 2000 and 1999, respectively, through relief of tax liabilities and cash and cash equivalent payments. In 2001, the Tatarstan government settled the remaining balance of the loan through tax liability relief and transfer of shares in companies in Tatarstan, such as Bank Ak Bars and OAO Kamaz.

In the past we have also guaranteed the obligations of other Tatarstan entities in which the Tatarstan government had an interest. In 1998, we entered into a guarantee agreement for a US$50 million loan made by Société Générale to TAIF, which is partly owned by the Tatarstan government. Under the terms of the guarantee, we agreed to meet all of TAIF’s obligations under the loan agreement. As a result of TAIF’s failure to repay the loan in full, we became liable for paying US$19 million to Société Générale. This obligation was restructured under the terms of the Restructuring Agreement (which we repaid in 2002).

Through 2000, Tatarstan had a special tax regime in relation to our operations. This tax regime provided significant tax savings for us. We did not enjoy any significant tax benefits from Tatarstan in 2001 or 2002.

Resolution of the Cabinet of Ministers of Tatarstan No. 462 reduced tariffs for power resources used by us by 27% beginning in the third quarter of 1998 and continuing through the final quarter of 1999. We have not received any similar benefits since 1999.

The President of Tatarstan has publicly encouraged us to construct an oil refinery in Tatarstan, and we have made substantial investments in new refining facilities at the Nizhnekamsk oil refinery. The Tatarstan government has also actively encouraged us to create a vertically integrated oil company in Tatarstan. See “—Business Overview—Strategy” under this Item.

The Tatarstan government ensures that we maintain a continuous supply of both crude oil and oil products to Nizhnekamskneftekhim. Prior to March 1999, we supplied crude oil to Nizhnekamskneftekhim via intermediaries. Since March 1999, we have shipped the principal refined products to Nizhnekamskneftekhim and various by-products to other customers. We also actively purchased crude oil and oil products from various refineries in the Russian Federation and used our marketing capabilities in the Tatarstan region to sell the products.

Substantially all of our material tangible fixed assets, consisting of interests in crude oil and natural gas reserves, refining facilities, gas stations, storage, manufacturing and transportation facilities and other property, is located in Tatarstan. For a description of our reserves, sources of crude oil, refining facilities, gas station operations and other facilities see “—Exploration and Production,” “—Refining and Marketing” and “—Petrochemicals” under this Item. In 1999, we started acquiring gas stations outside of Tatarstan, in particular in Moscow, the Moscow region, Vladimir, the Volga and Urals regions, the Leningrad region and Nizhny Novgorod. In 2002, in a series of transactions we purchased 16,767 hectares of land underneath most of our properties located in Tatarstan from the Tatarstan government for RR330 million.

The following discussion of our financial condition and results of operations is based on and should be read in conjunction with our audited consolidated financial statements as at December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002, 2001 and 2000. In each case, these statements should also be read together with the accompanying notes and supplemental information appearing elsewhere in this annual report. These financial statements have been prepared in accordance with U.S. GAAP. All ruble amounts are expressed in constant rubles of December 31, 2002 purchasing power, except as indicated otherwise.

Our financial results have been affected significantly by several factors attributable to the special characteristics of the Russian economy in recent years. These factors include the consequences of the Russian financial crisis of 1998; the real change in the purchasing power of the ruble relative to the U.S. dollar; a number of factors affecting sales; the high and varying incidence of taxes other than income taxes, and current income taxes, on our operations; and fluctuations in deferred tax credits and charges. Each of these factors is discussed in more detail below.

Though the situation has significantly improved from the acute distress experienced in the wake of decisions taken by the Russian government and the Central Bank in August 1998, the economy of the Russian Federation continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible outside of the country, extensive currency controls, a relatively low level of liquidity in the public and private debt and equity markets, and inflation higher than that of more developed market economics.

The prospects for future stability in the Russian Federation are largely dependent upon the continued effectiveness of economic measures undertaken by the government, together with legal, regulatory, and political developments.

Impact of the Real Change in Purchasing Power of the Ruble against the U.S. dollar

Impact on Operating Margins. A significant portion of our revenues is either denominated in U.S. dollars or correlated to some extent with U.S. dollar crude oil prices, while most of our costs (other than debt service costs) are denominated in rubles. Our results of operations are therefore significantly affected by the relative movements of ruble inflation and exchange rates. In particular, our operating margins are generally adversely affected by a real appreciation of the ruble against the U.S. dollar (i.e., by an inflation rate that is higher than the rate at which the ruble is devaluing against the U.S. dollar) because this will generally cause our costs to increase in real terms relative to our revenues. Conversely, our operating margins are generally positively affected by a real depreciation of the ruble against the U.S. dollar because this will generally cause our costs to decrease in real terms relative to our revenues.

The following table sets forth the rates of inflation in Russia, the rates of nominal devaluation of the ruble against the U.S. dollar and the rates of real change in the value of the ruble against the U.S. dollar for the periods shown.

Period to period comparisons of our sales revenues, as restated in constant rubles, have been significantly affected by the real change in the value of the ruble against the U.S. dollar, the currency in which our export sales are denominated. If U.S. dollar sales revenues for any periods being compared are the same, but between the periods the rate of devaluation of the ruble has been slower than the rate of Russian inflation (i.e., the ruble has appreciated in real terms), the related revenues expressed in constant rubles will decline from one period to the next. Conversely, if the rate of devaluation has exceeded the rate of inflation, such revenues expressed in constant rubles will increase from one period to the next.

The following table illustrates the effects of both exchange variations and the indexation of historical amounts to adjust for Russian inflation on a fixed amount of U.S. dollar revenues from sales denominated in U.S. dollars.

The impact of the real change of the ruble on our revenues was affected in each period by changes in the U.S. dollar prices of our export sales. The following table illustrates this effect by showing how a fixed volume of non-CIS exports would be reflected in our consolidated statements of operations for the period in which the relevant sale is made, assuming that the U.S. dollar price per ton in the relevant sale was the U.S. dollar Platt’s price per barrel on the date of sale.

Impact of Monetary Effects. Our results of operations have also been substantially affected by the impact of devaluation and inflation on the value of our monetary assets and liabilities. Devaluation of the ruble has generally resulted in foreign exchange gains on monetary assets denominated in foreign currencies and foreign exchange losses on monetary liabilities denominated in foreign currencies. These gains and losses are recorded on a net basis on our statements of operations under the caption “Exchange loss (gain).” Inflation has resulted in purchasing-power gains on monetary liabilities and purchasing-power losses on monetary assets; because our financial statements are price-level restated, these gains and losses are recorded on a net basis on our statements of operations under the caption “Monetary gain.”

The following table sets forth our net foreign exchange loss, net monetary gain or loss and net interest expense realized for the periods shown.

The impact of net foreign exchange losses and net monetary gains on our financial results has been significant in prior periods as is demonstrated the table below:

Several factors attributable to special characteristics of the Russian economy have affected our sales in recent years. These factors include:

In addition, world crude oil market prices have fluctuated significantly since the fourth quarter of 1997, falling below US$10 per barrel by February 1999. Starting from 1999, oil prices increased and stabilized at significantly higher levels. The average prices of Brent crude, an international benchmark oil price, for the three years ended December 31, 2002, 2001 and 2000, were approximately US$24.98, US$24.46 and US$28.50 per barrel, respectively. In 2002, world oil prices increased significantly, by 35% from January to December. Refined products prices have also fluctuated significantly and generally followed the trends of crude oil prices in 2002. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company” and “Item 3—Key Information—Risk Factors—Risks Relating to the Oil Industry.”

Export Sales. Prices for our non-CIS export sales exceed prices for our domestic sales by a considerable margin. Prices for our CIS export sales also exceed prices for our domestic sales, but by substantially smaller margins. Domestic Russian crude oil prices remain well below world levels primarily due to large regional surpluses in Russia (as a result of the transportation constraints on exports discussed below).

Accordingly, we seek to maximize exports of crude oil to non-CIS countries. However, we depend on the state-controlled network of crude oil trunk pipelines operated by Transneft for transportation, including export, of substantially all of our crude oil. Access to Transneft’s pipeline network is regulated by Russian government authorities. From September 11, 2001, export pipeline capacity and sea terminal access are allocated among oil producers and their parent companies on a quarterly basis in proportion to the volumes of oil produced and delivered to the Transneft pipeline system, and not in proportion to oil production levels, as in the past. Limitations on access to the pipeline network constrain the ability of producers to export crude oil, as do limited port, shipping and railway facilities.

In addition to these constraints, the Russian government has in the past limited the ability of Russian producers to export crude oil. Export quotas imposed at the beginning of 1995 permitted producers to export crude oil in excess of their quotas only on the condition that they paid the excess of the export price over the domestic price for those sales to the Russian government. Export quotas were terminated in 1995, replaced by a program under which the Russian government reserved for itself a significant portion of export pipeline capacity for sales of crude oil purchased from certain Russian producers. This program was then abolished in July 1997, and President Yeltsin ordered the pipeline capacity that had been reserved for this program to be distributed among oil producers on the basis of production on the condition that they satisfy their tax obligations to the federal government with any resulting export proceeds. Under allocations made pursuant to the decree implementing this order, we were allocated an additional 1.26 million tons of export capacity per year through the end of 2002. In 2000 we received an additional export quota of 0.86 million tons in return for contributions to Tatarstan of social assets, and 0.4 million tons were allocated to improve our financial position.

We are required to pay taxes owed to the Russian government in order to maintain our access to export pipelines and seaports. Under Resolution No. 1446 of December 31, 1994 and Resolution No.417 of May 4, 1998, Russian oil companies only have access to export pipelines and sea terminals if they are current in their tax payments. In addition, Article 4 of Resolution No. 589 of June 2, 1999, “On Settlement of the Tax Indebtedness of Oil-Producing and Oil-Refining Enterprises and Measures to Secure Full Tax Payments to the Federal Budget,” as amended on January 6, 2000 (“Resolution 589”), stipulates that oil companies should conclude agreements with the Ministry of Taxes and Duties (“Tax Agreements”) which provide for (i) the payment of all their accumulated tax delinquencies by the end of each calendar year; and (ii) an increasing cash component in tax payments until November 2000, from which date 100% of tax payments must be made in cash. An oil company that fails to make the required cash payments is to lose its access to the oil export pipelines. We signed a Tax Agreement with the Ministry of Taxes and Duties on June 6, 1999; it was subsequently extended to cover 2000. Even though the Tax Agreement was not officially extended to cover periods subsequent to December 31, 2000, we complied with all of its requirements in 2001 and 2002. As a matter of policy, we make tax payments slightly in advance of when they are due in order to ensure that we do not lose access to the oil export pipelines. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company.”

Government-Directed Deliveries. The Russian and Tatarstan governments can mandate, and have in the past mandated, deliveries of crude oil and oil products by us, directly or through informal pressure. Government directed deliveries take precedence over market sales, and may be, and in the past have been, compensated at less than market prices.

Since the 1970s, the Tatarstan government has continuously directed us (or our predecessors) to deliver crude oil or oil products to the Nizhnekamskneftekhim refinery. The deliveries were approximately 1.0, 1.2 and 5.5 million tons in 2002, 2001 and 2000, respectively. Prior to March 1999, these government-directed deliveries included sales of crude oil to the refinery, directly or via intermediaries, and tolling arrangements involving us, the refinery and, in some cases, a related third party, TAIF. Since March 1999, we have leased a refining unit currently owned by TAIF, operated the unit, and sold the principal refined products to Nizhnekamskneftekhim. The Tatarstan government fixed the price payable by Nizhnekamskneftekhim to us for crude oil and refined products at a level below the domestic market price throughout 2001 and 2000. We expect Tatarstan government-directed deliveries to Nizhnekamskneftekhim, either directly or through intermediaries, to continue for the next several years. The Tatarstan government may continue to set prices at below market rates, and we may be directed to deliver even greater quantities of oil products to Nizhnekamskneftekhim.

Barter Transactions. Prior to 2000, as a result of the liquidity crisis affecting much of the Russian economy, barter comprised a significant proportion of our domestic sales. During this period, we generally acquired a substantial portion of our equipment by barter, including pipes, vehicles, machinery and spare parts. In 2002, the proportion of total sales and other operating revenues represented by barter decreased to 4% from 6% in 2001 and 11% in 2000. Barter transactions also accounted for 16%, 17% and 40% of total additions to property, plant and equipment in the years ended December 31, 2002, 2001 and 2000, respectively. Barter transactions involving the purchase of property, plant and equipment are excluded from our statement of cash flows. See “—Liquidity and Capital Resources—Cash Flows” under this Item. Barter transactions may significantly impair our ability to generate cash, and barter transactions are inherently more time-consuming and less efficient than cash transactions. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company.”

Barter transactions are settled either in the form of direct delivery of goods and services to the other party involved, or through a chain of non-cash transactions involving several parties. In these latter indirect cases, goods delivered in kind may be offset as part of a series of inter-linked transactions with different parties. Barter transactions are normally initiated by the other parties making offers of materials, pipes and equipment at competitive prices, and not by us. Most of the goods and services that we receive in barter transactions are commodities for which there are either publicly available market prices or for which we have price lists from potential suppliers. Generally, we receive goods and services in kind that we believe have a value at least equal to the domestic market price of the bartered crude oil and oil products we supply in exchange, and, in many cases, such transactions are more favorable to us than a similar cash transaction would have been. In some cases, however, the insolvency of the counterparty may necessitate barter arrangements at rates that result effectively in the settlement of an otherwise uncollectable debt for less than the value of the debt.

The majority of barter transactions represent transactions which have been settled through a chain of non-cash transactions involving several companies rather than transactions pursuant to standing barter arrangements or transactions originally intended to be settled through a contractual barter agreement.

Barter transactions are included in the financial statements primarily on the basis of the value of the goods sold. The significant decline in barter sales between 2000 and 2002 was due to increased liquidity in the economy as a result of improved performance by the government of its payment obligations to commercial enterprises (itself made possible by improved tax collection); the rise in profits of Russian commercial enterprises in ruble terms due to the devaluation of the ruble following the events of August 17, 1998; the decline in attractive alternative uses of free funds resulting from the contraction of the GKO/OFZ market; and a decrease in interest rates on bank term deposits.

We realize no special material gains or losses on barter transactions, since substantially all of our barter transactions take place at fair value. Crude oil, the primary form of consideration given, has an established market value and, as discussed above, most goods and services that we receive in barter transactions are commodities for which prices can be readily determined.

Blending of High Sulfur Content Crude Oil. We benefit from the practice of blending high sulfur content crude oil with low sulfur content crude oil in the Transneft pipeline system, which currently transports approximately 60% of our high sulfur content crude oil. The resulting blended crude oil sells for a uniform price that is higher than the price that high sulfur crude oil would command in the market. Although Transneft charges a $3.00 per ton premium for blending and transporting the high sulfur crude oil, we generally receive a higher price for our blended crude oil than we would if either (i) the high sulfur content crude oil were transported and sold separately or (ii) Transneft charged a premium for transporting high sulfur content crude oil that more closely matched the differential in world market prices between high sulfur content crude oil and the blended crude oil that Transneft currently carries. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company.”

We are subject to numerous taxes that have had a significant effect on the results of operations. Russian tax legislation is and has been subject to varying interpretations and frequent changes.

Through December 31, 2000, our Russian companies were subject to income tax at a maximum statutory rate of 30%. In August 2000, the Federal Law on Income Tax for Companies was amended, raising the maximum statutory income tax rate to 35% in most jurisdictions effective January 1, 2001.

In August 2001, the Russian Tax Code was amended again. As a result of this amendment, which became effective on January 1, 2002, two new chapters of the Russian Tax Code were introduced that have affected our results of operations. Under the first of these chapters, the maximum income tax rate for income received from ordinary activities was reduced from 35% to 24%, the tax rate for dividends received from domestic companies was reduced from 15% to 6% and the tax rate for dividends received from foreign companies was reduced from 35% to 15%. However, investment tax credits that could be used to reduce income tax by up to 50%, have been abolished. Under the second chapter, a unified natural resources production tax was introduced. This unified natural resources production tax replaced the mineral restoration tax, royalty tax and excise tax on crude oil.

These taxes have had a significant effect on our results of operations, and represented 22%, 21% and 19% of total sales and other operating revenues in the years ended December 31, 2002, 2001 and 2000, respectively. These taxes also represented 25% of total costs and other deductions in the each year ended December 31, 2002, 2001 and 2000.

These taxes are reflected in taxes other than income taxes in our consolidated statements of operations. In addition, we are the is subject to payroll-based taxes, which are included as salary costs within selling, general and administrative expenses or operating expenses, as appropriate.

The table below presents a summary of statutory tax rates to which we and most of our subsidiaries were subject during the years ended December 31, 2002, 2001 and 2000:

Prior to January 1, 2002, Tatneft was subject to mineral restoration and royalty taxes at the average effective rates of approximately 6% and 8%, respectively, of oil and gas revenues recognized under Russian accounting regulations by production subsidiaries and excise taxes on crude oil production of approximately US$0.30 per barrel at the December 31, 2001 exchange rate. Under the second chapter of the Russian Tax Code, the mineral restoration tax, royalty tax and excise tax on crude oil production were abolished and replaced by the unified natural resources production tax. For the year ended December 31, 2002, the unified natural resources production tax expense was RR16,940 million. Total mineral restoration tax, royalty tax and excise tax on crude oil for the year ended December 31, 2001 were RR11,908 million. Through December 31, 2004, the base rate for the unified natural resources production tax is set at RR340 per ton of crude oil produced and is to be adjusted depending on the market price of Urals blend and the Ruble exchange rate. The tax becomes zero if the Urals blend price falls to or below US$8.00 per barrel. For the year ended December 31, 2002, the average rate for the unified natural resources production tax, based on the Urals blend market price and ruble exchange rates, was RR668 per ton of crude oil produced. At December 31, 2002, the effective statutory rate for the unified natural resources production tax was RR753 per ton. From January 1, 2005, the unified natural resources production tax rate is set by law at 16.5% of crude oil revenues recognized by the exploration and production companies based on Russian accounting regulations.

On June 21, 2003, the State Duma, the lower house of Russia’s parliament, passed a bill increasing the rate of the unified natural resources production tax to RR357 per ton of crude oil produced starting from January 1, 2004. The Federation Council passed this bill on June 25, 2003. For the increase to become effective, the President must also approve it.

Maximum rates of export duties for crude oil were established by Russian Federal Law No.126-FZ dated August 8, 2001, and have been effective since February 1, 2002. The maximum rates depend on a lagged average of Urals blend prices. The rates start at zero when the lagged Urals blend price is at or below US$15.00 per barrel. They then increase by US$0.35 per barrel for each US$1.00 increase in the lagged Urals blend price when the lagged Urals blend price is between US$15.00 and US$25.00 per barrel, and by US$0.40 per barrel for each US$1.00 increase in the lagged Urals blend price when the lagged Urals blend price is above US$25.00 per barrel.

Effective from January 1, 2003, export duties on refined products are limited to 90% of the export duties on crude oil.

We are also subject to value added tax, or VAT, of 20% on most purchases. VAT paid is recoverable against VAT received on domestic sales. Export sales, other than to some CIS countries, are not subject to VAT. Input VAT related to export sales is recoverable from the Russian government. Our results of operations exclude the impact of VAT. On June 21, 2003, the State Duma passed a bill that would reduce the VAT rate to 18% starting from January 1, 2004. The Federation Council approved the bill on June 25, 2003 but it remains subject to approval by the President.

Current income taxes have also had a significant effect on our financial results, representing 24%, 28% and 21% of income before income taxes and minority interest in the years ended December 31, 2002, 2001 and 2000, respectively.

In the context of the significant regulatory changes related to Russia’s transition from a centrally planned to a market economy over the past ten years and the general instability of the new market institutions introduced in connection with this transition, taxes, tax rates and implementation of taxation in Russia have experienced numerous changes. Although there are signs of improved political stability in Russia, further changes to the tax system may be introduced which may adversely affect our financial performance. In addition, uncertainty related to Russian tax laws exposes us to the possibility of enforcement measures and the risk of significant fines and could result in a greater than expected tax burden.

For more information on the current system of oil-related taxation see “Appendix B—Overview of the Russian Oil Industry—Current System of Oil-Related Taxes and Payments.” See also “Item 3—Key Information—Risk Factors—Risks Relating to the Company—The Russian tax system imposes substantial burdens on us and is subject to frequent change and significant uncertainty.”

In Russia, significant differences have existed between the CPI, which for countries considered to be hyperinflationary is used to restate the book value of property, plant and equipment for financial reporting purposes in accordance with U.S. GAAP (the “financial reporting basis”), and the indices used under applicable Russian statutes to revalue those assets for tax purposes (the “tax basis”). Net deferred tax liability recorded in the consolidated balance sheets as at December 31, 2002, 2001 and 2000 was RR19,830 million, RR21,616 million and RR29,818 million, respectively. Increases or decreases in the deferred tax asset or

liability are credited or charged to income in each reporting period. Accordingly, we recorded deferred tax charges (benefits) in the years ended December 31, 2002, 2001 and 2000 of RR(1,488) million, RR(8,205) million and RR8,895 million, respectively.

In relation to statutory tax revaluations of property plant and equipment effective on or after January 1, 1997, we have the option to use appraisals by independent qualified experts instead of the indices developed by the Russian government. We made use of independent appraisals in the statutory tax revaluations as of January 1, 1998 and January 1, 2002. The impact on deferred tax charges and credits in future periods will depend in large part on whether statutory tax revaluations increase or reduce the tax basis of our fixed assets in relation to their financial reporting basis, as well as the extent to which inflation requires the restatement of such fixed assets for the purpose of determining their financial reporting basis. The revaluation of the fixed assets as of January 1, 2002 increased our tax basis in fixed assets by approximately RR11,893 million.

For further information regarding volumes, contract prices and net prices to Tatneft for non-CIS exports, CIS exports and domestic sales of crude oil see Attachment 3 to the Reserves Report (which provides information for the month of December 2002), and for a further analysis of estimated expenses see Attachment 5 to the Reserves Report. Our banking operations are discussed under “Item 4—Information on the Company—Banking Operations.”

A breakdown of sales and other operating revenues is provided in the following table:

Sales and other operating revenues totaled RR145,483 million for the year ended December 31, 2002, a decrease of 6% compared to RR155,511 million for the year ended December 31, 2001. The decrease is attributable to a decrease in domestic sales, delivered prices of crude oil and a decrease in purchases of crude oil and refined products that are resold. This decrease was

partially offset by an increase in petrochemicals sales as a result of a full year of tire sales by OAO Nizhnekamskshina, which has been consolidated into our financial results from September 2001.

Sales of crude oil decreased by 15% to RR81,297 million for the year ended 2002 compared to RR95,223 million for the year ended 2001. The table below provides an analysis of the changes in sales of crude oil:

Domestic sales of crude oil decreased by 63% to RR11,901 million in 2002 from RR32,371 million in 2001. This decrease resulted from the combined effect of a 49% decrease in volumes sold and a 27% decrease in selling prices. The decline in volumes sold domestically was due to our strategy of reducing domestic crude oil sales resulting in higher sales to the CIS and increased refining volumes. The decrease of average selling prices in 2002 compared with 2001 is due to low domestic prices in the first half of 2002. Domestic prices increased in the third quarter but dropped again in December 2002. As a percentage of total sales and other operating revenues, domestic sales decreased to 8% in 2002 from 21% in 2001

Substantially all of our CIS sales of crude oil in the periods under review were to the Kremenchug oil refinery in Ukraine. CIS export sales of crude oil increased by 65% to RR11,510 million in 2002 from RR6,997 million in 2001. This increase was attributable to an increase in supplies to the Kremenchug refinery. CIS average crude oil prices per ton decreased to RR2,823 for the year ended December 31, 2002, or by 31%, compared to RR4,078 for the year ended December 31, 2001, due to a decline in CIS market prices. As a percentage of total sales and other operating revenues, CIS export sales increased to 8% in 2002 from 4% in 2001.

Non-CIS export sales of crude oil totalled RR57,886 million for the year ended December 31, 2002, an increase of 4%, compared to RR55,855 million for the year ended December 31, 2001. Sales volumes increased to 10,861 thousand tons in 2002 compared to 10,065 thousand tons in 2001. Non-CIS average crude oil prices per ton decreased to RR5,330 in 2002 from RR5,549 per ton in 2001, or by 4%, as a result of a general change in world crude oil prices in 2002. As a percentage of total sales and other operating revenues, non-CIS export sales increased to 40% in 2002 from 36% in 2001.

The table below provides an analysis of the changes in sales of refined products:

Sales of refined products amounted to RR44,376 million for the year ended December 31, 2002 compared to RR43,859 million for the year ended December 31, 2001, a 1% increase. This slight increase in refined product sales was due primarily to two offsetting factors: a 14% increase in domestic prices and a decrease in sales to Europe. Refined products that we sell are primarily gasoline, fuel oil (mazut), diesel fuel and nafta. As a percentage of total sales and other operating revenues, sales of refined products increased to 31% in 2002 from 28% in 2001. Production of our own refined products represents a new business direction for us, which we intend to expand further in the future.

Domestic sales of refined products totaled RR24,378 million for the year ended December 31, 2002 compared to RR18,971 million for the year ended December 31, 2001, a 29% increase. Volumes of domestic sales of refined products increased to 7,403 thousand tons in 2002 compared to 6,591 thousand tons in 2001 due to the combined effects of an increase in volumes resulting from the growth in our retail gas stations network and an increase in selling price resulting primarily from changes in the mix of products to include more light refined products. The share of light refined products, especially gasoline, increased primarily due to increased processing at the Moscow refinery. Domestic sales of refined products constituted 17% of our total sales and other operating revenues in 2002, compared to 12% in 2001. The Tatarstan government requires us to maintain a continuous supply of both crude oil and refined products to Nizhnekamskneftekhim. Prior to March 1999 we supplied crude oil to Nizhnekamskneftekhim via intermediaries. Since March 1999, when we started operating a leased refining unit in Nizhnekamsk, we have shipped the principal refined products to Nizhnekamskneftekhim for higher prices than if we had sold crude oil directly to it. In 2002, we sold 972,000 tons of refined products to Nizhnekamskneftekhim for RR3,216 million, included here in domestic sales.

Non-CIS export sales of refined products decreased by 17% to RR19,968 million in 2002 from RR24,183 million in 2001 due to declines in volumes sold, partially offset by a 7% increase in the average selling price in 2002 compared with 2001. The decrease in volumes resulted from a shift to selling our own refined products to export markets from reselling refined products purchased from third parties. As a result, our sales of purchased refined products decreased in 2002 compared to 2001. Non-CIS sales of refined products constituted 14% of our total sales and other operating revenues in 2002.

Sales of petrochemical products increased by 140% to RR9,920 million in 2002 from RR4,133 million in 2001. The increase was primarily attributable to the full-year consolidation of Nizhnekamskshina’s revenues in 2002, while in 2001 it was consolidated only from the fourth quarter. Sales of tires, which are included within sales of petrochemical products, increased by 223% to RR8,768 million in 2002 from RR2,718 million in 2001. Sales of petrochemical products constituted 7% of our total sales and other operating revenues in 2002.

Other sales decreased by 20% to RR9,890 million in 2002 from RR12,296 million in 2001. Other sales include revenues from sales of materials and equipment, various field services provided by our production subsidiaries to third parties (such as drilling, lifting, construction, repairs and geophysical works) and revenues from some of our specialized subsidiaries for communication services and insurance fees. The decrease of other sales is due to our strategy to reduce the number and level of our non-core activities.

Operating expenses increased by 16% to RR36,390 million in 2002 from RR31,297 million in 2001. Operating expenses include the following main categories: lifting expenses connected with extraction of crude oil, refining expenses, cost of petrochemical products, cost of materials other than oil and gas, refined products purchased for resale and other direct costs. The increase in operating expenses is primarily attributable to the full-year consolidation of Nizhnekamskshina, whose operating expenses increased by approximately RR5,600 million to RR8,184 million. Refining expenses also increased by RR1,031 million due to the increase in refining volumes. These increases were partially offset by a reduction in crude oil lifting costs in the amount of RR2,854 million. Operating expenses as a percentage of total sales and other operating revenues increased to 25% in 2002 from 20% in 2001.

A summary of purchases of oil and refined products for 2002 and 2001 is as follows:

Expenses related to the purchase of oil and refined products totaled RR28,372 million for the year ended December 31, 2002, a decrease of 17%, compared to RR34,104 million for the year ended December 31, 2001. This decrease resulted from reduction in purchases of oil to RR14,035 million in 2002 from RR21,013 million in 2001. The average price of purchased refined products was due to the increase in the volume of light refined products in the mix of purchased products. Refined products are purchased from third parties for resale. The decline in crude oil purchases was due mainly to a decrease in volumes purchased, as we increased the refining of our own crude oil. Purchases of oil and oil products as a percentage of total sales and other operating revenues decreased to 20% in 2002 from 22% in 2001.

Exploration expenses totaled RR463 million for the year ended December 31, 2002, a decrease of 45% compared to RR839 million for the year ended December 31, 2001. Total exploration expenditures for 2002 actually increased slightly to RR856 million from RR839 million in 2001, but the overall reduction in exploration expense is attributable to our success in exploratory drilling resulting in a greater proportion of these costs being capitalized.

Transportation expenses are incurred in the delivery of crude oil and refined products to final customers and to refineries for processing. Transportation expenses increased by 10% to RR5,683 million in 2002 from RR5,183 million in 2001 primarily due to an increase in Transneft transportation tariffs and the increase in CIS crude oil export sales. In 2002, we also began to export crude oil by rail in order to overcome limitations on crude oil exports outside of the CIS through the Transneft pipeline system.

Selling, general and administrative expenses decreased by 14% to RR15,770 million in 2002 from RR18,309 million in 2001. Certain selling, general and administrative expenses are by nature fixed costs, which are not directly attributable to production, such as general business costs, insurance, advertising, management expenses, legal fees, consulting and audit services. The decrease was largely due to a RR1,716 million decrease in charity and sponsorship expenses and a RR1,289 million decrease in bad debt provisions. Selling, general and administrative expenses included insurance costs in the amount of RR3,351 million in 2002 (RR2,088 million in 2001), which increased due to the combined effect of increased tariff rates and scope of insurance coverage. These expenses constituted 11% of our total sales and other operating revenues in 2002.

Depreciation, depletion and amortization totaled RR7,325 million for the year ended December 31, 2002, an increase of 26% compared to RR5,822 million for the year ended December 31, 2001. The increase was attributable to the combined effect of the full-year consolidation of Nizhnekamskshina, which became our subsidiary effective from September 30, 2001, and continued investments into property, plant and equipment, especially our retail network of service stations. These expenses constituted 5% of our total sales and other operating revenues in 2002, compared to 4% in 2001.

Loss on disposals and impairment decreased by 66% to RR851 million in 2002 from RR2,502 million in 2001, due primarily to a decrease in impairment charges from 2001 and losses on disposals of subsidiaries not considered to be part of our core operations. These expenses constituted less than 1% of our total sales and other operating revenues in 2002.

Taxes other than income taxes totaled RR31,988 million for the year ended December 31, 2002, a decrease of 4% compared to RR33,373 million for the year ended December 31, 2001. Export duties decreased by RR4,807 million to RR11,890 million from RR16,697 million. Mineral restoration tax, royalty tax and excise tax were abolished and replaced by the unified natural resources production tax. Unified natural resources production tax for 2002 increased by RR5,032 million in comparison to the total amount of the three production taxes, in effect in 2001. Housing tax and research and development taxes were also abolished effective from January 1, 2002. Property taxes increased by 23% to RR1,336 million from RR1,087 million due to an increase in the taxable base after Tatneft completed a statutory revaluation of its fixed assets. Road users tax decreased by 16% to RR1,079 million from RR1,285 million due to the decrease in net sales. As a percentage of total sales and other operating revenues, taxes other than income taxes remained substantially the same at 22% and 21% in 2002 and 2001, respectively. See “Item 3—Key Information—Risk Factors—Risks Relating to the Russian Legal System and Russian Legislation.”

Maintenance of social infrastructure expenses totaled RR199 million for the year ended December 31, 2002, a decrease of 59% from RR491 million for the year ended December 31, 2001. Social infrastructure expenses include mainly agricultural support costs and are subject to variations depending on social needs. The decrease was primarily attributable to reduction in agriculture

support and city reconstruction costs. As a percentage of total sales and other operating revenues, maintenance of social infrastructure expense remained below 1% in both 2002 and 2001.

Expenses arising from the transfer of social assets constructed after privatization totaled RR1,293 million for the year ended December 31, 2002, an increase of 118% compared to RR593 million for the year ended December 31, 2001. This reflected our continued divestiture of social assets. The timing of these transfers is dependent on discussions with the government of Tatarstan. As a percentage of total sales and other operating revenues, transfer of social infrastructure expense remained below 1% in both 2002 and 2001

Total production expenses include lifting, general and administrative and transportation expenses, and exclude costs incurred in conjunction with services rendered to third parties, goods produced or purchased and then subsequently sold, and other auxiliary activities of the exploration and production segment unrelated to the extraction of oil and gas reserves. Lifting and general and administrative expenses are expenses related to oil and gas production and incurred by our oil and gas producing divisions.

Our direct operating costs for crude oil extraction, or lifting expenses averaged US$2.47 per barrel in 2002 compared to US$2.74 per barrel in 2001, representing a 9.9% decrease. The decrease in lifting expenses in 2002 compared to 2001 occurred primarily as a result of a cost-saving program initiated by management, including optimization of the cost structure, outsourcing of auxiliary activities and other efficiency improvements.

General and administrative expenses include expenses incurred by production divisions that relate to crude oil production. The increase in general and administrative expenses per barrel of produced crude oil was primarily the result of increased overhead of the production divisions.

The increase in transportation expenses per barrel of produced crude oil was primarily due to the combined effect of increased Transneft tariffs and increased sales of crude oil to the CIS for which transport costs are generally higher than for domestic sales.

The increase in total taxes other than income tax per barrel of produced crude oil was primarily the result of the introduction of the unified natural resources production tax, which replaced royalty tax, mineral restoration tax and excise tax on crude oil production. In 2002, the effective unified natural resources production tax rate was US$2.86 per barrel, while the effective aggregate tax rate for royalty, mineral restoration and excise on production in 2001 was US$1.87 per barrel. The increase in the unified natural resources production tax was partly offset by the decrease in crude oil export duty and road users tax per barrel.

The increase in the depreciation expense per barrel of produced crude oil was primarily the result of continued significant investment in the development of oil fields.

Other income (expenses) totaled RR2,370 million for the year ended December 31, 2002, an increase of 24% compared to RR1,917 million for the year ended December 31, 2001. As a percentage of total sales and other operating revenues, other income accounted for 2% during 2002 and 1% during 2001.

Foreign exchange loss totaled RR1,042 million for the year ended December 31, 2002, an increase of 22% from RR851 million for the year ended December 31, 2001. This was due to increased nominal devaluation of the ruble from 7% in 2001 to 11% in 2002. The exchange loss resulted primarily from the revaluation of higher U.S. dollar-denominated liabilities which more than offset the exchange gain associated with U.S. dollar-denominated accounts receivable.

Monetary gain totaled RR871 million for the year ended December 31, 2002, a decrease of 51% from RR1,764 million for the year ended December 31, 2001. The decrease was primarily attributable to slightly lower inflation of 15.1% in 2002 compared to 18.6% in 2001 and a decreased net monetary liability position compared to 2001.

Net interest income from banking decreased by 37% to RR845 in 2002 million from RR1,350 million in 2001. Net interest income from banking consisted of interest income of RR2,236 million and interest expense of RR1,391 million primarily related to the operations of Zenit Bank. Interest expense increased by RR801 million as a result of an increase in debt securities issued and customer deposit accounts partially offset by an increase of RR296 million in interest income.

Other net banking expense increased by 28% to RR673 million in 2002 from RR525 million in 2001. Other net banking expense primarily consists of other income and expenses connected with Bank Zenit and Bank Devon-Credit: income from commissions (RR163 million), gains from sales and purchase of securities net of provisions (RR203 million), loan loss provision (RR69 million), net gains from dealing in foreign currencies (RR281 million), operating expenses related to banking activities (RR1,359 million), and other items. Other net banking expense increased primarily due to an increase in operating expenses related to banking activities by 35% to RR1,359 million in 2002 from RR1,005 million in 2001, primarily attributable to increased staff costs.

Interest expense net of interest income increased by 51% to RR2,051 million in 2002 from RR1,358 million in 2001, primarily due to a decrease of interest income to RR804 million in 2002 from RR1,517 million in 2001. This decrease in interest income was due to reduced holdings of short-term investments.

Other income increased by 312% to RR4,272 million in 2002 from RR1,036 million in 2001. The increase in other income was primarily driven by the redemption of Tatneft Finance Eurobonds, resulting in a net realized holding gain of RR3,408 million. In 2001, these gains were partially recognized in comprehensive income as unrealized holding gains on available-for-sale securities.

Total income tax (benefit) expense totaled RR3,255 million for the year ended December 31, 2002, compared to a (RR1,133) million benefit for the year ended December 31, 2001. Current income taxes totaled RR4,743 million for the year ended December 31, 2002, a decrease of RR2,329 million compared to RR7,072 million for the year ended December 31, 2001. The decrease was attributable to lower statutory profit recognized by the Company in 2002 and lower tax rates. Deferred taxes totaled (RR1,488) million for the year ended December 31, 2002, a decrease of 82% compared to (RR8,205) million for the year ended December 31, 2001. The primary reason for the decrease in deferred income taxes was the change in the Russian income tax rate from 35% to 24% effective January 1, 2002.

Expense attributable to minority interest decreased from RR1,698 million in 2001 to RR471 million in 2002, reflecting decreased income earned by our subsidiaries that are not wholly owned. A significant portion of the decrease is attributable to our increased ownership in Bank Devon-Credit (up to 92%) and decreased net income of our banks in 2002, compared to 2001. In 2002, we also reduced operations with certain subsidiaries with significant minority interest, which contributed to the decline of minority interest.

A breakdown of sales and other operating revenues is provided in the following table:

Sales and other operating revenues totaled RR155,511 million for the year ended December 31, 2001, a decrease of 22% compared to RR199,503 million for the year ended December 31, 2000. This decrease was mainly attributable to the fall in world market prices for oil and refined products and a decline in the amount of oil and refined products purchased for resale from RR61,587 million in 2000 to RR34,104 million in 2001. Sales of crude oil decreased by 20% to RR95,223 million for the year ended December 31, 2001 compared to RR118,964 million for the year ended December 31, 2000.

Domestic sales of crude oil totaled RR32,371 million for the year ended December 31, 2001, a decrease of 7% compared to RR34,657 million for the year ended December 31, 2000. This decrease was attributable to a decrease in oil prices. Domestic average crude oil prices per ton decreased to RR3,036 for the year ended December 31, 2001, or by 18%, compared to RR3,695 for the year ended December 31, 2000. Sales volumes increased to 10,664 thousand tons in 2001 compared to 9,378 thousand tons in 2000. As a percentage of total sales and other operating revenues, domestic sales increased to 21% in 2001 from 17% in 2000.

CIS sales of crude oil totaled RR6,997 million for the year ended December 31, 2001, an increase of 305% compared to RR1,729 million for the year ended December 31, 2000. CIS average crude oil prices per ton increased to RR4,078 for the year ended December 31, 2001, or by 35%, compared to RR3,017 for the year ended December 31, 2000. Sales volumes increased to 1,716 thousand tons in 2001 compared to 573 thousand tons in 2000. The major portion of crude oil sales to CIS countries in 2000 was carried out at a fixed price that was below the market price. In 2001, we realized a market price on all CIS sales rather than

the lower fixed price realized in 2000. As a percentage of total sales and other operating revenues, CIS export sales increased to 4% in 2001 from 1% in 2000.

Non-CIS export sales of crude oil totaled RR55,855 million for the year ended December 31, 2001, a decrease of 32%, compared to RR82,578 million for the year ended December 31, 2000 mainly due to a decline in price. The non-CIS average crude oil price per ton decreased to RR5,549 in 2001 from RR7,529 per ton in 2000, or by 26%, as a result of a general decrease in world crude oil prices in 2001. Sales volumes decreased to 10,065 thousand tons in 2001 compared to 10,968 thousand tons in 2000. As a percentage of total sales and other operating revenues, non-CIS export sales decreased to 36% in 2001 from 41% in 2000.

Sales of refined products amounted to RR43,859 million for the year ended December 31, 2001 compared to RR65,121 million for the year ended December 31, 2000, a 33% decrease. This decrease in refined product sales was due primarily to a decline in average sales prices on the domestic and world markets. This decline reflects the general decline in market prices of fuel oil (mazut) and diesel fuel and a decrease in the amount of refined products purchased for resale. As a percentage of total sales and other operating revenues, sales of refined products decreased to 28% in 2001 from 33% in 2000.

Domestic sales of refined products totaled RR18,971 million for the year ended December 31, 2001 compared to RR21,399 million for the year ended December 31, 2000, an 11% decrease. Volumes of domestic sales of refined products increased to 6,591 thousand tons in 2001 compared to 6,431 thousand tons in 2000 due to the growth in our retail gas stations network. The average price of domestic refined products decreased to RR2,878 per ton in 2001 compared to RR3,327 per ton in 2000, a 13% decrease. Domestic sale of refined products constituted 12% of our total sales and other operating revenues in 2001. Revenues associated with retail gas stations operations totaled RR6,572 million and RR3,474 million for the years ended December 31, 2001 and 2000, respectively, increasing by 89%. These revenues constituted 4% of our total sales and other operating revenues in 2001. The Tatarstan government requires us to maintain a continuous supply of both crude oil and refined products to Nizhnekamskneftekhim. In 2001, we sold to Nizhnekamskneftekhim 1,192 thousand tons of crude oil for RR3,008 million and 1,029 thousand tons of oil products for RR3,289 million.

Non-CIS export sales of refined products totaled RR24,183 million for the year ended December 31, 2001 compared to RR43,695 million for the year ended December 31, 2000, a 45% decrease. The average price of non-CIS refined products decreased to RR3,590 per ton in 2001 compared to RR5,978 per ton in 2000, a 40% decrease. Volumes of non–CIS sales of refined products amounted to 6,737 thousand tons in 2001 compared to 7,309 thousand tons in 2000. Domestic sale of refined products constituted 16% of our total sales and other operating revenues in 2001.

Sales of petrochemical products increased by 74% to RR4,133 million in 2001 from RR2,373 million in 2000. The increase is primarily attributable to the acquisition of the controlling interest in Nizhnekamskshina in September 2001, which provided tire sales of RR2,718 million in the fourth quarter of 2001.

Other revenues consisted primarily of revenues received from selling materials and equipment to third parties and provision of field services to third parties. Revenues from these activities decreased by 6% to RR12,296 million in 2001 from RR13,045 million in 2000. All other sales consisted primarily of revenues received from the sale of raw materials and equipment and the provision of field services to third parties.

Operating expenses totaled RR31,297 million for the year ended December 31, 2001, an increase of 26% compared to RR24,836 million for the year ended December 31, 2000. This increase relates to the consolidation of Nizhnekamskshina from September 30, 2001, an increase in processing costs and an increase in electricity tariffs. The increase in processing costs reflects a change in our strategy in 2001 to switch from purchasing refined products to paying processing fees to third parties to refine our own crude oil. The remaining increase was primarily attributable to increased operating costs required to maintain stable production levels. Our oil fields are mature and would experience a decline in production without an increase in maintenance costs. Operating expenses as a percentage of total sales and other operating revenues increased to 20% in 2001 from 12% in 2000.

A summary of purchases of oil and refined products for 2001 and 2000 is as follows:

Expenses related to the purchase of oil and refined products totaled RR34,104 million for the year ended December 31, 2001, a decrease of 45%, as compared to RR61,587 million for the year ended December 31, 2000. Most of this decrease derived from purchases of refined products, which decreased to RR13,091 million in 2001 from RR41,436 million in 2000. Purchases of oil and refined products as a percentage of total sales and other operating revenues decreased to 22% in 2001 from 30% in 2000.

Exploration expenses totaled RR839 million for the year ended December 31, 2001, an increase of 13% compared to RR740 million for the year ended December 31, 2000. This increase was mainly due to the increase in exploration work as we continued to evaluate our unproved reserves. Overall exploration expenses remained relatively low, at 1% of total costs for the year ended December 31, 2001, due to our continued focus on the development of existing fields.

Transportation expenses increased by 19% to RR5,183 million from RR4,349 million in 2000. The increase is due to an increase in Transneft transportation tariffs.

Selling, general and administrative expenses totaled RR18,309 million for the year ended December 31, 2001, an increase of 66%, compared to RR11,060 million for the year ended December 31, 2000. The increase was primarily attributable to a RR1,635 million increase in insurance costs, a RR1,493 million increase in the overhead costs of production divisions, a RR1,414 million charge for commissions paid on back to back crude oil transactions, and a RR1,027 million increase in the bad debt provision. These expenses constituted 12% of our total sales and other operating revenues in 2001.

Depreciation, depletion and amortization totaled RR5,822 million for the year ended December 31, 2001, an increase of 10%, compared to RR5,292 million for the year ended December 31, 2000. This increase attributable to increased investment in oil producing fixed assets occurring during the last two years in order to maintain production levels. These expenses constituted 4% of our total sales and other operating revenues in 2001.

Loss on disposals and impairment totaled RR2,502 million for the year ended December 31, 2001, a decrease of 4%, from RR2,604 million for the year ended December 31, 2000. The 2001 charge attributable to impairments during 2001 included: RR394 million relating to the write off of fixed assets of one of our telecommunication subsidiaries; RR979 million relating to losses on the disposal of fixed assets; and RR739 million relating to the write down of equity securities received from the government of Tatarstan in connection with the settlement of its loan receivable to Tatneft. These expenses constituted 2% of our total sales and other operating revenues in 2001.

Taxes other than income taxes totaled RR33,373 million for the year ended December 31, 2001, a decrease of 11% compared to RR37,415 million for the year ended December 31, 2000. The decrease was primarily attributable to the reduction in charges for mineral use taxes, excise taxes, road users tax, housing fund and fuel sales taxes more than offsetting the increase in export tariffs. Mineral use taxes decreased by RR1,049 million to RR4,552 million in line with the decline in domestic crude oil prices. Excise taxes decreased by RR2,025 million as we received a refund from the Tatarstan government for excise taxes paid to both the federal budget and Tatarstan budget from 1996 to 2000. The refund amounted to RR2,089 million. Road users tax decreased by RR755 million to RR1,285 million due to the reduction in crude oil prices and the reduction in the tax rate from 2.5% to 1%. Federal housing fund and fuel sales taxes decreased by RR2,814 million as they were abolished in 2001. Export tariffs increased by RR2,866 million to RR16,697 million in line with higher tariffs on crude oil and refined product sales. The average oil and refined products export tariff increased by euro 6.69 per ton to euro 29.18 in 2001. As a percentage of total sales and other operating revenues, taxes other than income taxes increased to 21% in 2001 from 19% in 2000.

Maintenance of social infrastructure expenses totaled RR492 million for the year ended December 31, 2001, an increase of 95% from RR252 million for the year ended December 31, 2000. The increase was primarily attributable to the increases in agricultural support and city reconstruction costs. As a percentage of total sales and other operating revenues, maintenance of social infrastructure expense remained below 1% in both 2001 and 2000.

Expenses arising from the transfer of social assets constructed after privatization totaled RR593 million for the year ended December 31, 2001, an increase of 364% compared to RR128 million for the year ended December 31, 2000. This reflected our continued divestiture of social assets. As a percentage of total sales and other operating revenues, transfer of social infrastructure expense remained below 1% in both 2001 and 2000.

Our direct lifting costs averaged US$2.74 per barrel in 2001 compared to US$2.39 in 2000, a 14.6% increase. The increase in lifting expenses in 2001 compared to 2000 was attibutable primarily to increased repair and maintenance expenses in 2001. The repair and maintenance program prior to 2001 had been limited by a lack of financing, but increased proceeds from sales of crude oil in 2000 allowed an expansion of repairs and maintenance works in 2001.

General and administrative expenses increased by 51% in 2001 compared to 2000. The increase was primarly due to increased insurance expenses included within general and administrative expenses, and staff costs of administrative personnel also increased as a result of salary increases.

Transportation expenses decreased by 4% in 2001 compared to 2000. This decrease was primarily due to an 8% decline in the volumes of crude oil sales to Europe in 2001 compared to 2000, partially offset by increased Transneft tariffs for transportation of crude oil.

Taxes other than income tax decreased by 18% to US$3.18 per barrel in 2001 from US$3.87 per barrel in 2000. The decrease was primarily attributable to a reduction in charges for mineral use tax, excise tax and road users tax, partially offset by an increase in export duties. Mineral use tax decreased in line with the decline in domestic crude oil prices, excise tax decreased as a result of a refund from the Tatarstan Government for excise taxes paid to both the federal and Tatarstan budgets from 1996 to 2000 amounting to RR2,084 million, and road users tax decreased due to a reduction in crude oil prices and a reduction in the tax rate from 2.5% to 1%. Export duties increased due to higher tariffs on crude oil.

The depreciation, depletion and amortization charge per barrel increased by 19% in 2001 compared to 2000 due to increased investment in oil producing fixed assets in order to maintan stable production levels.

Other income (expenses) totaled RR1,918 million for the year ended December 31, 2001, an increase of 36% compared to RR1,406 million for the year ended December 31, 2000. As a percentage of total sales and other operating revenues, other expenses were 1% during both 2001 and 2000.

Foreign exchange loss expense totaled RR851 million for the year ended December 31, 2001, an increase of 44% from RR591 million for the year ended December 31, 2000. This was due to further devaluation of the ruble from 4% in 2000 to 7% in 2001. The exchange loss resulted primarily from the revaluation of U.S. dollar-denominated liabilities which more than offset the exchange gain associated with U.S. dollar-denominated accounts receivable.

Monetary gain totaled RR1,764 million for the year ended December 31, 2001, a decrease of 52% from RR3,706 million for the year ended December 31, 2000. The decrease was primarily attributable to slightly lower inflation of 18.6% in 2001 compared to 20% in 2000 and a decrease in our net monetary liability position compared to 2000.

Bank Zenit was consolidated effective December 31, 2000 and banking income and expense were included separately into net interest income and other net banking income. Net interest income from banking consisted of interest income of RR1,940 million and interest expense of RR590 million primarily related to the operations of Bank Zenit. Other net banking income primarily consisted of RR315 million of net income from commissions, RR599 million of net gains from the sale and purchase of securities and foreign currencies, RR348 million of loan loss provision and RR1,005 million of operating expenses related to the operations of Bank Zenit.

Interest expense net of interest income decreased by 61% to RR1,358 million, primarily due to the decrease in average annual interest rates in line with the decrease in LIBOR, more than offsetting the impact of higher total debt, and an increase in interest accrued on debt securities.

Total income tax (benefit) expense was a benefit of (RR1,133) million for the year ended December 31, 2001, compared to a RR19,717 million expense for the year ended December 31, 2000. Current income taxes totaled RR7,072 million for the year ended December 31, 2001, a decrease of RR3,750 million compared to RR10,822 million for the year ended December 31, 2000. The decrease was due to a decrease in taxable income. Deferred taxes reflected a benefit of (RR8,205) million for the year ended December 31, 2001, a decrease of 192% compared to a RR8,895 million expense for the year ended December 31, 2000. The primary reason for the decrease in deferred income taxes was the change in the Russian income tax rate from 35% to 24%, enacted in August 2001 and effective January 1, 2002.

Expense attributable to minority interest increased from RR475 million in 2000 to RR1,698 million in 2001, primarily due to the consolidation of Nizhnekamskshina and Bank Zenit and an increase in the profitability of other majority-owned subsidiaries.

Our Consolidated Statements of Cash Flows reflect the effects of operating in a hyperinflationary environment, in which financial statements are adjusted for price level changes, and the effects of currency fluctuations on our results. The amounts in the Consolidated Statements of Cash Flows show actual nominal cash flows restated to the December 31, 2002 purchasing power of the ruble. The working capital movements represent the actual nominal increases or decreases in working capital balances at the date they actually occurred, restated to the December 31, 2002 purchasing power of the ruble. Accordingly, this presentation removes the effects of inflation and foreign exchange on us, and presents this information on inflation and foreign exchange separately in the cash flow statement.

At December 31, 2002, our cash holdings consisted of cash, cash equivalents, and restricted cash, including U.S. dollar-denominated amounts of RR4,150 million (US$131 million), of which holdings of RR178 million (US$6 million) is restricted.

At December 31, 2002, our working capital amounted to RR17,273 million, compared to RR5,958 million at December 31, 2001, and our current ratio increased to 1.36 from 1.09. The increase in working capital was primarily due to a decrease in short-term debt and current portion of long-term debt from RR27,081 million at December 31, 2001 to RR16,618 million at December 31, 2002. In October 2002, we repaid our US$300 million loan from Dresdner Bank AG that we had received in connection with the issuances of the Tatneft Finance PLC Eurobonds primarily through new long-term borrowings. We believe that our working capital is sufficient for our present requirements.

As required by U.S. GAAP, our presentation of cash flows excludes barter transactions. In order meaningfully to compare the fluctuations in cash flows between periods, the following discussion includes barter transaction as shown in the following tables.

In 2002 and 2001, the major sources of our liquidity were cash flows from operating activities and funds borrowed under credit facilities described under “—Debt” below.

Our net cash and barter settlements provided by operating activities decreased from RR25,892 million at December 31, 2001 to RR18,193 million at December 31, 2002. This decrease occurred primarily due to a decrease in sales and other operating revenues.

Our net cash and barter settlements provided by operating activities decreased from RR33,689 million at December 31, 2000 to RR25,892 million at December 31, 2001. This decrease occurred primarily due to a significant decrease in net income from RR32,454 million in 2000 to RR24,350 million in 2001; a decrease in barter settlements; and the impact of deferred tax changing from a positive adjustment of RR8,895 million in 2000 to a negative adjustment of (RR8,205 million) in 2001. These negative factors were offset by cash inflows arising from changes in our working capital of RR182 million in 2001 compared to a cash outflow of RR12,901 million in 2000 and a decrease in monetary gain from RR3,706 million in 2000 to RR1,764 million in 2001.

Net cash and barter settlements used for investing activities were RR16,042 million for the year ended December 31, 2002, compared to RR28,145 million for the year ended December 31, 2001. The main reason for this decrease was the decrease in cash used for investing activities primarily as a result of lower capital expenditures on property, plant and equipment. Capital expenditures on property, plant and equipment declined to RR13,100 million in 2002 from RR20,583 million in 2001.

Net cash and barter settlements used for investing activities were RR28,145 million the year ended December 31, 2001, compared to RR30,130 million for the year ended December 31, 2000. Net cash used for investing activities increased by RR4,540 million primarily due to the consolidation of our subsidiary Nizhnekamskshina and an increase in our investment in OAO Nizhnekamsk Oil Refinery from RR1,031 million in 2000 to RR3,060 million in 2001.

Net cash provided by financing activities totaled RR325 million in 2002 compared to net cash provided by financing activities of RR4,024 million in 2001. The decrease is due to the reduction of proceeds from debt net of repayment equal to RR1,142 million in 2002 compared with RR5,804 million in 2001. Purchases of treasury shares net of proceeds from sales of treasury shares also decreased to RR416 million in 2002 from RR1,774 million in 2001.

Net cash provided by financing activities totaled RR4,025 million in 2001 compared to net cash used for financing activities of RR2,579 million in 2000. This increase related to new long-term hard currency loans from Commerzbank AG in the amount of RR4,337 million and BNP Paribas in the amount of RR3,470 million.

We make some of our capital expenditures using consideration other than cash. In the year ended December 31, 2002, our operating cash flows exceeded our cash capital expenditures and were above our combined cash and non-cash capital expenditures. In the years ended December, 31, 2001 and 2000, our operating cash flows exceeded our cash capital expenditure, but were not sufficient to cover our combined cash and non-cash capital expenditures.

Most of our capital expenditures are made in the exploration and production segment to maintain oil production levels. Capital expenditures in refining and marketing are made to improve the oil refining capacities of Nizhnekamsk oil refinery and increase our number of gas stations. Capital expenditures in the petrochemicals segment are mainly related to capital expenditures of Nizhnekamskshina, Nizhnekamsk Industrial Carbon Plant and Yarpolymermash-Tatneft to support production and sale of automobile tires.

We have planned capital expenditures for 2003 of approximately RR13,000 million. Future capital expenditures are expected to be made principally on production development, drilling development and other equipment in order to maintain current crude oil production. In addition, we plan to continue to make investments in the Nizhnekamsk refinery, our single most significant current capital commitment, development of our retail gas station network and development of our petrochemicals operations, including upgrading production at Nizhnekamskshina. Our capital expenditures will be dependent on the sufficiency of cash flows. See “Item 4—Information on the Company.” Capital expenditures on social assets will continue to be substantial, although we believe they will be lower than in the past as a result of the implementation of our cost restructuring plans. See “Item 4—Information on the Company—Corporate Reorganization—Divestiture of Social Assets.”

We expect to finance substantially all of our capital expenditures from cash from operating activities, primarily sales of crude oil and refined and petrochemical products. The actual amount and timing of capital expenditures made are subject to change depending on economic and political conditions.

Our borrowings net of repayments were RR1,142 million and RR5,804 million for the period ended December 31, 2002 and December 31, 2001, respectively. However, as a result of the restatement in constant ruble terms of all our comparatives in accordance with inflation accounting under Accounting Principles Board Statement 3, Financial Statements Restated for General Price-Level Changes, our debt balances are reported to have declined despite these net borrowings.

The overall decline in our borrowings as reported in our financial statements resulted from opposite movements in our long-term and short-term borrowings. Our long-term borrowings (including the current portion of long-term borrowings), which are predominantly denominated in convertible currencies (mainly the U.S. dollar and the euro), are reported to have declined in constant ruble terms at December 31, 2002 compared to December 31, 2001. Our short-term borrowings (excluding the current portion of long-term borrowings), which are predominantly denominated in rubles, are reported to have increased in constant ruble terms at December 31, 2002 compared to December 31, 2001.

The following table shows our borrowings at December 31, 2002 and 2001 expressed in constant ruble terms:

At December 31, 2002 and 2001, respectively, our long-term debt, including current maturities, amounted to RR20,734 million and RR23,712 million, and our short-term debt amounted to RR16,618 million and RR27,081 million. In the following paragraphs we provide a summary of our outstanding debt. For a more comprehensive information about our debt see Note 11 to our audited consolidated Financial Statements included in this annual report.

Short-term foreign currency-denominated debt. At December 31, 2002, our short-term foreign currency-denominated debt amounted to RR11,677 million and included loans from Winter Bank, BNP Paribas, Donau Bank, Credit Swiss Zurich, Whill Trading and interbank loans.

In July 2001, we entered into a RR1,042 million (US$30 million) loan agreement with Winter Bank. The loan bears an interest rate of 6 month LIBOR plus 4.5% per annum. The loan must be repaid in full every six months and may be renewed immediately for an additional six months during the three year term of the commitment. The loan matures in November 2004. The amount of the loan outstanding as of December 31, 2002 was RR954 million.

In 2002, we entered into a RR 1,570 million (US$50 million) loan agreement with BNP Paribas. The loan bears interest at one month LIBOR plus 3.5% per annum and is collateralized by the crude oil export contracts of 45,000 tons per month. The amount of the loan outstanding as of December 31, 2002 was RR993 million. The loan matures in May 2003.

In December 2002, we entered into a RR636 million (US$20 million) loan agreement with Donau Bank. The loan bears interest at 2.3% per annum and matures in December 2003.

In 2002, we entered into a RR636 million (US$20 million) one month revolving overdraft facility with Credit Swiss Zurich. The monthly revolving loan bears interest from 3.150% to 3.750% per annum and is collateralized by crude oil sales. The amount of loan outstanding as of December 31, 2002 was RR438 million (US$14 million).

In 2002, we entered into a RR22 million (US$0.7 million) loan agreement with Whill Trading. The loan bears interest at 12 % per annum, matures in March 2003 and is unsecured.

Interbank loans from foreign banks of RR2,522 million and RR3,276 million as of December 31, 2002 and 2001 had effective average year end interest rates of 7% and 4% per annum, respectively.

Long-term foreign currency-denominated debt. At December 31, 2002, our long-term foreign currency-denominated debt amounted to RR20,162 million. Our largest long-term foreign currency-denominated loans include a Commerzbank loan, two BNP Paribas loans and a Credit Suisse First Boston loan.

In October 2001, we entered into RR4,337 million (US$125 million) loan agreement with Commerzbank AG. The loan is secured by oil export receivables and matures in October 2003. As of December 31, 2002, we had US$69.4 million outstanding under this loan agreement.

In November 2001, we entered into a RR3,470 million (US$100 million) loan agreement with BNP Paribas. The loan is secured by oil export receivables and matures in May 2004. As of December 31, 2002, we had US$70.8 million outstanding under this loan agreement.

In March 2002, we entered into a RR6,357 million (US$200 million) loan agreement with Credit Suisse First Boston (Cyprus) Limited. The loan is secured by oil export receivables and matures in March 2007. As of December 31, 2002, we had US$180 million outstanding under this loan agreement.

In October 2002, we entered into a RR9,353 million (US$300 million) loan agreement with BNP Paribas. The loan is secured by oil export receivables and matures in October 2007. As of December 31, 2002, we had US$298.6 million outstanding under this loan agreement.

We pay interest on our secured loans at a floating rate calculated as LIBOR plus a certain margin, ranging from 3.5% to 4.25%. These loans are currently collateralized by aggregate oil exports of 450,000 tons per month (subject to increases depending on crude oil prices).

Zenit Eurobonds. In June 2003, our subsidiary Bank Zenit entered into a credit facility agreement (the “Credit Facility”) with WestLB AG (“WestLB”) in the amount of US$125 million, bearing interest at 9.25%, payable semi-annually. Simultaneously, WestLB issued US$125 million of 9.25% notes due in June 2006 (the “Notes”). WestLB loaned the proceeds from this issuance to Bank Zenit under the Credit Facility. Payments made by Bank Zenit under the Credit Facility fund WestLB’s payment obligations under the Notes. As part of this series of transactions, Bank Zenit has guaranteed the obligations of WestLB under the Notes.

Ruble-denominated debt. At December 31, 2002 and 2001, we had short-term ruble-denominated loans of RR4,941 million with contractual interest rates of 10% to 25% per annum and RR3,921 million with contractual interest rates of 10% to 22% per annum, respectively. We also had short-term notes payable in the amount of RR2,830 million and RR7,710 million at December 31, 2002 and 2001, respectively, with contractual interest rates of 2% to 19%for the year ended December 31, 2002. Long-term ruble-denominated debt includes debentures and other loans. In 2001 and 2002 we issued RR300 million in debentures with contractual interest rates from 11.78% to 18.72%. Debentures outstanding as of December 31, 2002 amounted to RR200 million. Other loans include non-interest bearing ruble-denominated loans of RR112 million with related parties and loans with other counter parties. The loans mature between 2003 and 2015.

The following table shows our schedule of repayments for long-term borrowings (excluding long-term promissory notes, deposit certificates and term banking customer deposits) at December 31, 2002 and December 31, 2001, expressed in constant ruble terms.

Banking commitments and contingent liabilities comprise Bank Zenit’s loan commitments and guarantees of RR4,773 million and RR2,398 million at December 31, 2002 and 2001, respectively. The contractual amount of these commitments represents the value at risk if the bank’s clients default and all existing collateral becomes worthless.

Bank Zenit managed trust and fiduciary assets with a nominal value of RR4,148 million and RR14,941 million at December 31, 2002 and 2001, respectively. These assets are recorded off balance sheet as they are not assets of Bank Zenit. No insurance coverage is maintained with respect to these assets.

The preparation of consolidated financial statements in conformity with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual amounts may differ from these estimates. The following critical accounting policies require significant judgments, assumptions and estimates and you should read them in conjunction with our consolidated financial statements.

Oil exploration and production activities. We follow the successful efforts method of accounting for our oil and gas properties, whereby property acquisitions, successful exploratory wells, all development costs (including development dry holes) and support equipment and facilities are capitalized. We expense exploratory well costs if we cannot determine whether proved reserves have been found within a reasonable amount of time following completion of drilling.

We expense all other exploratory costs. We calculate depreciation, depletion and amortization of capitalized costs of proved oil and gas properties using the unit-of-production method for each field based upon estimates of proved and proved developed reserves.

The process of estimating reserves is inherently judgmental. Proved oil and gas reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date that the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon judgments about future conditions. Actual prices and costs are subject to change due, in significant part, to factors beyond our control. These factors include world oil prices, energy costs and increases or decreases of oil field service costs. Due to inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to changes over time as additional information becomes available.

Our oil and gas fields are situated on land belonging to the government of Tatarstan. We obtain licenses from local authorities and pay taxes to explore and produce oil and gas. Most significant licenses expire in 2013. Management believes the licenses may be extended at our initiative and expects to extend such licenses for properties expected to produce subsequent to their license expiry date. Management believes that proved reserves should include quantities that are expected to be produced after the expiration dates of our production licenses. We have disclosed elsewhere in this annual report information on proved oil reserve quantities for periods up to and following license expiration dates separately.

We accrue estimated costs of dismantling oil and gas production facilities, including abandonment and site restoration costs, using the unit-of-production method and includes these costs as a component of depreciation, depletion and amortization. These estimates are based on currently available technology and current environmental regulations and their interpretation. If these technologies or regulations or their interpretation change in the future, actual results could differ from the estimates.

Environmental remediation. We record liabilities for environmental remediation when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Liabilities for environmental remediation are subject to change because of matters such as changes in laws and regulations and their interpretation, the determination of additional information on the extent and nature of site contamination and improvements in technology.

Income tax accounting. The computation of our income tax expense requires the interpretation of complex tax laws and regulations and the use of judgment in determining the nature and timing of accounting for differences between financial reporting and income tax reporting. This is particularly evident in the Russian Federation where tax legislation is constantly changing (specifically the statutory profits tax rate) and is subject to interpretation by the tax authorities. Changes in the Russian statutory tax rate can significantly affect our deferred tax liability. As prescribed by U.S. GAAP, any changes to the statutory tax rate are recognized by us in the period the tax law is enacted rather than the effective date of the change.

In August 2001, two new chapters of the Russian Tax Code were enacted that significantly affect our results of operations. Under the first of these chapters, the rate of corporate income tax was reduced from 35% to 24%; however, investment tax credits that could be used to half the corporate tax rate have been abolished. Under the second chapter, mineral restoration tax and mineral use tax (at the effective rate of approximately 6% and 8%, respectively, of oil and gas revenues recognized for Russian statutory purposes) and excise tax on crude oil production of approximately US$0.30 per barrel were replaced with a unified natural resources production tax. The unified natural resources production tax effective through December 31, 2004 is computed as US$1.55 per barrel multiplied by a coefficient linked to market prices for Urals blend crude oil (the “Urals price”) over US$8.00 per barrel. From January 1, 2005, the unified rate is set by law at 16.5% of oil and gas value of extracted natural resources which may be calculated by reference to actual sale prices of natural resources or the deemed value of natural resources. The two new chapters of the Russian tax code came into effect on January 1, 2002.

The above assessment of critical accounting policies is not meant to be an all-inclusive discussion of the uncertainties to financial results that can occur from the application of the full range of our accounting policies. Materially different results could occur in the application of the accounting policies as well. Additionally, materially different results can occur upon the adoption of the new accounting standards promulgated by the various rule-making bodies.

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No.

143, Accounting for Asset Retirement Obligations (“SFAS 143”). This new statement will be adopted effective January 1, 2003 and applies to legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Adoption of SFAS 143 primarily affects our accounting for oil and gas producing assets and differs in several significant respects from current accounting under Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. Upon initial recognition of a liability for an asset retirement obligation, we will capitalize an asset retirement cost by increasing the carrying value of the related long-lived asset by the same amount. Legal obligations, if any, to retire refining and marketing and distribution assets are generally not recognized because of the indeterminable settlement date of these obligations. We are currently completing our assessment of the effect of the adoption of SFAS 143 on us.

Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FAS 123 (“SFAS 148”) provides alternative methods for the transition of the accounting for stock-based compensation from the intrinsic value method to the fair value method. Effective January 1, 2003, we plan to apply the fair value method to future grants and any modified grants of stock-based compensation. Based upon this change, and assuming the terms of stock options grants in 2003 are similar to those granted in prior years, the estimated impact on our 2003 earnings would not be materially different than under previous accounting standards.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”). The disclosure provisions of FIN 45 are effective for fiscal years ending after December 15, 2002, and are included in Note 20, Commitments and Contingent Liabilities, whereas the recognition and measurement requirements are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”). FIN 46 amended ARB 51, Consolidated Financial Statements, and established standards for determining under what circumstances a variable interest entity (“VIE”) should be consolidated with its primary beneficiary. FIN 46 also requires disclosures about VIEs that we are is not required to consolidate but in which it has a significant variable interest. The consolidation requirements of FIN 46 apply immediately to VIEs created after January 31, 2003, while earlier formed entities must be consolidated in the first fiscal year or interim period beginning after June 15, 2003. We do not expect the initial adoption of FIN 46 to have a significant impact on our results of operations, financial position or liquidity.

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (“SFAS 150”). SFAS 150 establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equity and is effective for financial instruments entered into or modified after May 31, 2003. We do not expect the initial adoption of SFAS 150 to have a significant impact on our results of operations, financial position or liquidity.

In the years ending December 31, 2002, 2001 and 2000, we spent approximately RR437 million, RR426 million and RR436 million on research and development, respectively.

The Tatar Research and Design Institute of the Oil Industry (“TatNIPIneft”), a research division of ours, has been in operation for 45 years and is our main research and development unit. TatNIPIneft is one of the leading petroleum and petrochemicals research and development institutes in Russia and specializes in the prospecting and exploration of oil fields, well construction and rehabilitation, production methods, corrosion protection of oil equipment, and the design and development of oil fields.

We often conduct basic research in collaboration with independent research institutes, either on an ongoing or one-off contract basis. Generally, contracts for such research provide for the joint ownership of any research developed, our ownership of any resulting patents, and an indemnification of Tatneft by the research institute with regard to any claims arising from unauthorized usage by the research institute of processes or technologies patented by third parties. These terms are all subject to variation, however, depending on the specific circumstances of the research to be conducted.

We use a variety of patented technologies (and related processes) in our operations, as do our affiliates and related institutes, such as TatNIPIneft. These patented technologies and processes include several that have been licensed from third parties. We currently hold more than 400 Russian patents, of which we actively exploit approximately 50. In addition, we hold 23 patents outside Russia, including in the United States, Australia and China. Patented technology (and related processes) that are material to our operations consist primarily of patents relating to protecting pipelines against corrosion caused by water or foreign particles, patents for local well fixing technology and patents relating to extracting and containing gas and light hydrocarbons escaping from crude oil held in storage. We developed some of these patents (such as those on the TATEX gas collection system) in joint ventures or in collaboration with other third parties. We believe that licensing revenues are not material to us.

In 2002, our oil field development work included development of new designs and processes for the application of advanced oil bed stimulation methods and technologies, in order to ensure profitable oil field development. In the area of well construction, we have specifically focused on increasing penetration rates and well production capabilities. Moreover, we continue to improve the quality of techniques for drilling mud, technologies for implementing profile shut-offs and construction of small-diameter wells. In oil and gas treatment, we are developing a “quality bank” of stock-tank oils and rebuilding oil and gas collection and well-production separation structures. In addition, we have continued development of a unit for utilization of acid gases, which will reduce our environmental emissions as well as facilitate the production of elementary sulfur.

In the energy sector, we are building new, more efficient and economical equipment. We are focusing on energy-saving projects as well as the development and implementation of measures to optimize energy consumption during the transition to time-specific tariffs by our suppliers. We are also improving the automation of our control systems by creating integrated control and information support for oil production, accounting, treatment and delivery. These measures will allow us to use available information to analyze various production areas and to take immediate action during an emergency.

In order to protect our equipment, we have worked to develop new anticorrosion equipment and monitoring programs, including new field development methods. We have also sought to develop geological-technical measures for improving our flooding system, ensuring a reliable operation of well stock and creating highly efficient pumping units, valving and “Christmas-tree” equipment. We have also worked to develop technical solutions for the production of high viscosity oil as well as the profitable operation of flooded and low-producing wells. We continued to improve oil gathering and well-productivity accountability measures and to develop efficient depth pumping units and wellhead equipment for producing wells. In addition, we have undertaken an environmental analysis, including assessing the adequacy of our current environmental efforts and the health of the population in the oil-producing areas of Tatarstan in which we operate.

As of December 31, 2002, we held 62 licenses giving us the exclusive rights to produce oil from 68 fields. Our Joint Ventures held nine similar licenses for seven additional oil fields and two subsoil areas, including five in the Republic of Tatarstan (three are held by Tatoilgas, and two by TATEX) and four licenses in the Republic of Kalmykia (held by Kalmtatneft, our joint venture with regional oil producer Kalmneft). Of the nine licenses held by the Joint Ventures, two licenses held by Kalmtatneft and one license held by TATEX were solely production licenses; four were combined exploration and production licenses and two licenses (won by Kalmtatneft at a tender in March 2002) were geological survey, exploration and production licenses. Of our 62 licenses, 33 were solely production licenses, and 29 were combined exploration and production licenses, 6 of which covered 11 fields. Two licenses were provided for the Tat-Kandyzskoe oil field located in the Republic of Tatarstan and the Orenburg region (one is production license for the Republic Tatarstan’s part of the field and the other is combined exploration and production license for the Orenburg region’s part).

Five of the exploration and production licenses allow for exploration with the right to future development on newly discovered fields. Once exploration is completed, however, each field will require a separate development license with specific conditions relating to that field. These licenses were issued in 1995, and cover virtually the entire oil-prospecting region of Tatarstan. These licenses exclude only fields for which specific licenses have already been granted, and are valid for 25 years. However, as we received these licenses without a tender, we may not receive production rights to those oil fields that we discover. There are currently 11 known oil fields within these license areas, including three producing fields and eight fields at the preparatory stage. As of January 1, 2003, we have applied for 12 additional production licenses or additions to existing licenses and three licenses for exploration with rights to future production in Tatarstan, and we believe that we will eventually receive these licenses.

We also currently hold two Russian Federation exploration licenses, valid for five years from the date of issuance, for exploration in the Ulyanovsk region (issued in October 2000) and in the Chuvash Republic (issued in May 2001). Prior to its expiration in October 2002, we held an exploration license for the Orenburg region. The exploration within that license area led to the discovery of the Medovoye oil field and additions to reserves at the Matrosovskoye oil field located in both Tatarstan and the Orenburg region. We have applied for and expect to receive a production license for the Medovoye oil field. In addition, in 2002, the terms of our license for the Matrosovskoye oil field region were expanded to cover exploration as well as production, permitting us to continue exploratory drilling in the Orenburg region.

Most of our existing production and combined exploration and production licenses were issued between 1993 and 1997 under the “grandfather” provisions of the Tatarstan and Russian laws on subsoil use. The production licenses give Tatneft and the Joint Ventures the exclusive right to exploit fields in a defined area and are valid for 20 years, and the combined licenses that allow both exploration and production of crude oil are valid for 25 years. All of the licenses relating to the fields located in Tatarstan held by our Joint Ventures and all but two licenses held by small Tatarstan oil companies were transferred to such entities by Tatneft.

The exploration and production licenses require us to pay certain local and federal taxes and to meet certain environmental requirements. These licenses may be revoked if we fail to comply with their terms or if we fail to heed warnings given by the regulatory authorities.

During the fourth quarter of 1997 and 1998, pursuant to a decree of the Tatarstan government encouraging the development of small new oil fields by newly established companies, we transferred several of our oil fields to such newly established companies. In each case, through this transfer we created new, smaller oil fields located in the territory that is covered by the five special Russian exploration licenses referred to above. As of December 31, 2002, as a result of this process, 21 newly formed oil companies held 59 licenses for 59 small oil fields, including 46 combined exploration and production licenses and 13 production licenses. Some of the newly established companies are majority owned by current and former employees of Tatneft. These companies are not affiliates of Tatneft. Such transfers may not have been made in full compliance with Russian law, which requires that the initial license-holder own over 50% in the legal entity that receives the license and that the new license-holder possesses the equipment necessary to explore the oil field or extract oil.

Due to the special relationship between Russia and Tatarstan, we typically obtain licenses pursuant to both Russian federal law and the laws of Tatarstan. See “Appendix C—The Republic of Tatarstan.” Federal licenses are issued jointly by local and federal authorities.

Information on recent trends in our operations is discussed in “Item 4—Information on the Company—Business Overview—Strategy” and “—Results of Operations” under this Item.

The Joint-Stock Companies Law requires at least a seven-member Board of Directors for an open joint stock company with more than 1,000 holders of ordinary shares, and at least a nine-member Board of Directors for an open joint stock company with more than 10,000 holders of ordinary shares. Our Board currently consists of 15 members. Directors are elected for one-year terms by our shareholders’ meeting and can be re-elected for an unlimited number of terms. If the Board is not elected at the time prescribed under current legislation, the powers of the existing Board terminate and a new shareholders’ meeting has to be convened to elect a new Board. Directors can be removed by a vote of the shareholders’ meeting. The Tatarstan government holds the Golden Share in our company that could allow it to appoint a representative to our Board. However, under Federal legislation, as long as the Tatarstan government holds more than 25% of our share capital, it may not exercise its rights under the Golden Share. As of May 12, 2003, the Tatarstan government held 30.44% of our share capital. See “Item 4—Information on the Company—Relationship with Tatarstan and “Item 7—Major Shareholders and Related Party Transactions.”

As of June 28, 2003, members of the Executive Board of Tatneft who are not also directors are as follows:

Rustam Nurgalievich Minnikhanov. Mr. Minnikhanov was born in 1957. In 1978, he graduated from Kazan Agricultural Institute with a specialization in mechanical engineering, and graduated from the Institute of Soviet Trade in 1985. He started work in 1978 as engineer responsible for diagnostics at Sabinsky District Union of Agricultural Equipment. His further work record has included such positions as Senior and Chief Power Engineer, Sabinsky Forestry Engineering Co. From 1983 to 1985, he was Deputy Director for Trade, Trade Authority, Sabinsky District and from 1985 to 1990 he was Chairman, Arsky Consumer Supplies Board. Then he was elected Chairman of the Executive Committee, Arsky Council of Peoples’ Deputies. In 1992, for one year, he was First Deputy Head of Administration, Arsky District, and from 1993 to 1996, he was Chairman of Visokogorsky District Council of People’s Deputies and then Head of Administration, Visokogorsky District, of the Republic of Tatarstan. From 1996 to 1998 he was Minister of Finance of the Republic of Tatarstan. Since July 1998 he has been Prime Minister of the Republic of Tatarstan. He has served as the Chairman of our Board since June 1998. He holds a degree of Candidate of Science in Economics.

Shafagat Fahrazovich Takhautdinov. Mr. Takhautdinov was born in 1946. In 1971, he graduated from Gubkin Petrochemical and Gas Industry Institute of Moscow. He started work in 1964 as driller’s assistant at Almetyevsk Drilling Operations Department, then worked as oil production operator, underground well repair foreman and manager of a reservoir pressure maintenance section. His other positions have included Chief of the Djalilneft NGDU (1978-1983), Chief of Almetyevneft NGDU (1983-1985), First Secretary of the Leninogorsk City Committee of the Communist Party (1985-1990), and Chief Engineer and First Deputy General Director of OAO Tatneft (1990-1999). Since 1999, he has been our General Director. He holds a degree of Doctor of Economics.

Rishat Fazlutdinovich Abubakirov. Mr. Abubakirov was born in 1959. In 1981, he graduated from Kazan Construction Engineering Institute. After graduation, he served for two years in the Armed Forces. Between 1983 and 1990, he was a Young Komsomol League and then a Communist Party functionary, serving at the Almetyevsk City Komsomol Committee, Tatar Regional Komsomol Committee, and the Almetyevsk City Committee. Between 1990 and 2001, he worked with OAO Tatneft as assistant to the General Director, Head of the PR Department, Chief of Staff, Deputy General Director for Personnel and Social Development. Since July 2001, he has been Head of Almetyevsk Region and City Administration.

Rinat Gimadelishlamovich Galeev. Mr. Galeev was born in 1939. In 1967, he graduated from Ufa Oil Institute with a specialization in mining engineering. Mr. Galeev started work in 1958 as well research operator with the Oil Production Department of Almetyevneft, then he was Secretary of the Communist Party Committee of NGDU, Second and then First

Secretary of the Almetyevsk City Committee of the Communist Party of the Soviet Union, Head of the Almetyevneft NGDU, Deputy General Director of OAO Tatneft. Between 1990 and 1999, he was General Director of OAO Tatneft. Since 1999, he has been Chairman of the Board of Directors of Bank Devon-Credit. He holds a degree of Candidate of Technical Sciences.

Radik Raufovich Gaizatulin. Mr. Gaizatulin was born in 1964. In 1985, he graduated from Kazan Agricultural Institute with a specialization in accounting and economic analysis of agriculture. He started work as chief accountant at the collective farm Mayak, Laishevsky District. Then he worked as the leading economist for control and supervision of the Laishevsky District Cooperative Society, followed by a stint as chief accountant of the agricultural firm Biryuli, Visokogorsky District. In 1999, he was transferred to the Ministry of Finance of the Republic of Tatarstan as Head of the Section for Financing Agriculture and Food Industry, and in June 2000, he was appointed Deputy Minister of Finance of the Republic of Tatarstan. Since June 27, 2002, he has served as Finance Minister of the Republic of Tatarstan. He has been a member of our Board of Directors since 2001.

Nail Gabdulbarievich Ibragimov. Mr. Ibragimov was born in 1955. In 1977, he graduated cum laude from the Gubkin Petrochemical and Gas Industry Institute of Moscow. He first worked as an oil and gas production operator with the Almetyevneft NGDU, and was then promoted to the position of Chief Engineer. In 1999, he was appointed Deputy General Director and Chief Engineer of Tatneft. He has been First Deputy General Director for Production and Chief Engineer of the Company since 2000. He holds a degree of Candidate of Technical Sciences.

Rais Salikhovich Khisamov. Mr. Khisamov was born in 1950. In 1978, he graduated from the Evening Department of Gubkin Petrochemical and Gas Industry Institute of Moscow with a specialization in mining engineering. He started work as an oil production operator at the Oil Production Department of Elkhovneft, then worked as a collector at Birsk Geological Prospecting Unit and operator at the Oil Production Department Irkenneft. In 1972, after serving in the military, he joined Irkenneft NGDU where he worked until 1997 rising from the position of well exploration operator to that of Chief Geologist. Since October 1997, he has been working as Chief Geologist and Deputy General Director of the Company. He holds a degree of Doctor of Geology and Mineralogy.

Vladimir Pavlovich Lavushchenko. Mr. Lavushchenko was born in 1949. In 1972, he graduated from the Moscow Petrochemical and Gas Industry Institute. After serving in the military, he worked as engineer, then as senior engineer and Head of a computing equipment group at the Research and Production Division of the Almetyevneft NGDU. In 1984, he became Head of the Scientific Organization of Work Section of the Yamashneft NGDU, and from 1986 he worked as Deputy Director of the Almetyevneft NGDU for Economic Matters. In April 1995 he was appointed Chief Accountant of OAO Tatneft, and since 1997, he has been Deputy General Director for Economics He holds a degree of Candidate of Economics.

Nail Ulfatovich Maganov. Mr. Maganov was born in 1958. In 1983, he graduated from the Evening Department of the Gubkin Petrochemical and Gas Industry Institute of Moscow. He started work in 1977 at NGDU Elkhovneft where he was gradually promoted from transportation helper to Head of the Oil and Gas Production Division. Between 1991 and 1993, he was Deputy Head of Zainskneft NGDU for capital construction. In 1993, he was transferred to the position of Chief of OAO Tatneft Oil and Oil Products Sales Department. In 1994, he was appointed Deputy General Director of OAO Tatneft for Production. Since July 2000, he has been First Deputy General Director for the Sales and Refining of Oil and Oil Products and Head of the Oil and Oil Products Sales Department.

Renat Halliulovich Muslimov. Mr. Muslimov was born in 1934. In 1957, he graduated from the Kazan State University with a specialization in geology and exploration of oil and gas fields. He started work in 1957 as driller’s assistant with a well development team, and later became Chief of the Geological Section of the Oil Production Department Bugulmaneft and Chief Geologist of the Oil Production Department Leninogorskneft. From 1966 he worked as Chief Geologist and Deputy General Director of Tatneft. Since 1998, he has been State Counsel to the President of the Republic of Tatarstan. He holds a degree of Doctor of Geology and Mineralogy.

Ardinat Galievich Nugaibekov. Mr. Nugaibekov was born in 1947. In 1986, he graduated from Ufa Oil Institute with a specialization in mining engineering and in 1970, he graduated from Kazan State University with a specialization in mechanical engineering. He started work with NGDU “Suleevneft” where he worked as geologist of TsNIPR. For the next six years, he worked as engineer, foreman for the oil and gas production, Head of Shift and Deputy Head of the District Engineer and Technological Service at NGDU “Almetyevneft.” In 1976, he was appointed head of a shop with TsBPO for EPU. Between 1978 and 1981, he was Head of the Industry and Transportation Department of the Almetyevsk City Committee of the Communist Party, then for three years he was Head of the Central Maintenance Base for electric loaders. Since 1984, he has been Head of NGDU Elkhovneft. He holds a degree of Doctor of Technical Sciences.

Albert Kashafovich Shigabutdinov. Mr. Shigabutdinov was born in 1952. Following graduation from Kazan Institute of Aviation in 1976, he started work as a laboratory engineer for Special Construction Enterprise-5 KIS. He then worked as Deputy Director of the state farm “Narmonskiy” and Head of Department and Deputy Director of the Bauman foodstuffs procurement organization in Kazan. In 1986, he became Head of the Repair and Maintenance Enterprise of the Tatrybprom Group. From 1987

to 1991, he served as Deputy General Director of Tatrybprom for Construction, Logistics and Sales. In 1991, he was appointed General Director of the Foreign Trade Research and Production Association “Kazan.” Since 1995, he has worked as General Director of TAIF.

Victor Vasilievich Smykov. Mr. Smykov was born in 1949. In 1971, he graduated from Kazan State University with a specialization in geology and exploration of oil and gas fields. In 1989, he graduated from the Academy for National Economy with the USSR Council of Ministers. He started work in 1971, as a geologist with the Elista geology and prospecting expedition. From 1974-1979, he worked at NGDU Yamashneft as Head Geologist, Head of RITS shift, Head of Research and Production Works, Head of TseDNG. Between 1979 and 1985 he was a Communist Party official, serving first as an instructor and then Head of the Industry and Transportation Department of Almetyevsk City Committee. Since 1985 he has been Head of NGDU Yamashneft. He holds a degree of Candidate of Technical Sciences.

Aleksey Arkadievich Sokolov. Mr. Sokolov was born in 1956. He graduated from Moscow Aviation Institute and Moscow Financial Institute. He started work in 1978. He worked as an engineer at Moscow Thermal Technology Institute, and then as a senior engineer of the State Committee for External Economic Relations of the USSR Council of Ministers. From 1989 to 1993, he headed the Credit and Financial Operations Department of AO Sovfintrade, thereafter serving three years as Deputy Chairman of the Executive Board of KIB Alfa-Bank. Since 1995, he has been Chairman of the Executive Board of Bank Zenit.

Valery Pavlovich Vasiliev. Mr. Vasiliev was born in 1947. He graduated from Kazan Agricultural Institute in 1970 with a specialization in mechanical engineering. He started work in 1970 as a mechanical engineer at the OKS of the Agricultural Department of the Executive Committee of Laishevsky District Council. He then worked in the Laishevsky District as Chief Engineer of Volzhsky state farm, Chairman of Put Ilyicha collective farm and Director of Rossiya state farm. His other positions have included: from 1977-1985 service as a full-time party officer, serving as the Second and First Secretary of the Laishevsky District Committee of the Communist Party and Head of the Agriculture and Food Industry Section of the Tatar Region Committee of the Communist Party. In 1988, he was appointed First Deputy Chairman of the Republic’s State Agricultural Committee and Minister of the Tatar Autonomous Soviet Socialist Republic. He was then appointed First Secretary of the Rybno-Slobodsky District Committee of the Communist Party. From 1989-1995, he worked with the Government of the Republic as First Deputy Chairman of the Council of Ministers of the Tatar Autonomous Soviet Socialist Republic and First Deputy Prime Minister of the Republic of Tatarstan. He was then Head of the Control Department of the President of the Republic of Tatarstan. From 1996-1999, he headed the Ministry for Agriculture and Food of the Republic of Tatarstan. In May 1999, he was appointed Chairman of the State Property Management Committee of the Republic of Tatarstan. Since 2001, he has been Minister for Land and Property Relations of the Republic of Tatarstan.

Viktor Isakovich Gorodny. Mr. Gorodny was born in 1952. In 1978, he graduated with distinction from the Gubkin Petrochemical and Gas Industry Institute of Moscow with a specialization in “Technology and Comprehensive Mechanization of Oil and Gas Field Development.” Mr. Gorodny also graduated from the Higher Communist Party School in Saratov in 1987, from the Business Technology College of the North-Western Extramural Polytechnic Institute in 1993 and from the International Personnel Academy in Kiev, Ukraine, in 1998. Between 1969 and 1984, he worked with the Almetyevneft NGDU in various worker and engineer positions, then served as Secretary of the Communist Party Committee at NGDU Elkhovneft (1984-1985); superintendent of the industrial-transport section of the Almetyevsk City Committee of the Communist Party (1985-1988); and Deputy Head of the Capital Construction Department of the Almetyevneft NGDU (1988-1995). He is a deputy of the Joint Council of the Almetyevsk District of the city of Almetyevsk. Since 1995, he has served as Deputy General Director and Chief of the Property Management Department of Tatneft. He holds a degree of Doctor Economics.

Iskander Gatinovich Garifullin. Mr. Garifullin was born in 1960. In 1981, he graduated from the Kazan Financial and Economic Institute with a specialization in accounting. Between 1981 and 1982, he worked as deputy chief accountant of a mobile unit of the PA Tatneftestroi. Subsequent work includes serving as an accountant at the Construction and Installation Department of the Suleevneft NGDU (1983-1985); chief accountant of a state farm from (1985-1989); Chief Accountant of the Almetyevsk District Agro-Industrial Production Association (1989 to 1991); Chief Accountant of the Almetyevneft NGDU (1991-1997); and Chief Accountant of Tatneft (1997-1999). Since 1999 Mr. Garifullin has served as Chief Accountant and Head of the Accounting and Reporting Department.

Valeriy Dmitrievitch Ershov. Mr. Ershov was born in 1949. In 1978, he graduated from the Kazan State University with the specialization “Jurisprudence.” He started work in 1971 as an adjuster at the Omsk Aviation Plant. From 1972 to 1992 he served in the Ministry for the Interior. His subsequent work record includes serving as Head of the Bureau for Foreign Economic Relations of AO “Alnas” (1992-1995) and Director of OOO “Taurus” (1995-1998). In 1998, he joined Tatneft as Chief of Legal Division and after its reorganization into the Legal Department in 2002 became Chief of Legal Department.

Semyon Afroimovich Feldman. Mr. Feldman was born in 1936. In 1958, he graduated from the Leningrad Mining Institute and received the specialization of mining engineer for development of oil and gas fields. He worked first as an oil production

operator, and then as a production foreman, manager of an oil production section and Deputy Head for Capital Construction at the Prikamneft NGDU. Since 1985, he has served as Deputy General Director for Capital Construction at Tatneft.

Khalit Zagirovich Kaveev. Mr. Kaveev was born in 1955. He graduated from the Kazan Aviation Institute (KAI) in 1978, and received a Ph.D. in Economics from the Academy of National Economy in 1992. After working at KAI, he worked at the Minnibaevsk Oil Refinery from 1979 to 1984. He then worked as an instructor at the Almetyevsk City Committee of the Communist Party, from 1987 serving as Deputy Chairman of the City Council of People’s Deputies and from 1989 as Chairman of the Almetyevsk City Council of People’s Deputies. He has served as Deputy Manager of the joint ventures Tatoilpetro and TATEX since 1992, and was appointed General Director of TATEX in December 1996. Since June of 1999, he has served as Deputy General Director and Chief of the Foreign Economic Department.

Robert Gabdrakhmanovich Khannanov. Mr. Khannanov was born in 1952. He graduated from the Almetyevsk Construction College, in 1971, from the Kazan Engineering and Construction Institute with specialization “Industrial and Civil Construction,” in 1982, and from the Academy for National Economy with the USSR Council of Ministers, in 1988. He started work in 1971 as a foreman at Construction Trust-45. After serving in the Soviet Armed Forces, he returned to Trust-45, continuing to work as a mechanical engineer, and eventually being promoted to foreman. In 1975, he moved to Construction and Assembly Trust No. 8 as an engineer and then as a senior engineer. His subsequent work record includes serving as senior foreman at the Construction and Assembly Company No. 42 (1978-1979); Deputy Head for Production, chief engineer, Head of UMR-1 at the Stroimechanization Trust (1979–1984); chief engineer, then manager of the Construction and Assembly Trust No. 4 (1984-1989); chief engineer, First Deputy Head of Tatneftgasstroi (1989-1995); general Director of branch of TAKPO (1995-1996); General Director of AOOT ART (1996-1997); General Director of OOO RASK (1997-1999); and First Deputy General Director of OOO Tatneft-Nizhnekamsk. In October 2000, he was appointed Deputy General Director of Tatneft.

Rustam Nabiullovich Mukhamadeev. Mr. Mukhamadeev was born in 1952. In 1977, he graduated from the Gubkin Oil Processing and Gas Industry Institute of Moscow, with a degree in “Technological and Complex Mechanization for the Development of Oil and Gas Fields.” In 1970-71, Mr. Mukhamadeev worked as a student operator for Elkhovneft. Following service in the army, he joined the evening department of the Tatarstan branch of the Gubkin Petrochemical and Gas Industry Institute of Moscow as a senior laboratory technician. In 1975, Mr. Mukhamadeev returned to Elkhovneft as an oil-pump research engineer, subsequently becoming a senior geologist at Tatneftegasrazvedka in 1978. His subsequent work includes serving as an instructor in the industrial-transport section of the Almetyevsk City Committee of the Communist Party (1981-1985); Secretary of the Communist Party committee, Assistant Director of Personnel, extra-curricular and social development, Assistant Director for Social Development and Assistant Director for General Operations of NGDU Elkhovneft (1985-1998); and chief of the Almetyevsk repair and construction division of Tatneft (1998-2001). Mr. Mukhamadeev has served as our Deputy General Director for Personnel and Social Development since August 2001.

Rafael Saitovich Nurmukhametov. Mr. Nurmukhametov was born in 1949. In 1974, he graduated from the Ufa Oil Institute with specialization “Technology and Complex Mechanization of the Development of Oil and Gas Fields.” He started work in 1966 as an electrician. After graduation, he worked at NGDU Suleevneft as an oil production operator, technology engineer, foreman for oil production, Head of the Oil and Gas Production Shop, Head of Subterranean and Capital Oil Well Workover. Mr. Nurmukhametov has also served on the Tatar Regional Committee of the Communist Party and as an instructor and Head of the Oil and Gas Production Departments of NGDU Djalilneft (1983-1986), Laseganneft (1986-1989) and Pokachivneft (1987-1989). Since 1989 he has been Chief of NGDU Leninogorskneft of Tatneft.

Rafkat Mazitovich Rakhmanov. Mr. Rakhmanov was born in 1948. In 1970, he graduated from the Ufa Oil Institute with the specialization “Machinery and Equipment for Oil and Gas Fields.” He started his career in 1964 as a car mechanic. After graduation, he worked at NGDU Djalilneft as a laboratory engineer, oil production foreman, Head of the District Engineer Controlling Service, Head of Oil and Gas Production Shop and Head of a Production Department. Due to a change of residence, he became Chief Engineer at the company for well workover. From 1982-1986, he was Head of Oil and Gas Production Shop and then Head of Production Department of NGDU Elkhovneft. In 1986, he was appointed Chief of Almetyevsk Central Base for the Maintenance of Oil Production Equipment. In 2001, he became our Deputy General Director for Oil Well Repair and PNP.

Fyodor Lazarevich Shyelkov. Mr. Shyelkov was born in 1948. In 1972, he graduated from the Moscow Institute of Petrochemical and Gas Industry with a specialization in “Oil and Gas Field Machinery and Equipment.” He started work in 1966 as a driller’s assistant at the directorate Tatburneft. His subsequent work record includes: mechanic, driller’s assistant, senior mechanical engineer with the department Leninogorskburneft (1972-1973); service in the Soviet Armed Forces (1973-1974); mechanic, Deputy Manager, Manager of the Production Servicing Unit, Secretary of the Communist Party Committee of the Leninogorsk Drilling Work Department (1974-1983); Head of the Leninogorsk UPNP and Well Rehabilitation Department (1983-1985); First Deputy General Director of PA Tatneft for Western Siberia (1985-1987); Head of the Department for the Preparation of Process Fluid for Maintaining Reservoir Pressure of PA Tatneft (1987); and as Deputy General Director of PA Tatneft and Head of the Industrial Transport and Special Purpose Equipment Department (1987-1996). Since 1996, he has served as our Deputy General Director for General Matters.

Mikhail Nikolaevich Studenskiy. Mr. Studenskiy was born in 1945. In 1966, he graduated from Oktyabrsk Oil Technical College with a specialization in oil well drilling, in 1972, he graduated from the Ufa Oil Institute. From 1966 until 1997, he has worked in many positions starting from a driller and working up to the Head of Almetyevsk Drilling Works Department. He has served as Deputy General Director for Drilling of Tatneft since January 2000 and as a Deputy General Director and Chief of the Drilling Department since October 2000.

Migrazian Zakievich Taziev. Mr. Taziev was born in 1947. In 1972, he graduated from the Gubkin Petrochemical and Gas Industry Institute of Moscow with a degree in “Machine and Equipment of the Oil and Gas Industry.” In 1965, Mr. Taziev began working as a machinist-repairman in the oil-industrial section of Tyumazineft of Production Association “Bashneft.” From 1966 to 1978, he worked at NGDU Elkhovneft, as a mechanic, a specialist in oil production, and the chief of exchange of the regional engineering-technological service. In 1978 he joined Tatneft, working as the chief of the repair shop and assistant Head of Central Production Services for the repair of electrical loading stations. In 1984 he became assistant Head of construction at Elkhovneft. In 1988, he accepted a position as chief of NGDU Irkenneft. Since January 2001, Mr. Taziev has served as Chief of NGDU Djalilneft.

Evgeniy Alexandrovich Tekhturov. Mr. Tekhturov was born in 1960. In 1982, he graduated from Ordjonikidze Moscow Management Institute with a specialization in “Organization of Management.” After service in the Soviet Armed Forces, he started work in 1984 at NGDU Yamashneft as an engineer. Subsequent positions included: Head of the Labor Organization Section, Head of Labor and Salary Section, Deputy Head of Economic Department, Deputy Head of Economic Department – Chief Accountant. In 1995, he was transferred to the position of deputy Head of the Economic and Finance Department. In 1997, he was appointed Head of Tatneft’s Financial Division. Since 1999, he has as served as the Chief of Financial Department.

Alexander Trofimovich Yukhimets. Mr. Yukhimets was born in 1949. He graduated from the Tatar evening faculty of Gubkin Petrochemical and Gas Industry Institute of Moscow in 1972. He started working in 1966 as a machinist, master in oil production of RITS-1 of NGDU Almetyevneft. After serving in the Soviet Army he worked as an engineer and as Head of Shift of RITS-1. In 1974 he was elected a Deputy Secretary of the Communist Party Committee of NGDU Almetyevneft. From 1976 to 1979, he worked as a Deputy General Engineer on Safety. He was elected Head of the Trade Union of NGDU Almetyevneft in 1979 and Head of the Trade Union of Tatneft in 1985. He served as Deputy Head of NGDU Suleevneft in 1990-1995. Since 1995 Mr. Yukhimets has served as Secretary of our Board of Directors.

Total salaries, bonuses and other gifts paid by Tatneft and its subsidiaries to members of the Board as a group and to executive officers other than members of the Board as a group during 2002 were approximately RR40 million.

In addition, in 2002, we issued and placed to members of our Board and senior management 9,300,000 options to acquire 9,300,000 Ordinary Shares, representing approximately 0.43% of our Ordinary Shares. The options, represented by option certificates, are non-transferable and are exercisable in the period from 270 to 365 days from their placement. Each option entitles its holder to purchase one Ordinary Share at the price of RR9.50, the minimum price of the Ordinary Shares in the two-year period preceding the date the decision on issuance of the option certificates was adopted by our Board of Directors. The option certificates were placed at a subscription price of RR1.00 per certificate starting from September 9, 2002. The weighted average market price of the Ordinary Shares on the Russian Trading System on September 9, 2002 was RR22.62 per share. We acquired Ordinary Shares underlying the options on the secondary market or from our affiliates. Our subsidiary, IFK Solid, acted as the underwriter and placement agent for the issuance of the options, and OAO Aktsionerny Kapital (“Aktsionerny Kapital”), our registrar, acts as the registrar for the option certificates.

The Board has the right to take decisions on all issues pertaining to our activity and internal affairs, except for issues within the competence of the shareholders’ meeting, the General Director or the Executive Board. See “—The General Director” and “—The Executive Board” under this Item.

The following matters are within the competence of the Board, according to the Joint-Stock Companies Law, our Charter and the Provisions on the Board of Directors:

The Board meets whenever necessary, but in general once every month. The Board must hold one meeting at least one month prior to the annual shareholders’ meeting to review Tatneft’s annual report.

Meetings of the Board can be called by the Chairman of the Board or at the request of any other Director, the Revision Committee, the outside auditor or the General Director. The agenda of Board meetings must include any items proposed by the shareholders who own in the aggregate at least 5% of our Ordinary Shares, members of the Board, the Revision Committee, the General Director or the Executive Board.

The Joint-Stock Companies Law and our Charter generally require the affirmative vote of a majority of our directors present at a meeting for an action to pass. A quorum exists if more than 50% of our directors are present. Russian law requires a qualified vote or unanimous vote of all of our directors for certain decisions, such as the approval of major transactions, interested-party transactions, and the issuance of additional shares. The Chairman of the Board casts the deciding vote in the event of a tie.

The minutes of the Board meetings must be accessible for review to any shareholder upon request.

The current Joint-Stock Companies Law prohibits a person from holding the posts of Chairman of the Board and General Director at the same time.

The Joint-Stock Companies Law defines a “major transaction” as a transaction (including a loan, pledge or guarantee) or a series of transactions not in the ordinary course of business and not in connection with the placement of shares or securities

convertible into ordinary shares, involving the acquisition or disposal of assets, the value of which constitutes 25% or more of the balance sheet value of the assets of a company. Major transactions involving assets ranging from 25% to 50% of the balance sheet value of the assets of a company require the unanimous approval of all members of the Board or, in the absence of such approval, the affirmative vote of shareholders holding a majority of the voting shares present at a shareholders’ meeting. Major transactions involving assets in excess of 50% of the balance sheet value of our assets require a three-quarters affirmative vote of shareholders present at a shareholders’ meeting.

The Joint-Stock Companies Law contains special requirements for approval of transactions with interested parties. The definition of “interested parties” includes members the Board, the General Director, members of the Executive Board, any person that owns, together with any affiliates, at least 20% of our Ordinary Shares (for example, Tatarstan or the Tatarstan MLPR) or that may give instructions to us with which we must comply, provided that such person, or that person’s close relatives or affiliates:

We must obtain the approval of one of the following prior to entering into an interested party transaction:

In certain transactions, we failed to comply with this requirement of the Joint-Stock Companies Law. Due to the nature of these transactions and the Board’s ability to ratify actions taken previously, we do not believe that this failure will have a material impact on our financial condition or results of operations.

The General Director is elected by the Board for a five-year term, and can be removed by two-thirds of the Board. The current General Director, Mr. Shafagat F. Takhautdinov, was elected by the Board on June 21, 1999.

The General Director exercises day-to-day control over our activities. The General Director is accountable to the Board and the shareholders. The General Director is authorized, without a power of attorney, to take actions in the name of the Company.

Pursuant to the Charter and the Provisions On the General Director approved by the shareholders on June 28, 2002, competence of the General Director includes the following:

The Executive Board is our collegial executive body. While under the Provisions On the Executive Board approved by the shareholders of directors on June 28, 2002, the Executive Board does not have a fixed number of members, the General Director, the First Deputy General Directors, the Chief Accountant, the Secretary of the Board and the Head of the Legal Department must be among its members. Other members may be appointed by the Board. The Executive Board exercises day-to-day management and control over our activities. Pursuant to the Charter, the Executive Board provides for the execution of the following:

The Executive Board meets when necessary as determined by the General Director, or at the request of one-third of members of the Executive Board, Board of Directors, Revision Committee or the Chairman of the Board of Directors. Meetings of the Executive Board have a quorum if at least one-half of the members are present. All decisions are taken by a simple majority of votes. The Chairman of the Executive Board has the deciding vote in the event of a tie.

The Revision Committee is our financial control body, and is charged with supervising our financial and economic activity. It is accountable to the general shareholders’ meeting. The Revision Committee makes decisions by a majority of votes of its members.

The Revision Committee consists of nine members. The Revision Committee cannot include directors, the General Director or any other of our officers. Revision Committee members serve a one-year term.

The Revision Committee must submit its annual report to the Board at least 40 days prior to each annual shareholders’ meeting.

The Revision Committee can be directed to conduct a special audit by holders of 10% or more of the Ordinary Shares, by the shareholders’ meeting or by the Board. In such case, a report of the Revision Committee must be submitted to the Board not later than one month after the directive.

As of December 31, 2002, together with our principal subsidiaries we had approximately 95,000 employees, of which Tatneft and our wholly-owned subsidiaries (other than agricultural subsidiaries) had approximately 68,555 employees, including

approximately 34,438 that worked in oil production and 6,463 that worked in drilling; Nizhnekamskshina had 14,939 employees; and our banking subsidiaries had 1,273 employees. Tatneft and our wholly-owned subsidiaries had approximately 74,226 and 71,409 employees at December 31, 2001 and 2000, respectively; Nizhnekamskshina had 15,179 and 15,258 employees at December 31, 2001 and 2000, respectively; and our banking subsidiaries had 974 and 757 at December 31, 2001 and 2000, respectively.

We do not expect a significant reduction in the workforce to result from our restructuring program. The reduction in number of employees at Tatneft and our wholly-owned subsidiaries in 2002 is attributable to ordinary attrition and sale of the non-core businesses.

We have adopted a collective labor agreement that applies to all employees, and sets a minimum level of compensation. This agreement is renegotiated annually and the most recent version became effective on January 24, 2003. Each NGDU, however, is entitled to provide additional benefits to its employees if it so chooses. Most employees are members of the Tatneft employees’ union, which acts for those employees in discussions with management. To date, we have not experienced any material labor disputes, strikes or legal actions, and we believe that our relations with our employees are good.

We maintain a pension plan pursuant to the collective labor contract that entitles employees who have worked with Tatneft for more than ten years to receive 7.5% of their average monthly salary plus 0.75% for each year of employment over ten years following their retirement. In 1997, we established a new discretionary pension fund, in which employees who have worked for us for more than ten years may participate. Tatneft pays a portion of the contributions for participants in this plan. At December 31, 2002, there were approximately 31,746 employees participating in the discretionary pension fund. In addition to these pension plans, employees can obtain a number of formal and informal benefits, including bonuses for those who travel frequently, compensation for work-related injuries and losses, and one-time severance pay for workers who are laid off. The liabilities represented by these plans and benefits are not currently material to our financial condition or results of operations. However, the cost of such plans may become significant in the future.

We also have an incentive plan through which we allocate a certain portion of net profits to purchase Ordinary Shares on the secondary market or from our affiliates for distribution under our stock option compensation program. In 2001, we issued options to purchase 9,395,000 Ordinary Shares to members of the Board of Directors and the Executive Board that were exercised in full in 2002. In 2002, we issued further options to purchase 9,300,000 Ordinary Shares to members of the Board of Directors and senior managers. See “—Compensation” under this Item.

No single Director or executive officer owned in excess of one percent of our outstanding capital stock as at May 12, 2003. Moreover, our directors and members of the Executive Board, as a group (30 persons) own less than one percent of our capital stock. The following table sets forth information concerning the beneficial ownership of our shares for all directors and members of the Executive Board as at May 12, 2003.

At May 12, 2003, Tatarstan, through the Tatarstan MLPR, owned 708,194,779 Ordinary Shares, or 30.44% of our capital stock and 32.51% of our Ordinary Shares. At May 12, 2003, 95,939,179 of these shares (or 4.12% of Tatneft’s capital stock and 4.4% of the Ordinary Shares) were held by OAO Central Depositary, a depositary located in Kazan, Tatarstan, as nominee for the Tatarstan MLPR, and 612,255,600 (or 26.32% of Tatneft’s capital stock and 28.1% of the Ordinary Shares) were held by Tatneftekhiminvestholding, an investment company, pursuant to a trust agreement with the Tatarstan MLPR (the “Trust Agreement”). The Trust Agreement provides that Tatneftekhiminvestholding is to manage shares of Tatneft (and other Tatarstan industrial entities placed in its trust) for the purpose of deriving a profit, and also provides that the Tatarstan MLPR may remove its shares from the trust at any time. The Tatarstan MLPR is free to dispose of the Tatneft shares it holds, including any shares it may remove from the trust, at any time, in accordance with the privatization laws of the Russian Federation.

In addition to its ownership of Ordinary Shares, the Tatarstan MLPR owns the Golden Share. However, under current Russian Federation law, the Tatarstan government may not exercise its rights under the Golden Share as long as it holds over 25% of our capital stock. Under Federal law when the holder of the Golden Share holds less than 25% of an enterprise’s capital stock, it then has the power to veto major decisions at meetings of shareholders, including:

Under Tatarstan law, the Golden Share also allows the government to veto the foregoing decisions of the shareholders or the Board, as well as participation of the Company in other legal entities and appointment of the General Director. It is not certain how the inconsistencies between Federal and Tatarstan legislation on the Golden Share would be resolved, were they to be tested in a court. See “Item 3—Risk Factors—Risks Related to Tatarstan—Tatarstan legislation may be inconsistent with Russian legislation, and resolution of these inconsistencies is uncertain.”

The Tatarstan government has announced plans to transfer some or all of our shares that it holds to a newly-formed company, Svyazinvestneftekhim, which will also hold shares of other oil, petrochemicals and telecommunications companies currently owned by the Tatarstan government. In the event of such a transfer, the rights attaching to the Golden Share may become exercisable.

Under both Federal and Tatarstan law, upon its effectiveness the Golden Share also allows the government to appoint one representative of the government to each of our Board of Directors and Revision Committee.

In accordance with the Provisions on the Tatarstan MLPR approved by the Order of the Cabinet of Ministers of the Republic of Tatarstan No. 430, dated July 9, 2001, the Tatarstan government retains its rights under the Golden Share until such time as the Tatarstan MPLR takes a decision to terminate them.

Due to its current ownership of Ordinary Shares, Tatarstan, through the Tatarstan MLPR, may elect members of the Board and influence the direction and future operations of the Company, including decisions regarding acquisitions and other business opportunities, declaration of dividends and issuance of additional shares and other securities even without recourse to the Golden Share.

Our shareholding structure evolved out of the mass privatization program in Russia that began in 1991. Although there have been some changes since 1991 in the authority of various agencies involved, the privatization process has been regulated and supervised by the Federal State Property Management Committee (the “GKI”) or in some regions, such as Tatarstan, by its regional counterparts (for Tatarstan, the Tatarstan MLPR and its predecessors). The privatization program generally required that both management and workers agree on a privatization plan, and that it be approved by the GKI. A plan provided a charter for the new joint-stock company and for the distribution of its shares. Although there were several possible choices, plans generally called for shares to be: (i) given or sold at nominal value or less to management and workers; (ii) sold at tender or auction to third parties; and (iii) held by the state for some specified period of time, often three or five years (with little provision as to what would or could be done with the shares after the specified period). Large blocks of shares (in some cases as much as 51%) were transferred to management and employees. In some cases, workers and management received some shares free of charge (usually Preferred Shares), and were given the right to purchase other shares (usually ordinary voting shares) for nominal value (usually the

price to management) or a discount to nominal value (usually the price to workers). Moreover, during the first two years of the privatization program, workers and management were able to purchase shares using privatization vouchers that were issued free to all Russian citizens in October 1992, and that until near the end of the voucher privatization period in 1994 could generally be purchased at a discount to their nominal value. Finally, workers and management, as well as other Russians and in some cases non-Russians, were able to purchase shares in periodic auctions or tenders held by the GKI.

In the case of Tatneft, the Tatarstan State Property Management Committee (the “Tatarstan GKI”), the legal predecessor to the Tatarstan MLPR, initially owned all of our shares, and then distributed them pursuant to our privatization plan of January 21, 1994 (the “Privatization Plan”). Workers were given Preferred Shares free of charge, although a few were not taken up and were subsequently returned to the Tatarstan GKI. The Tatarstan GKI offered Ordinary Shares representing approximately 30% of the capital stock to workers at 40% of their nominal value, and offered another 5% to management at nominal value. The Tatarstan GKI gave another block of shares to us to use as bonus shares in order to give incentives to workers and management. The Tatarstan GKI sold some shares in domestic auctions. The Tatarstan GKI also transferred a block of 33,000,000 shares to us, which have since been transferred to Tatneft, Solid & Co. and IFK Solid. See “Item 9—The Offer and Listing—Activities of the Company and its Affiliates in the Market.” Finally, the Tatarstan GKI sold Ordinary Shares in a global offering of ADSs, representing the Ordinary Shares, in December 1996. In connection with that transaction, we caused the ADSs to be listed on the London Stock Exchange Limited (the “LSE”) and arranged for the ADSs to be listed on the New York Stock Exchange, Inc. (the “New York Stock Exchange”) in March 1998 and on the NewEx in November 2000.

We have not issued any additional shares since our inception, and the Tatarstan MLPR continues to hold those shares that it has not otherwise distributed pursuant to the Privatization Plan.

On June 27, 1997, a share split was approved at our annual shareholders’ meeting. The FCSM approved this split on April 15, 1998, and it became effective in our share register on April 30, 1998. In conjunction with the issue of the new Ordinary Shares in connection with the share split, the ratio of Ordinary Shares to ADSs was changed from 1/5:1 to 20:1. Each ADS accordingly represents the right to receive twenty post-share split Ordinary Shares.

On June 22, 2001, the annual shareholders’ meeting approved a ten-fold increase of the charter capital. This increase has been accomplished by raising the nominal value of our shares from 10 kopeks to 1 ruble per share. The FCSM registered the share conversion relating to the charter capital increase on November 20, 2001, and the capital increase became effective on December 20, 2001, when the respective amendments to our Charter were registered with the state registration chamber.

The following table sets forth information as of May 12, 2003 regarding the record ownership of Ordinary Shares by shareholders who own more than 5% of such shares and by the directors and executive officers as a group:

OAO UK Nikoil-Sberezheniye, acting in trust for the Fund for Assistance in Comprehensive Research in the Energy Industry, was a registered owner of over 5% of our Ordinary Shares as of May 12, 2003, and TAIF acquired in excess of 5% of our Ordinary Shares in late 1998. We are not currently aware of any arrangements that might result in a future change in control.

The Tatarstan government is our largest shareholder owning 30.44% of our capital stock and 32.51% of our Ordinary Shares and holding the Golden Share. See “—Major Shareholders” under this Item. Currently, five of our directors, including the Chairman of the Board, are senior members of the Tatarstan government, and one of our other directors is the CEO of TAIF, an entity partially owned by the Tatarstan government. In the ordinary course of business, we regularly enter into transactions with other entities that are controlled, either directly or indirectly, by the government of Tatarstan. These enterprises include, among others, Tatenergo, TAIF and Nizhnekamskneftekhim. In addition, the Tatarstan government owns 28.8% of Ukrtatnafta, the owner of the Kremenchug oil refinery in Ukraine and one of the major customers for our high sulfur content crude oil. In 2002, we purchased approximately 16,767 hectares of land underneath most of our properties in Tatarstan from the Tatarstan government for approximately RR330 million.

Transactions are entered in the normal course of business with significant shareholders, directors and companies with which we have significant shareholders in common.

See “Item 18—Financial Statements” and our Consolidated Financial Statements and other financial information included elsewhere in this annual report.

Export sales (outside the CIS) of oil and refined products were RR77854 million, RR80,038 million, RR126,279 million, RR47,352 million and RR21,065 million or 54%, 51%, 63%, 56%, 40% of total revenue for the years ended December 31, 2002, 2001, 2000, 1999 and 1998, respectively.

We are the named defendant in a number of lawsuits as well as the named party in numerous other proceedings arising in the ordinary course of business. None of these proceedings has to date had, individually or in the aggregate, a material adverse impact on us. While the outcome of these suits is uncertain, we are currently neither the subject of nor aware of any pending legal action which, in our opinion, would individually or in the aggregate have a material adverse effect on us.

We may declare annual dividends on the Ordinary Shares and Preferred Shares by resolution of a simple majority of shareholders voting at a shareholders’ meeting, up to the amount recommended by the Board. Under the Joint-Stock Companies Law, we are permitted to pay dividends on Ordinary Shares out of net profits, and dividends on Preferred Shares out of net profits and funds specially designated for such purposes. In either case, these amounts are calculated in accordance with RAR. This legislation and other statutory laws and regulations dealing with distribution rights are open to interpretation. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company.” Our Charter requires us to declare an annual dividend to holders of Preferred Shares equal to 100% of the nominal value of Preferred Shares (unless otherwise decided by the shareholders). However, if a dividend declared on the Ordinary Shares is greater than 100% of the nominal value of the Preferred Shares, holders of the Preferred Shares are entitled to receive a dividend of value at least equal to the dividend declared on the Ordinary Shares. The net income (loss) per Ordinary Share calculations consider this entitlement to dividends for the preferred shareholders through the use of the two class calculation method. Under this method, net income is reduced by the amount of dividends on the Preferred Shares and the amount of imputed additional dividends that are necessary to ensure that the preferred shareholders do not receive a dividend amount per Preferred Share that is inferior to that received by each common shareholder. Certain of our loan agreements also restrict our ability to pay dividends in excess of our net profits for the financial year for which the dividend is paid, as calculated in accordance with RAR.

The amount of any future dividends will depend on our results of operations, cash requirements and other factors. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company.” Reserves available for distribution to shareholders are based on statutory accounts prepared in accordance with RAR, which differ from U.S. GAAP.

Owners of ADSs are entitled to receive any dividends to which the Ordinary Shares represented by their ADSs are entitled. Cash dividends are paid to the Depositary in rubles and, except as otherwise provided in the Deposit Agreement between us and the Depositary relating to the ADSs, are converted by the Depositary into U.S. dollars and distributed to owners of ADSs. Under certain circumstances, dividends may be subject to withholding tax. See “Item 10—Additional Information—Taxation” for a discussion of the tax consequences for owners of ADSs of the payment of dividends by Tatneft. Fluctuations in the value of the ruble against the U.S. dollar will affect the U.S. dollar amount of any dividends received by the holders of the ADSs.

At its March 2003 meeting, our Board approved the issuance of RR1.5 billion in ruble-denominated bonds on the domestic Russian market. The Russian Federal Commission on the Securities Market registered the issuance on June 11, 2003. We plan to place these bonds in the second half of 2003.

At their June 11, 2003 annual shareholders’ meeting, the shareholders of our principal petrochemicals subsidiary Nizhnekamskshina approved a ten-fold capital increase to be distributed by closed subscription among Nizhnekamskshina shareholders in proportion to their stakes. We intend to subscribe for this capital increase in full in proportion to our holding in Nizhnekamskshina.

On June 12, 2003, our subsidiary Bank Zenit entered into a credit facility agreement (the “Credit Facility”) with WestLB AG (“WestLB”) in the amount of US$125 million, bearing interest at 9.25%, payable semi-annually. Simultaneously, WestLB issued US$125 million of 9.25% notes due in June 2006 (the “Notes”). WestLB loaned the proceeds from this issuance to Bank Zenit under the Credit Facility. Payments made by Bank Zenit under the Credit Facility fund WestLB’s payment obligations under the Notes. As part of this series of transactions, Bank Zenit has guaranteed the obligations of WestLB under the Notes.

Other than as disclosed above or elsewhere in this annual report, no significant changes have occurred since the date of our most recent audited financial statements.

Our ADSs are listed on the New York Stock Exchange, the London Stock Exchange and the NewEx trading segment of the Frankfurt Stock Exchange. Following our listing on the New York Stock Exchange in March 1998, our ADSs have been trading on the Berlin, Munich, Stuttgart, Hamburg and Dusseldorf stock exchanges. Since the integration of NewEx Börse AG into the Deutsche Börse AG in 2002, our ADSs have also been trading on the Xetra trading system of the Deutsche Börse. Our Ordinary Shares are traded on the RTS and are listed on the Moscow Stock Exchange.

The principal trading markets for the ADSs are the New York Stock Exchange and the London Stock Exchange. The ADSs were admitted to the Official List of the LSE in December 1996 and were listed on the New York Stock Exchange on March 30, 1998.

The following table shows, for each period indicated, the reported closing highest and lowest middle market quotation for the ADSs on the New York Stock Exchange.

The following table shows, for each period indicated, the reported closing highest and lowest middle market quotation for the ADSs on the LSE as derived from the Daily Official List of the LSE.

In June 1996, we launched a program, registered with the Securities and Exchange Commission, for ADRs representing Ordinary Shares or rights to receive Ordinary Shares. In December 1996, we established two unregistered American depositary receipt programs (the “Restricted ADR Program” and the “Regulation S ADR Program”) in connection with an international offering of certain of our Ordinary Shares in the United States and elsewhere pursuant to Rule 144A and Regulation S under the Securities Act. In March 1998 we merged these two ADR programs into one registered ADR program (the “Registered ADR Program”) in connection with listing the ADRs on the New York Stock Exchange. We also exchanged ADRs issued under the Restricted ADR Program for ADRs issued under the Registered ADR Program, and we formally abolished the Restricted ADR Program in 1999. According to the records of the Depository Trust Company, as of May 12, 2003 there were 30 registered and 1,275 beneficial U.S. holders of 19,878,529 ADRs under the Registered ADR Program. In the aggregate, these holdings constitute approximately 18.25% of our total issued Ordinary Shares, and approximately 17.09% of our capital stock. Since brokers and other nominees hold certain of the ADRs, the above numbers may not represent the actual number of U.S. beneficial holders or of Ordinary Shares or ADRs beneficially held by U.S. persons.

In April 2003, the FCSM issued a regulation providing that deposit of shares of a Russian company into ADR programs requires its permission. Such permission may be denied if more than 40% of the class of shares eligible for deposit into the ADR program will circulate outside Russia or if the ADR program contemplates the voting of the shares underlying the ADSs other than in accordance with the instructions of the ADS holders. Our ADR program has no express limitations on the deposit of our Ordinary Shares into the program, and it contemplates that, in the absence of instructions from ADS holders, the depositary will give a proxy to vote the shares underlying such ADSs to our representative. It is uncertain as to whether the new FCSM regulation applies to ADR programs into which additional shares have been deposited exceeding the aggregate number of shares in the ADR program at the time of enactment of the regulation, or only to ADR program established after the time of its enactment. Furthermore, the new FCSM regulation does not specify the consequences of the violation of the regulation. We have not obtained FCSM permission for our ADR program. An assertion that the new FCSM regulation applies to our ADR program could have a material adverse effect on the market price of our Ordinary Shares or ADSs.

Trading in Ordinary Shares within Russia has grown significantly since 1996. The primary market for the Ordinary Shares is the RTS, a screen-based over-the-counter trading system. The Ordinary Shares were first quoted on the RTS on October 17, 1995.

The following table shows, for each period indicated, the reported highest and lowest denominated middle market prices for the Ordinary Shares on the RTS. These prices were reported in rubles, and have been converted to U.S. dollars at the exchange rate in effect as the date of such quotation.

Generally accepted public indications of trading volumes in Tatneft’s shares are not available. The Ordinary Shares and Preferred Shares are also listed on the Moscow Stock Exchange, but there has been no trading in the Ordinary Shares and Preferred Shares on that exchange.

At May 12, 2003, Tatarstan held approximately 30.44% of our capital stock and 32.51% of the Ordinary Shares through the Tatarstan MLPR. The Tatarstan MLPR is free to dispose of its Ordinary Shares at any time.

Both we and our affiliates, including directors, management, and affiliated broker-dealers and financial institutions, have in the past been active in the market for Ordinary Shares. This activity is likely to continue in the future. Russian residents generally find it difficult or impossible to participate in the ADS market due to currency exchange restrictions. See “Item 10—Additional Information Exchange Controls.”

On March 18, 1997, Tatneft, IFK Solid, a Russian broker-dealer that we control, and Zenta, a limited partnership controlled by Bank Zenit, formed a limited partnership, Tatneft, Solid & Co. (the “LP”). The LP was formed in order to acquire unrestricted Ordinary Shares and rights to acquire Restricted Ordinary Shares as those shares became unrestricted. The Restricted Ordinary Shares were the Ordinary Shares that were subject to restrictions on transfer for what was originally a three-year period subsequent to their transfer out of state ownership. By May 2001, all such restrictions were lifted and all of our Ordinary Shares became freely tradeable. One reason for the establishment of the LP was to control the flow of Restricted Ordinary Shares into the market as the restrictions on resale expired. See “—The Ordinary Share Market” under this Item.

Tatneft, IFK Solid and Zenta are the LP’s general partners, holding general partnership interests of 51%, 25% and 24%, respectively. At June 8, 2003, there were 83 limited partners, mainly Tatneft employees (including our directors and executive officers), who generally contributed unrestricted Ordinary Shares to the LP in exchange for their limited partnership interests. The general partners are entitled to 20% of the LP’s net income, and the limited partners to 80%. Each general partner and limited partner shares in the net income allocable to its class pro rata to its contribution to the LP. At May 12, 2003, the LP held 26,171,765 Ordinary Shares. See “—The Ordinary Share Market” under this Item.

IFK Solid began to actively participate in the market for the Ordinary Shares from September 19, 1996. IFK Solid was acquired in 1996 by a group that included Tatneft and several affiliated and non-affiliated companies, and it continues to participate actively in the market for our shares.

Overall, at December 31, 2002, approximately 200,288,000 Ordinary Shares were held by our subsidiaries and classified as treasure stock under the U.S. GAAP, compared to approximately 176,133,000 Ordinary Shares at December 31, 2001 and approximately 66,575,000 Ordinary Shares at December 31, 2000. Under Russian law, shares held by subsidiaries may vote and receive dividends.

Our share register is currently held by Aktsionerny Kapital, which holds both federal and Tatarstan licenses to act as a share registrar. In the case of trades of Tatneft shares that involve licensed Russian broker-dealers, a transaction will ordinarily be registered by Aktsionerny Kapital solely on the basis of a transfer order. In the case of a transaction in which neither party is a licensed broker-dealer, additional documentation—including a transfer order, signature verifications and properly executed

powers-of-attorney—is required. To facilitate trading, Aktsionerny Kapital has departments that act as transfer agents in Moscow and Kazan. These arrangements ordinarily obviate the need for traders in Moscow and Kazan to travel to Almetyevsk to execute a trade. The registrar generally charges the maximum rates permitted by Russian law for various registrar actions. The maximum rates for these transactions currently include: (i) for opening an account, RR10 (approximately US$0.33 at June 1, 2003); (ii) for registration of a transaction, 0.2% of the transaction price; (iii) for amendments or additions to the information on a registered person, RR30 (approximately US$0.98 at June 1, 2003); and (iv) for issuing an extract from the share register, RR10 (approximately US$0.33 at June 1, 2003).

Aktsionerny Kapital is a member of PARTAD, the Russian professional organization of share registrars, transfer agents and depositories. It follows PARTAD guidelines for keeping share registers. It keeps reserve copies of the computerized register in a bank vault, as well as copies of extracts from the register. Aktsionerny Kapital also makes periodic backups of the share register.

Aktsionerny Kapital was established as an open joint-stock company in December 1996 and received capital contributions from five entities, including Tatneft and Bank Devon-Credit. We have been informed that Aktsionerny Kapital plans to expand its operations to act on behalf of other companies in Tatarstan. At June 1, 2003, it acted as share registrar for more than 200 companies.

The FCSM regulations currently require that the share register of any Russian company with more than 500 shareholders, such as Tatneft, be held by a specialized registrar and that such company not own more than 20% of the registrar’s share capital. The FCSM regulations also generally prohibit (with a few exceptions) a specialized registrar from carrying out any activities other than those of a share registrar, and require that the specialized registrar obtain a license from the FCSM. We currently own approximately 4.51% of the share capital of Aktsionerny Kapital and through Bank Devon-Credit currently hold an additional 1.97% of the share capital of Aktsionerny Kapital.

To the best of our knowledge and that of Aktsionerny Kapital, there has never been any accusation that either Tatneft or its share registrar has wrongfully failed to effect a transfer of shares on the Tatneft share register, or that a shareholder has been wrongfully deleted from the register.

Tatneft is a Russian Open Joint-Stock Company. Tatneft’s affairs are governed by the Joint-Stock Companies Law, as amended, the Tatarstan Privatization Law, the Charter, as amended from time to time, most recently on June 27, 2003 (the “Charter”), and Provisions On the Executive Board, Provisions On the Board of Directors, Provisions On the General Director and Provisions On the Revision Committee, each as approved by the shareholders at the June 28, 2002 annual shareholders’ meeting.

Section 3 of our Charter states that the principal objective of our activities shall be the receipt of profit, particularly through exploration, drilling, and development of oil and gas deposits. In pursuing these objectives, we may pursue a wide range of activities, including operation of oil refineries, gasoline stations, and accompanying maintenance, operations and research.

Our Board of Directors consists of 15 members elected by cumulative voting at the annual shareholders’ meeting held this year on June 27, 2003. The term of office of a Director is one year. In cumulative voting, a shareholder may cast a number of votes for one or more nominees for the Board equal to the number of voting shares held by such shareholder multiplied by the number of directors to be elected.

The quorum of the Board exists if a majority of directors are present at a meeting of the Board, and decisions must generally be taken by a majority vote of directors present at such a meeting. Pursuant to the Joint-Stock Companies Law, an interested party transaction involving, whether directly of indirectly, one of our directors must be approved by the disinterested directors or by a majority of our shareholders. See “Item 6—Directors, Senior Management and Employees—Board Practices—Approval of Interested Party Transactions.”

Our authorized capital consists of 2,178,690,700 Ordinary Shares, nominal value RR1.00 per share, and 147,508,500 Preferred Shares, nominal value RR1.00 per share.

Our Board of Directors recommends the payment of annual dividends to our shareholders, who approve such annual dividends by a majority vote at the annual shareholders’ meeting. The annual dividend approved at the shareholders’ meeting may not be more than the amount recommended by the Board. Annual dividends are distributed to shareholders entitled to participate in the annual shareholders’ meeting. Dividends are not paid on treasury shares. Amendments to our charter approved at the June 27, 2003 shareholders’ meeting will, when they are registered and become effective, permit us to pay quarterly dividends.

Holders of Preferred Shares are entitled to a dividend of 100% of the nominal value of their shares unless otherwise decided by the shareholders’ meeting. However, if a dividend declared on the Ordinary Shares is greater than 100% of the nominal value of the Preferred Shares, holders of the Preferred Shares are entitled to receive dividend of at least equal value to the dividend declared on the Ordinary Shares. Dividends are paid to shareholders’ accounts at Bank Devon-Credit or Bank Zenit.

Under the Joint-Stock Companies Law, we are permitted to pay dividends on Ordinary Shares out of net profits and dividends on Preferred Shares out of net profits and funds specially designated for such purposes. In either case, these amounts are calculated in accordance with RAR. The following conditions also have to be met for dividends to be paid:

Our Charter also establishes a mandatory reserve fund equivalent to 5% of the charter capital, with annual contributions of 5% of net income until this amount has been reached. This fund may only be used to cover losses, to redeem bonds, and to repurchase shares when other funds are not available.

Each fully paid Ordinary Share, except for treasury shares, gives its holder the right to participate in shareholders’ meetings and vote on matters to be decided thereby. Holders of Preferred Shares are generally not entitled to vote at the shareholders’

meetings. However, both the Charter and the Joint-Stock Companies Law entitle preferred stockholders to vote on changes and additions to the Charter where such changes provide for reorganization or liquidation of the Company, limitation of their rights, including the issuance of preferred shares with broader rights than those of the existing preferred shares, or change the amount of dividend on the Preferred Shares. Holders of preferred shares are also entitled to vote at the shareholders’ meeting on any items that may appear on the agenda in the event that we fail to pay a dividend on Preferred Shares.

We are required by the Joint-Stock Companies Law to hold a general shareholders’ meeting at least once a year between March 1 and June 30 of each year, and the agenda must include the following items:

A shareholder or a group of shareholders owning in the aggregate at least two percent of our issued voting shares may submit proposals to the agenda of the annual shareholders’ meeting and may nominate candidates to serve as members of our Board or Revision Committee. The shareholders must provide their agenda proposals or nominations to us within 30 calendar days of the end of the fiscal year preceding the annual shareholders’ meeting, i.e. by January 30.

Extraordinary shareholders’ meetings may be called by the Board at its own initiative to consider matters within the competence of the general shareholders’ meeting, as well as upon written request by the Revision Committee, our external auditor or shareholders owning not less than 10% of our Ordinary Shares in the aggregate as of the date of such request. The Board must then consider the request, and, if approved, schedule the meeting not more than 40 days from the date of receipt of the request or 70 days from the date of receipt of the request if the proposed agenda includes the re-election of the Board by way of cumulative voting.

The quorum for a shareholders’ meeting constitutes presence in person or through authorized representatives of holders of more than 50% of our voting shares. If the quorum requirement is not met, another shareholders’ meeting must be scheduled, in which case the quorum requirement is met if shareholders owning at least 30% of the issued voting shares have registered at that meeting. Shareholders may participate in meetings by proxy, provided that the proxy holds a power of attorney issued by the shareholder.

All our shareholders entitled to participate in a shareholders’ meeting must be notified of a meeting no less than 20 days prior to the date of the meeting. However, if reorganization of the Company is an agenda item, shareholders must be notified at least 30 days prior to the date of the meeting, and if it is an extraordinary shareholders’ meeting to elect our Board by cumulative vote, shareholders must be notified at least 50 days prior to the date of the meeting. The record date shareholders’ meeting set by the Board. The record date may not be (i) earlier than the date of adoption of the resolution to hold a shareholders’ meeting and (ii) more than 50 days before the date of the meeting. In the case of an extraordinary shareholders’ meeting to elect our Board, the record date must be within 65 day period proceeding to the meeting.

Under Russian legislation, the liquidation of a company results in its termination without the transfer of rights and obligations to other persons as legal successors. Tatneft may be liquidated by a three-quarters vote of our shareholders at a shareholders’ meeting or by a court order.

Following a decision to liquidate, the right to manage our affairs would pass to a liquidation committee. In case of a voluntary liquidation, shareholders appoint the members of the liquidation committee at a shareholders’ meeting. The court appoints members of the liquidation committee in the case of an involuntary liquidation. Creditors may file claims within a period to be determined by the liquidation committee, but which must be at least two months from the date of publication of the notice of liquidation by the liquidation committee.

The Civil Code sets the following order of priority among creditors in a liquidation:

The remaining assets are distributed among shareholders in the following order of priority:

There are currently no restrictions under the Charter or under Russian or Tatarstan law that limit the right of non-Russian residents or persons to own or vote our shares either directly or through an ADR program. However, under an FCSM regulation, a deposit of shares of a Russian company into an ADR program requires permission of the FCSM. Such permission may be denied if more than 40% of the class of shares eligible for deposit into the ADR program will circulate outside Russia or if the ADR program contemplates the voting of the shares underlying the ADSs other than in accordance with the instructions of the ADS holders. Our ADR program has no express limitations on the deposit of our Ordinary Shares into the program, and it contemplates that, in the absence of instructions from ADS holders, the depositary will give a proxy to vote the shares underlying such ADSs to our representative. There is uncertainty as to whether the FCSM regulation on this subject matter applies to ADR programs in existence at the time of its enactment, or to ADR programs into which further shares have been deposited since the time of its enactment, or only to ADR program established after the time of its enactment. Furthermore, such FCSM regulation does not specify the consequences of the violation of the regulation. We have not obtained FCSM permission for our ADR program. An assertion that the new FCSM regulation applies to our ADR program could have a material adverse effect on the market of our Ordinary Shares or ADSs. See “Item 3—Key Information—Risk Factors—Risks Relating to an Investment in our ADSs.”

Approval of the Ministry of Antimonopoly Policy and Support of Entrepreneurship of the Russian Federation

Pursuant to the Russian antimonopoly legislation, any transaction that would result in a person (including companies or individuals of its group, as defined by antimonopoly legislation) holding 20% or more of our issued voting shares must be approved in advance by the Ministry of Antimonopoly Policy and Support of Entrepreneurship of the Russian Federation.

The Joint-Stock Companies Law grants existing shareholders a preemptive right to purchase shares or securities convertible into shares that we propose to sell in a public offering. In a private placement of shares or securities convertible into shares, shareholders who voted against it or did not vote on such private placement are entitled to acquire an amount of such shares or convertible securities proportionate to their existing stake. This rule does not apply when the shares are placed solely among existing shareholders if all such existing shareholders are entitled to acquire new shares in proportion to their existing holdings. We must notify shareholders in writing of the proposed sale of securities at least 45 days prior to the offering. Within this 45-day period the shareholders may exercise their preemptive rights. If a shareholder elects to exercise preemptive rights to purchase securities, and the amount of securities that is proportionate to its existing stake is not a whole number, then such shareholder would be entitled to receive fractional securities.

In accordance with the Provision of the Tatarstan MLPR approved by the Order of the Cabinet of Ministers of the Republic of Tatarstan No. 430, dated July 9, 2001, the Tatarstan government retains its rights under the Golden Share until such time as the Tatarstan MLPR takes a decision to terminate them. The Golden Share gives the Tatarstan government the power to veto certain major decisions, including our liquidation or reorganization (i.e. mergers). See “Item 7—Major Shareholders and Related Party Transactions—Major Shareholders.”

Russian legislation requires that any person intending, either alone or in concert with affiliates, to acquire more than 30% of our Ordinary Shares, including shares already held by such person, must notify us in writing of its intention to acquire the shares at least 30 days, but in any event not more than 90 days, before such acquisition.

Additionally, within 30 days of any such acquisition, the acquiring shareholder must offer to buy all of the issued Ordinary Shares and securities convertible into Ordinary Shares, if any, at their market price, which should not be less than the weighted-

average acquisition price of the Ordinary Shares over the six months before the date of the acquisition. The same requirement applies at each five percent increment over the initial 30% threshold. Shareholders holding a majority of the issued Ordinary Shares present at a shareholders’ meeting, excluding the vote of the person acquiring shares and that person’s affiliates, may elect to waive this requirement. Alternatively, our Charter may contain a provision waiving this requirement. Currently, our Charter does not contain a waiver of, and our shareholders have not waived, this mandatory offer requirement. If the acquiring person fails to make the required offer, it may vote only those shares that have been acquired in accordance with the above procedures.

Other than the loan agreements with foreign lenders described under “Item 5—Operating and Financial Review and Prospects—Liquidity and Capital Resources” and contracts we enter into in the ordinary course of business, we have not entered into any contracts in the past two years that may be material to our operations.

Russia currently follows relatively strict policies regarding foreign currency transfers out of Russia. Nonetheless, payments in U.S. dollars (or other foreign currencies) may generally be made between a Russian resident and a non-resident for “current” transactions. Current transactions include transfers in and out of Russia for foreign currency for payments on import and export of goods and services without deferral of settlement, as well as payments in connection with credits on import-export operations with a term not exceeding 90 days; receipt and extension of financial credits with a term not exceeding 180 days; and transfers in and out of Russia of interest, dividend payments and other income on deposits, investments, credits and other similar transfers in connection with “capital” transactions and certain other payments specified by law. All other currency transactions are classified as “capital” transactions, which generally require a license from the Central Bank, subject to certain specified exceptions. Cash transactions in foreign currency are generally prohibited within Russia. Permissible payments in foreign currency must be made by means of wire transfers.

Russian exporters are required to repatriate 100% and convert into rubles 50% of foreign currency export proceeds. Like other Russian companies, we are required to convert up to 50% of all hard currency earnings into rubles unless we obtain an exemption. On June 20, 2003, the State Duma passed a bill that, if approved by the Federation Council and President, will reduce the amount of foreign currency export proceeds that must be converted into rubles to 30%. Under this bill, the Central Bank would also be authorized to set a lower limit.

Russian resident companies may exchange rubles for foreign currency if they can document “current” foreign currency transactions (including payments of interest and dividends), if they engage in “capital” foreign currency transactions not requiring authorization from the Central Bank or if they have authorization from the Central Bank to engage in “capital” foreign currency transactions. Non-resident companies may convert foreign currency into rubles, but may only do so through special ruble accounts, which are subject to strict regulations and close control by the Central Bank of the Russian Federation.

Restrictions on the remittance of dividends, interest or other payments to non-residents

The Federal Law on Foreign Investments in the Russian Federation specifically guarantees foreign investors the right to repatriate their earnings from Russian investments. However, the Russian exchange control regime may materially affect your ability to do so.

Under Russian currency control laws, ruble dividends on the Ordinary Shares may be paid to the Depositary (or its nominee) and converted into U.S. dollars by the Depositary for distribution to owners of ADSs without restriction. Moreover, ADSs may be sold by a non-resident of Russia for U.S. dollars outside Russia without regard to Russian currency control laws so long as the buyer is not a Russian resident.

Under the terms of the Deposit Agreement, to which we, the Depositary, and the registered owners of ADRs and the owners of a beneficial interest in book-entry ADRs are parties, ADSs may be sold in Russia to Russian residents without restrictions. However, Russian currency control laws limit the ability of a non-residents of Russia to sell ADSs or Ordinary Shares in Russia to

a Russian resident. Russian residents generally must purchase securities for rubles (unless they obtain a Central Bank license), and rubles may not lawfully be transferred out of Russia. Moreover, Russian residents generally may not purchase foreign-currency denominated securities, such as the ADSs, without a license from the Central Bank. In order for a non-resident of Russia to repatriate the ruble proceeds from a sale of securities in Russia, the ruble proceeds must first be converted into U.S. dollars (or another hard currency) through special “K” accounts opened at a bank in Russia. A non-resident of Russia who intends to sell ADSs or Ordinary Shares in Russia will be required to open such an account in order to repatriate the proceeds of such a sale. These arrangements, together with applicable conversion fees and limitations on immediate repatriation, may increase the costs of such repatriation. Furthermore, weaknesses in the existing banking infrastructure may limit the actual transfer within, and the remittance of funds out of, Russia.

The ability of the Depositary and other persons to convert rubles into U.S. dollars (or another hard currency) is also subject to the availability of U.S. dollars (or such other hard currency) in Russia’s currency markets. Although there is currently a market within Russia for the conversion of rubles into U.S. dollars and other foreign currencies, including the interbank currency exchange and over-the-counter and currency futures markets, this market may not continue to exist in its present or a substantially comparable form in the future. At present, there is no market for the conversion of rubles into foreign currencies outside of Russia and no viable market in which to hedge ruble-currency and ruble-denominated investments.

The following discussion summarizes certain potential material United States federal and Russian income tax consequences for holders of our ordinary shares or ADSs. The discussion which follows is based on (a) the United States Internal Revenue Code of 1986, as amended, which is referred to in this summary as the “Code,” the U.S. Treasury regulations promulgated there under, and judicial and administrative interpretations thereof, (b) Russian law and (c) the Convention between the United States of America and the Russian Federation for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Income and Capital, which, for the purposes of this summary, is referred to as the “U.S./Russia Double Tax Treaty,” all as in effect on the date hereof, and as subject to any changes (possibly on a retroactive basis) in these or other laws occurring after such date. It is also based, in part, on representations of the Depositary, and assumes that each obligation in the deposit agreement and any related agreements will be performed in accordance with its terms.

The discussion which follows is intended as a descriptive summary only and is not intended as tax advice to any particular investor. It is also not a complete analysis or listing of all potential United States federal or Russian income and withholding tax consequences to a prospective holder of our ordinary shares or ADSs. Each prospective investor is urged to consult its own tax adviser regarding the specific United States federal, state, and local and Russian tax consequences of the ownership and disposition of our ordinary shares or ADSs.

The following is a summary of certain Russian tax considerations regarding the purchase, ownership and disposition of our ordinary shares or ADSs. The summary is general in nature and is based on the laws of the Russian Federation in effect as at the date of this prospectus. The summary does not seek to address the applicability of any double tax treaty relief. In this regard, however, it is noted that there may be practical difficulties involved in claiming double tax treaty relief. Investors should consult their tax advisors with respect to the consequences of an investment in the ordinary shares or ADSs arising under the legislation of the Russian Federation or any political subdivision thereof. Please see “Item 3—Key Information—Risk Factors—Risks Relating to the Company—The Russian tax system imposes substantial burdens on us and is subject to frequent change and significant uncertainty.” Under no circumstances should the descriptions set forth below be viewed as tax advice.

The Russian tax rules applicable to securities, and in particular those held by Non-Resident Holders, are characterized by significant uncertainties and by an absence of interpretative guidance. Russian tax law and procedures are not well developed and rules are sometimes interpreted differently by different tax inspectorates and inspectors. In addition, both the substantive provisions of Russian tax law and the interpretation and application of those provisions by the Russian tax authorities may be subject to more rapid and unpredictable change than in a jurisdiction with more developed capital markets. The relevant chapters of Part II of the Tax Code that set out the regulatory framework for taxation of the income of individuals and the profits of Russian and foreign legal entities do not regulate all issues arising in connection with the purchase, ownership, and disposition of ordinary shares or ADSs by Non-Resident Holders. In particular, the Russian tax authorities have not provided any guidance regarding the treatment of ADS arrangements.

For the purposes of this summary, a “Non-Resident Holder” means: a physical person, physically present in the Russian Federation for less than 183 days in a given calendar year; or a legal person or entity not incorporated or otherwise organized in the Russian Federation (with no tax registration in Russia), which holds and disposes of our ordinary shares or ADSs other than through a permanent establishment in Russia. Russian income tax obligations of a Non-Resident Holder may arise with respect to

income from a Russian source. Russian tax law does not provide a general definition as to what constitutes Russian source income, however, specific types of income, including dividends and capital gains on disposal of shares in certain Russian companies, are referred to as Russian source income for both individual and corporate Non-Resident Holders.

Generally, Russian income tax of a Non-Resident Holder with respect to income from Russian sources will be collected via a withholding mechanism. The obligation to withhold income tax of a Non-Resident Holder lies with a tax agent. Under Russian tax law, a tax agent may be either a Russian company or a foreign company carrying on business through a permanent establishment (taxable presence) in Russia. In practical terms, a tax agent is either a company paying dividends or a purchaser of ordinary shares or ADSs. There is no obligation for a Russian resident individual or a foreign company with no presence in Russia to withhold Russian income tax of a Non-Resident Holder.

Dividends paid to a Non-Resident Holder are generally subject to Russian income tax, which will be withheld by us as a tax agent, at a 15% rate for legal entities and at a 30% rate for individuals.

This tax may be reduced under the terms of a double tax treaty between Russia and the country of residence of the Non-Resident Holder. For example, the U.S./Russia Double Tax Treaty provides for reduced rates of withholding on dividends paid to holders that are Eligible U.S. Holders (as defined below) that are entitled to U.S./Russia Double Tax Treaty benefits; a 5% rate applies to Russian source dividends paid to Eligible U.S. Holders that are corporate legal entities owning 10% or more of the Russian entity’s outstanding shares and a 10% rate applies for all other Eligible U.S. Holders. See “ Procedure for obtaining double tax treaty relief.”

For the purposes of this summary, “Eligible U.S. Holder” means a U.S. person that is a beneficial owner of an ADS or ordinary share and of the cash dividends paid thereon that satisfies all the following conditions: the holder (i) is a resident in the United States for the purposes of the U.S./Russia Double Tax Treaty and (ii) holds the ordinary shares or ADSs in a manner not effectively connected with a permanent establishment in the Russian Federation through which such U.S. person carries on business activities or with a fixed base in the Russian Federation from which such U.S. person performs independent personal services.

However, double tax treaty relief may not be available to U.S. or other Non-Resident Holders of ADSs because of the absence of any interpretative guidance on the beneficial ownership concept in Russia and the fact that the depositary (and not the holders of the ADSs) is the legal holder of our ordinary shares under Russian law. In the absence of any clarification from the Russian tax authorities on the application of relevant double tax treaties, we are unlikely to be able to apply the reduced rates and will have to withhold income tax at the applicable rates under Russian domestic law on dividends payable to U.S. or other Non-Resident Holders.

Tax implications may differ upon disposal of either ADSs or our ordinary shares by a Non-Resident Holder that is a legal entity.

In the case of ADSs, a Non-Resident Holder, that is a legal entity, generally should not be subject to any Russian income tax in connection with the sale, exchange or other disposition of ADSs outside Russia. The Russian Tax Code provides that capital gains realized by non-resident legal entities from sales of shares or derivative instruments (where the underlying assets are in the form of shares in Russian companies) that are officially listed and sold on foreign exchanges will not be recognized as income from Russian sources and, therefore, shall not be subject to Russian income tax.

In the case of our Ordinary Shares, a Non-Resident Holder that is a legal entity may be subject to Russian income tax on capital gains only in connection with the sale of shares in a Russian company that has more than 50% of its assets in the form of immovable property in Russia. In the event of such a sale by a Non-Resident Holder, a tax agent will be required to withhold 24% of any gain realized on the sale by the foreign legal entity. The gain will be determined as the difference between the sale price and the cost of acquisition plus all actual expenses relating to the acquisition, holding and disposition of shares paid by the Non-Resident Holder; provided that the Non-Resident Holder is able to present documents confirming such amounts. Without documentary support, the Non-Resident Holder that is a legal entity is not entitled to deduct the cost of acquisition plus all actual expenses relating to the acquisition, holding and disposition of shares and income tax due will be withheld at the rate of 20% from the gross proceeds of the sale. It should be noted that since capital gains would be calculated in rubles using the respective exchange rates on the date of sale and the date of purchase of shares, the taxable base could be affected by changes in the ruble exchange rate.

Income received by a Non-Resident Holder who is an individual, including capital gains from the sale of securities is subject to income tax at the rate of 30% provided this income is received from a source within Russia. Income is received from a source within Russia if the shares or ADSs are sold in the territory of the Russian Federation. However, there is no definition of “sale in the territory of the Russian Federation” in relation to transactions involving securities. There is a risk that any sale of our Ordinary Shares or ADSs may be considered as a sale in the territory of the Russian Federation if the purchaser of our Ordinary Shares or ADSs is a Russian resident (either a legal entity or an individual).

A Non-Resident Holder that is an individual may recognize income as the difference between sale proceeds and the cost of acquisition plus all actual expenses relating to the acquisition, holding and disposition of shares or ADSs. Where the expenses are not documented and cannot be confirmed, the full sale proceeds are subject to tax. It should be noted that capital gains are calculated in rubles using the respective exchange rates on the date of sale and the date of purchase and, thus, the taxable base could be affected by changes in the ruble exchange rate.

The income tax of a Non-Resident Holder that is an individual must be collected by a tax agent via a withholding procedure. If a tax agent is a professional participant of the securities market (broker, dealer, trust manager, or any person acting under an agency or similar agreement for the individual), income tax should be withheld from gross proceeds from the sale of shares or ADSs less deduction of eligible costs and expenses. In other cases, when a tax agent is technically required to withhold income tax from gross sales proceeds, the individual may later claim a deduction for costs and expenses based on a tax declaration to be filed with Russian tax authorities at the end of the reporting period. A refund of any overpayment of personal income tax in relation to disposition of our ordinary shares or ADSs may be claimed on the basis of the tax declaration filed by the individual Non-Resident Holder. There is a significant uncertainty regarding the availability and timing of such refunds.

Double tax treaty relief. A Non-Resident Holder that is a legal entity may be able to avoid Russian income tax on the disposition of shares under the terms of a double tax treaty between the Russian Federation and the country of residence of the Non-Resident Holder.

No double tax treaty relief from taxation of capital gains on sale of our Ordinary Shares is available for U.S. holders. Under the U.S./Russia Double Tax Treaty, U.S. holders are exempt from income tax on capital gains unless 50% or more of assets of the issuer are represented by immovable property. However, it should be noted that there is a difference between the two official (i.e., English language and Russian language) texts of the U.S./Russia Double Tax Treaty. Since the Russian competent authority is most likely to rely on the Russian language version, there is a risk for U.S. holders that capital gains on disposal of the shares in a Russian company, where the proceeds of such disposal are received from a source within Russia, would still be subject to Russian tax if immovable property comprised fifty percent or more of fixed assets (as opposed to assets) of the issuer.

In practice, no advance exemption from withholding tax under a double tax treaty is available for individual Non-Resident Holders. See “—Procedure for obtaining double tax treaty relief.”

Legal entities. The procedure for obtaining double tax treaty relief is simplified under new legislative provisions. The Income Tax Chapter of the Russian Tax Code, which became effective on January 1, 2002, eliminates the requirement that a non-resident organization should obtain tax treaty clearance from Russian tax authorities prior to receiving any income derived from the shares or ADSs (i.e., from the payment of dividends or the sale of shares). However, Russian tax authorities, in connection with a tax audit, may still dispute the eligibility of a non-resident to benefit from a double tax treaty and require the tax agent to provide documentary support for non-withholding. Upon failure to provide the required documentary support, the tax agent may be required to pay any tax, penalties, and interest. Under the Russian Tax Code (Article 11) non-resident organizations include foreign legal entities, companies or other corporate formations with civil legal capacity established in accordance with legislation of foreign jurisdictions and international organizations.

In order to take advantage of a double tax treaty, it is sufficient to provide the Russian tax agent in advance of receiving income with a confirmation of tax residence in a state with which Russia has concluded the relevant treaty. The confirmation of the Non-Resident Holder’s tax residence may be issued in the form of a letter from the competent authority of the Non-Resident Holder’s country of residence, containing the tax identification number of the resident (if any), the period covered by the letter and the date of issuance. The letter should be duly signed and stamped.

If tax treaty relief is not obtained and income tax is withheld by a tax agent on capital gains or other amounts, a Non-Resident Holder that is an organization as defined by the Russian Tax Code may apply for a tax refund within 3 years from the end of the tax period in which the tax was withheld. To process a claim for a refund, the Russian tax authorities require (i) a confirmation of the tax residence of a Non-Resident Holder in a state with which Russia has concluded the relevant treaty at the time the income was paid; (ii) an application for refund of the income tax withheld in a format provided by the Russian tax authorities; and (iii) copies of the relevant contracts and payment documents confirming the payment of the income tax withheld to the appropriate

Russian authorities (Form 1012DT (2002) is designed to combine (i) and (ii) for foreign organizations). The Russian tax authorities may require a Russian translation of some documents. Under the provisions of the Russian Tax Code, the refund of the tax withheld should be granted within one month after the submission of the documents. However, procedures for processing such claims have not been clearly established, and there is significant uncertainty regarding the availability and timing of such refunds.

Individuals. In accordance with the Russian Tax Code, a Non-Resident Holder who is an individual, in order to take advantage of a relevant double tax treaty, must present to the tax authorities a document substantiating his or her tax residence that complies with the applicable double tax treaty and a document supporting the income received and the tax paid offshore, confirmed by the foreign tax authorities. Formally, such requirement means that an individual cannot rely on the tax treaty until he or she pays the tax in the jurisdiction of their residence.

If income tax is withheld by a tax agent, a Non-Resident Holder who is an individual may apply for a tax refund within 1 year from the end of the tax period in which the tax was withheld for individual Non-Resident Holders. There is however, significant uncertainty regarding the availability and timing of such refunds.

Information for U.S. holders. A U.S. corporate holder seeking to obtain relief from Russian withholding tax under the U.S./Russia Double Tax Treaty must provide a confirmation of its tax residence that complies with the applicable double tax treaty in advance of receiving income. U.S. holders may obtain such confirmation by writing to the Internal Revenue Service, Philadelphia Service Center, Foreign Certification Request, P.O. Box 16347, Philadelphia, PA 19114-0447. The procedures for obtaining certification are described in greater detail in Internal Revenue Service Publication 686.

Other than as specifically provided for in the foregoing discussion, the depositary will have no obligation to assist an ADS holder with the completion and filing of any application for advance double tax treaty relief.

If income received by a Non-Resident Holder who is an individual is treated as Russian source income subject to tax in Russia, but for any reason this tax has not been withheld by a tax agent, such a non-resident individual is liable to declare his/her income to the Russian tax authorities and pay the income tax.

No reporting obligations arise with respect to Russian source income for a Non-Resident Holder that is a legal entity.

The following is a general description of the material United States federal income tax consequences that apply to you if you are a beneficial owner of ADSs or Ordinary Shares who is a U.S. holder (as defined above under “—Taxation”). If a partnership (including any entity treated as a partnership for United States federal income tax purposes) is a beneficial owner of ADSs or Ordinary Shares, the United States federal income tax treatment of a partner in the partnership will generally depend on the status of the partner and the activities of the partnership. Since your United States federal income and withholding tax treatment may vary depending upon your particular situation, you may be subject to special rules not discussed below. Special rules will apply, for example, if you are:

In addition, this summary is generally limited to persons holding Ordinary Shares or ADSs as “capital assets” within the meaning of Section 1221 of the United States Internal Revenue Code and whose functional currency is the United States dollar. The discussion below also does not address the effect of any United States state or local tax law or foreign tax law.

For purposes of applying United States federal income and withholding tax law, a holder of an ADS will be treated as the owner of the underlying shares of Ordinary Shares represented by that ADS.

For United States federal income tax purposes, the gross amount of a distribution, including any Russian withholding taxes, with respect to Ordinary Shares or ADSs will be treated as a taxable dividend to the extent of our current and accumulated earnings and profits, computed in accordance with United States federal income tax principles. Distributions in excess of our current or accumulated earnings and profits will be applied against and will reduce your tax basis in Ordinary Shares or ADSs and, to the extent in excess of such tax basis, will be treated as gain from a sale or exchange of such Ordinary Shares or ADSs. You should be aware that we do not intend to calculate our earnings and profits for United States federal income tax purposes. If you are a corporation, you will not be allowed a deduction for dividends received in respect of distributions on Ordinary Shares or ADSs, which is generally available for dividends paid by U.S. corporations.

If a dividend distribution is paid in rubles, the amount includible in income will be the U.S. dollar value of the dividend, calculated using the exchange rate in effect on the date the dividend is includible in income by you in accordance with your method of accounting, regardless of whether the payment is actually converted into U.S. dollars. Subject to certain exceptions for positions that are hedged or held for less than 60 days, an individual U.S. holder generally will be subject to taxation at a maximum rate of 15% in respect of dividends received after 2002 and before 2009. Any gain or loss resulting from currency exchange rate fluctuations during the period from the date the dividend is includible in your income to the date the rubles are converted into U.S. dollars will be treated as ordinary income or loss. You may be required to recognize foreign currency gain or loss on the receipt of a refund of Russian withholding tax pursuant to the United States-Russia income tax treaty to the extent the United States dollar value of the refund differs from the dollar equivalent of that amount on the date of receipt of the underlying dividend.

Russian withholding tax at the rate applicable to you under the United States-Russia income tax treaty will be treated as a foreign income tax that, subject to generally applicable limitations and conditions, is eligible for credit against your U.S. federal income tax liability or, at your election, may be deducted in computing taxable income. If Russian tax is withheld at a rate in excess of the rate applicable to you under the United States-Russia income tax treaty, you may not be entitled to credits for the excess amount, even though the procedures for claiming refunds and the practical likelihood that refunds will be made available in a timely fashion are uncertain.

A dividend distribution will be treated as foreign source income and will generally be classified as “passive income” or, in some cases, “financial services income” for United States foreign tax credit purposes. The rules relating to the determination of the foreign tax credit, or deduction in lieu of the foreign tax credit, are complex and you should consult your own tax advisors with respect to those rules.

The sale of Ordinary Shares or ADSs will generally result in the recognition of gain or loss in an amount equal to the difference between the amount realized on the sale and your adjusted basis in such Ordinary Shares or ADSs. That gain or loss will be capital gain or loss if the Ordinary Shares or ADSs are capital assets in your hands and will be long-term capital gain or loss if the Ordinary Shares or ADSs have been held for more than one year. If you are an individual, such realized long-term capital gain is generally subject to taxation at a maximum rate of 15% for gain recognized after May 5, 2003 and before 2009, and otherwise at a maximum rate of 20%. Limitations may apply to your ability to offset capital losses against ordinary income.

Deposits and withdrawals of Ordinary Shares by you in exchange for ADSs will not result in the realization of gain or loss for U.S. federal income tax purposes.

If Russian tax is withheld on the sale of Ordinary Shares or ADSs, you may not be entitled to credits for the amount withheld, even though the procedures for claiming refunds under the United States-Russia income tax treaty and the practical likelihood that refunds will be made available in a timely fashion are uncertain.

Dividends and proceeds from the sale or other disposition of Ordinary Shares or ADSs that are paid in the United States or by a U.S.-related financial intermediary will be subject to U.S. information reporting rules and United States backup withholding tax, unless you are a corporation or other exempt recipient. In addition, you will not be subject to backup withholding if you provide your taxpayer identification number and certify that no loss of exemption from backup withholding has occurred. Holders that are not U.S. persons generally are not subject to information reporting or backup withholding, but such holders may be required to provide certification as to their non-U.S. status.

We are subject to informational requirements of the Securities Exchange Act of 1934, as amended, applicable to foreign private issuers and, in accordance therewith, file annual reports on Form 20-F with the Securities and Exchange Commission, and submit current reports on Form 6-K and other information and documents to the SEC. You may read and copy any materials we file with or submit to the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549 or,

with respect to materials filed after November 4, 2002, the SEC’s website http://www.sec.gov. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330 or, from outside the United States, at 1-202-942-8090.

We are exposed to market risk from changes in both foreign currency exchange rates and interest rates. We are exposed to foreign exchange risk to the extent that our costs are denominated in currencies other than rubles. We are subject to market risk from changes in interest rates that may affect the cost of our financing. Other than our banking subsidiaries, we do not use financial instruments, such as foreign exchange forward contracts, foreign currency options, interest rate swaps and forward rate agreements, to manage these market risks. We also do not hold or issue derivative or other financial instruments for trading purposes.

Our principal exchange rate risk involves changes in the value of the ruble relative to the U.S. dollar. At December 31, 2002, approximately RR25,727 million of our indebtedness was denominated in U.S. dollars (out of approximately RR31,240 million of our total indebtedness at that date). Decreases in the value of the ruble relative to the U.S. dollar will increase the cost in rubles of our foreign currency denominated costs and expenses and of our debt service obligations for foreign currency denominated indebtedness. A depreciation of the ruble relative to the U.S. dollar will also result in foreign exchange losses as the ruble value of our foreign currency denominated indebtedness is increased. We believe that the risks associated with our foreign currency exposure are mitigated by the fact that a significant portion of our revenues, approximately 63%, are U.S. dollar-denominated, and thus more closely matched to our foreign currency costs and debt service obligations. Furthermore, our loans receivable of RR7,443 million at December 31, 2002 were also U.S. dollar based, and serve to mitigate our exposure to foreign currency fluctuations. As of June 27, 2003, the ruble had increased in value against the U.S. dollar by approximately 4% since December 31, 2002.

A hypothetical, instantaneous and unfavorable 10% change in currency exchange rates on December 31, 2002 would have resulted in additional interest expense, including default interest, of approximately RR184 million per year, reflecting the increased costs in rubles of servicing our foreign currency denominated indebtedness held at December 31, 2002. A hypothetical, instantaneous and unfavorable 10% change in currency exchange rates at December 31, 2002 would have resulted in an estimated foreign exchange loss of approximately RR 2,573 million on foreign currency denominated indebtedness held at December 31, 2002.

We are exposed to interest rate risk on our indebtedness that bears interest at floating rates. At December 31, 2002, we had approximately RR 31,240 million in loans outstanding, of which approximately RR 9,185 million bore interest at fixed rates and approximately RR 22,055 million bore interest at floating rates determined by reference to the London inter-bank offered rate (“LIBOR”) for U.S. dollar deposits.

A hypothetical, instantaneous and unfavorable change of 100 basis points in the interest rate applicable to floating-rate financial liabilities held at December 31, 2002 would have resulted in additional net interest expense of approximately RR78 million per year. The above sensitivity analysis is based on the assumption of an unfavorable 100 basis point movement of the interest rates applicable to each homogenous category of financial liabilities. A homogeneous category is defined according to the currency in which financial liabilities are denominated and assumes the same interest rate movement within each homogeneous category (e.g., U.S. dollars, rubles).

For the purpose of reducing interest rate risk and currency risk, our banking subsidiaries use a number of derivative instruments. These comprise interest rate swaps, forward rate agreements and forward foreign exchange contracts. The objective, when using any derivative instrument, is to ensure that the risk to reward profile of any transaction is optimized. The normal policy is to measure these instruments at their fair value, using the spot rate at the year end as the basis for the fair value measurement with resultant gains or losses being reported within gains less losses arising from dealing in foreign currency within the statement of operations.

Our banking subsidiaries’ maximum exposure to credit risk excluding the value of collateral is generally reflected in the carrying amounts of financial assets on the balance sheet. The impact of possible netting of assets and liabilities to reduce potential credit exposure is not significant.

Credit risk for off-balance sheet financial instruments is defined as the possibility of sustaining a loss as a result of another party to a financial instrument failing to perform in accordance with the terms of the contract. Our banking subsidiaries use the same credit policies in making conditional obligations as they do for on-balance sheet financial instruments through established credit approvals, risk control limits and monitoring procedures.

Substantially all of our crude oil and refined products are sold on the spot market or under short-term contracts at market sensitive prices. Market prices for export sales of crude oil and refined products are subject to volatile trading patterns in the commodity futures market. Quality differentials, worldwide political developments and the actions of the Organization of Petroleum Exporting Countries also affect crude oil prices. Domestic prices follow the trend of world market prices but are volatile due to the nature of the Russian market. We do not use any derivative instruments to hedge our production in order to decrease our price risk exposure.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

Within the 90 days prior to the date of this report, the Company carried out an evaluation under the supervision and with the participation of our management, including the General Director and Deputy General Director for Economics, of the effectiveness of the design and operation of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of our evaluation, the General Director and Deputy General Director for Economics concluded that the disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed in the reports the Company files and submits under the Exchange Act is recorded, processed, summarized and reported as and when required.

There were no significant changes in the internal controls or in other factors that could significantly affect the internal controls of the Company subsequent to the date of their most recent evaluation.

The total amount of long-term debt securities of the registrant and its subsidiaries authorized under any one instrument does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish copies of any or all such instruments to the Securities and Exchange Commission upon request.

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

OAO TATNEFT
Registrant

/s/ SHAFAGAT F. TAKHAUTDINOV
Name:		Shafagat F. Takhautdinov
Title:		General Director

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15 and 15d-15) for the registrant and have:

(a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the “Evaluation Date”); and

(c) Presented in this report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the “Evaluation Date”); and

(c) Presented in this report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations and comprehensive income, of cash flows and of shareholders’ equity, expressed in constant Russian Roubles of December 31, 2002 purchasing power, present fairly, in all material respects, the financial position of OAO Tatneft and its subsidiaries (the “Group”) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Group’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America which require that we plan and perform the audit to obtain reasonable assurance about 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except share information)

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

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except share information)

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

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

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

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except share information)

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

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

OAO Tatneft (the “Company”) and its subsidiaries (jointly referred to as “the Group”) are engaged in crude oil exploration, development and production principally in the Republic of Tatarstan (“Tatarstan”), an autonomous republic within the Russian Federation. The Group also engages in refining and marketing of crude oil and refined products, petrochemical and banking activities (Note 17). The Group’s banking activities comprise the operations of Zenit Bank and Devon Credit Bank.

The Company was incorporated as an open joint stock company effective January 1, 1994 (the “privatization date”) pursuant to the approval by the State Property Management Committee of the Republic of Tatarstan (the “State”). All assets and liabilities previously managed by the production association Tatneft, Bugulminsky Mechanical Plant, Menzelinsky Exploratory Drilling Department and Bavlinsky Drilling Department were transferred to the Company at their book value at the privatization date in accordance with Decree No. 1403 on Privatization and Restructuring of Enterprises and Corporations into Joint-Stock Companies. Such transfers are considered transfers between entities under common control at the privatization date, and have been recorded at book value restated for the effects of hyperinflation for all periods for which the Russian Federation has been in a hyperinflationary state.

At December 31, 2002, the State held 33% of the common shares of the Company. As further described in Note 15, the State owns one “Golden Share” which carries the right to veto certain decisions taken at meetings of the shareholders and the Board of Directors. The Government of Tatarstan is able to exercise considerable influence through its ownership interest in the Company, its legislative, taxation and regulatory powers, its representation on the Board of Directors and informal influence. Additionally, the Government of Tatarstan also controls a number of the Group’s suppliers, such as OAO Tatenergo, the supplier of electricity to the Group, and a number of the Group’s ultimate customers, such as OAO Nizhnekamskneftekhim (“Nizhnekamskneftekhim”), the principal petrochemical company in Tatarstan. Related party transactions are further disclosed in Note 18.

The Group maintains its accounting records and prepares its statutory financial statements in accordance with the Regulations on Accounting and Reporting of the Russian Federation (“RAR”). The accompanying financial statements have been prepared from these accounting records and adjusted as necessary to comply with accounting principles generally accepted in the United States of America (“US GAAP”).

Use of estimates in the preparation of financial statements. The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including the discussion and disclosure of contingent assets and liabilities. While management uses its best estimates and judgments, actual results may vary from those estimates as future confirming events occur.

Foreign currency transactions and translation. The Russian Rouble is the functional currency for the Group’s operations. Balance sheet items denominated in foreign currencies have been translated using the exchange rate at the balance sheet date prior to restatement to December 31, 2002 purchasing power. The related foreign exchange gains and losses are included in earnings.

Exchange rates, restrictions and controls. The official rate of exchange of the Russian Rouble to the US Dollar (“US $”) at December 31, 2002 and 2001 was RR 31.78 and RR 30.14 to US $1.00, respectively. Exchange restrictions and controls exist relating to converting Russian Roubles into other currencies. At present, the Russian Rouble is not a convertible currency outside of the Russian Federation and, further, the Company is required to sell up to 50% (75% from March 1999 through August 2001) of its hard currency earnings for Russian Roubles. Accordingly, any translation of Russian Rouble amounts to US Dollars should not be construed as a representation that such Russian Rouble amounts have been, could be, or will in the future be converted into US Dollars at the exchange rate shown or at any other exchange rate.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Inflation accounting. All amounts in the consolidated financial statements and notes are expressed in constant Russian Roubles of December 31, 2002 purchasing power, in accordance with Accounting Principles Board Statement 3, Financial Statements Restated for General Price-Level Changes. This remeasurement is calculated from conversion factors derived from the Russian Federation Consumer Price Index, a historical price index published by the Russian State Committee on Statistics (“Goskomstat” prior to October 1999 and “Russian Statistics Agency” since October 1999), and from indices obtained from other sources for years prior to 1992. Management believes that the above indices are the most appropriate and consistent measures of the impact of general price inflation in the Russian Federation for the periods indicated.

The amounts shown in the general price-level consolidated financial statements do not purport to represent appraised value, replacement cost or any other measure of the current value of assets or the price at which transactions would take place currently.

The indices and respective conversion factors for the three years ended December 31, 2002, 2001 and 2000 used to restate the consolidated financial statements, based on 1988 prices (1988 = 100), are as follows:

The effects of inflation on the Group’s net monetary position are included in the consolidated statements of operations and have resulted in net monetary gains totaling RR 871 million, RR 1,764 million and RR 3,706 million for the years ended December 31, 2002, 2001 and 2000, respectively. These effects arise as a result of the Group being in a net monetary liability position for these years.

Effective January 1, 2003, for accounting purposes the economy of the Russian Federation has ceased to be hyperinflationary.

Russian Rouble purchasing power gains and losses. The accompanying consolidated financial statements include certain Russian Rouble amounts which represent underlying US Dollar balances. In 2002, 2001 and 2000, the Consumer Price Index in the Russian Federation increased by 15%, 19% and 20%, respectively, while the US Dollar has gained value with respect to the Russian Rouble by 5%, 7% and 4%, respectively.

For US Dollar balances other than those existing at December 31, 2002, differences between the rate of devaluation of the Russian Rouble and Russian Rouble inflation indexation result in inconsistencies between disclosed Russian Rouble amounts and amounts obtained from converting US Dollar denominated items to Russian Roubles based on December 31, 2002 exchange rates. The disclosed Russian Rouble amounts, however, represent the December 31, 2002 purchasing power amounts in accordance with US GAAP.

Barter transactions. Transactions settled by barter are included in the accompanying consolidated balance sheets and statements of operations on the same basis as cash transactions.

Barter transactions relate to sales of crude oil and refined products and are generally either in the form of direct settlement by crude oil and refined products to the final customer, or through a chain of non-cash transactions involving several companies. In such cases, both sales and purchases are recorded as a result of the barter transaction. Barter sales are recognized at the fair value which is the market price of the crude oil and refined products exchanged.

Disclosure of the effect of barter transactions on the cash flows of the Group is provided in Note 4.

Reclassifications. For comparative purposes, certain prior year amounts have been reclassified to conform to the current year’s presentation.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Principles of consolidation. The accompanying consolidated financial statements include the operations of all subsidiaries in which the Group directly or indirectly owns or controls more than 50 percent of the voting stock. Joint ventures and affiliates in which the Group has significant influence but not control (generally 20 percent to 50 percent) are accounted for using the equity method. Investments in other companies are accounted for at cost and adjusted for estimated impairment.

Cash equivalents. Cash equivalents include all liquid securities with original maturities of three months or less when acquired, as well as amounts due from banks to the Group’s banking subsidiaries.

Inventories. Crude oil, refined oil products, materials and supplies and finished goods inventories are valued at the lower of cost or net realizable value using the weighted-average method.

Investments. Investments include securities classified as available-for-sale, held-to-maturity, or trading. Securities are classified as available-for-sale when, in management’s judgment, they may be sold in response to or in anticipation of changes in market conditions. Available-for-sale securities are carried at fair value on the consolidated balance sheet. Unrealized gains and losses for available-for-sale securities are reported net as increases or decreases to accumulated other comprehensive income. The specific identification method is used to determine realized gains and losses on available-for-sale securities. Securities that management have the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at amortized cost on the consolidated balance sheet. Securities classified as trading are bought and held principally for the purpose of selling them in the near term. Trading securities are carried at fair value on the consolidated balance sheet. Unrealized gains and losses on trading securities are included in earnings.

Loans receivable and advances to customers. Loans receivable and advances to customers, which primarily relate to the Group’s banking operations, are stated at their principal amounts outstanding net of provisions for losses. Provisions for losses on loans and advances to customers are based on the evaluation by management of their collectibility. Specific provisions are recorded against debts whose recovery has been identified as doubtful. A general provision is recorded against the doubtful loans and advances to customers, which are inherent in the portfolio but which at the date of preparing the financial statements have not been specifically identified. Estimates of losses require the exercise of judgment and the use of assumptions.

Property, plant and equipment. The Group follows the successful efforts method of accounting for its oil and gas properties, whereby property acquisitions, successful exploratory wells, all development costs (including development dry holes), and support equipment and facilities are capitalized. Unsuccessful exploratory wells are charged to expense at the time the wells are determined to be non-productive. Production costs, overheads and all exploration costs other than exploratory drilling are charged to expense as incurred. Acquisition costs of unproved properties are evaluated periodically and any impairment assessed is charged to expense.

Depreciation, depletion and amortization of capitalized costs of proved oil and gas properties is calculated using the unit-of-production method for each field based upon proved developed reserves. Estimated costs of dismantling oil and gas production facilities, including abandonment and site restoration costs, are recorded using the unit-of-production method and included as a component of depreciation, depletion and amortization.

Gains or losses are not recognized for retirements of oil and gas producing properties which are subject to composite depreciation, depletion and amortization. Gains or losses on retirements of other than oil and gas producing properties are included in earnings.

Other property, plant and equipment not associated with oil and gas properties are recorded at cost less accumulated depreciation. Depreciation of these assets, including social assets, is calculated on a straight-line basis as follows:

Long-lived assets, including proved oil and gas properties, are assessed for possible impairment in accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”) . SFAS 144 requires long-lived assets with recorded values that are not expected to be

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

recovered through undiscounted future cash flows to be written down to current fair value. Fair value is generally determined from estimated future discounted net cash flows.

Maintenance and repairs and minor renewals are expensed as incurred. Major renewals and improvements are capitalized and any assets replaced are retired.

Social assets constructed prior to privatization, and the related deferred income tax balances, were charged to additional capital as a distribution of capital when the assets were permanently transferred to government authorities. Social assets constructed subsequent to privatization are charged to expense when the assets are permanently transferred to government authorities.

Derivative instruments. The Group recognizes all derivatives as either assets or liabilities in the consolidated balance sheet and measures those instruments at fair value. Derivative instruments primarily represent foreign exchange and commodity forwards associated with the Group’s banking operations. The accounting for changes in fair value depends on the derivatives’ intended use and designation and could entail recording the gain or loss through earnings of the current period, or as part of comprehensive income and subsequently reclassifying into earnings when the gain or loss is realised.

Environmental liabilities. Liabilities for environmental remediation are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.

Pension and post-employment benefits. The Group’s mandatory contributions to the governmental pension scheme are expensed when incurred. Discretionary pension and other post-employment benefits are not material.

Revenue recognition. Revenues from the production and sale of crude oil and petroleum products are recognized when deliveries of products to final customers are made and title passes to the customer and collectibility is reasonably assured. Sales of crude oil with next day obligations to repurchase are not accounted for as sales or purchases (see Note 18).

Stock-based compensation. The Group’s stock-based compensation is accounted for in accordance with the intrinsic value method established by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Compensation expense is recognized for stock options granted when the exercise price of the options granted is below the fair market value of the Group’s stock at the date of grant.

Income taxes. Deferred income tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in the years in which these temporary differences are expected to reverse. Valuation allowances are provided for deferred income tax assets when management believes that it is more likely than not that the assets will not be realized.

Comprehensive income. Comprehensive income includes all changes in equity during the period from non-owner sources and is detailed in the consolidated statement of operations and comprehensive income.

Net income per share. Basic income per share is calculated using the two class method of computing earnings per share. Under this method, net income is reduced by the amount of dividends declared in the current period for each class of shares, and the remaining income is allocated to common and preferred shares to the extent that each class may share in income if all income for the period had been distributed. Diluted income per share reflects the potential dilution that were exercised using the treasury stock method.

Treasury shares. Common shares of OAO Tatneft owned by the Group at the balance sheet date are designated as treasury shares and are recorded at cost. Any gain or loss on the resale of treasury shares is recorded as a component of equity.

Recent accounting pronouncements. In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). This new statement will be adopted effective January 1, 2003 and applies to legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Adoption of SFAS 143 primarily affects the Group’s accounting for oil and gas producing assets and differs in several significant respects from current accounting under Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. Upon initial recognition of a liability for an asset retirement obligation, the Group will capitalize an asset retirement cost by increasing the carrying value of the related long-lived asset by the same amount. Legal obligations, if any, to retire refining and marketing and distribution assets are generally not recognized because of the indeterminable settlement date of these obligations. Management is currently completing its assessment of the effect of the adoption of SFAS 143 on the Group.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FAS 123 (“SFAS 148”) provides alternative methods for the transition of the accounting for stock-based compensation from the intrinsic value method to the fair value method. Effective January 1, 2003, the Company plans to apply the fair value method to future grants and any modified grants of stock-based compensation. Based upon this change, and assuming the terms of stock option grants in 2003 are similar to those granted in prior years, the estimated impact on the Company’s 2003 earnings would not be materially different than under previous accounting standards.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”). FIN 46 amended ARB 51, Consolidated Financial Statements, and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated with its primary beneficiary. FIN 46 also requires disclosures about VIEs that the Group is not required to consolidate but in which it has a significant variable interest. The consolidation requirements of FIN 46 apply immediately to VIEs created after January 31, 2003, while earlier formed entities must be consolidated in the first fiscal year or interim period beginning after June 15, 2003. The Group does not expect the initial adoption of FIN 46 to have a significant impact on its results of operations, financial position or liquidity.

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (“SFAS 150”). SFAS 150 establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equity and is effective for financial instruments entered into or modified after May 31, 2003. The Group does not expect the initial adoption of SFAS 150 to have a significant impact on its results of operations, financial position or liquidity.

Note 4: Cash and Cash Equivalents, Restricted Cash and Cash Flow Information

The consolidated statements of cash flows provide information about changes in cash and cash equivalents. At December 31, 2002, 2001 and 2000, cash holdings of the Group, consisting of cash, cash equivalents and restricted cash, include US Dollar denominated amounts of RR 4,150 million (US $131 million), RR 3,295 million (US $95 million), and RR 4,096 million (US $106 million), respectively, of which RR 178 million (US $6 million), RR 727 million (US $21 million) and RR 2,825 million (US $73 million), respectively, is restricted. Restricted cash primarily consists of mandatory deposits with the Central Bank of Russia and deposits with lending institutions. Deposits with lending institutions are held over the life of the respective loans.

Net cash provided by operating activities reflects payments of interest and income taxes as follows:

Non-cash sales. Non-cash sales for the years ended December 31, 2002, 2001 and 2000 totaled RR 6,004 million, RR 8,560 million and RR 21,944 million, respectively, which approximates 4%, 6% and 11% of sales and other operating revenues, respectively.

Non-cash sales, settled by purchases of property, plant and equipment, have been excluded from net cash provided by operating activities and from net cash used for investing activities in the accompanying consolidated statements of cash flows.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Note 4: Cash and Cash Equivalents, Restricted Cash and Cash Flow Information (continued)

The following table shows the distribution of non-cash sales included in the consolidated statements of operations and as additions to property, plant and equipment:

Other non-cash transactions. During 2002 the Group entered in non-cash sales and purchase transactions with respect to treasury shares. Non-cash sales of treasury shares amounted to RR 1,995 million and represented 115,776 thousand shares. Non-cash purchases of treasury shares amounted to RR 3,560 million and represented 122,492 thousand shares.

Trade receivables are presented net of an allowance for doubtful accounts of RR 1,073 million and RR 1,246 million at December 31, 2002 and 2001, respectively.

Short-term investments are classified both as available-for-sale and trading securities:

Trading securities are those securities which are actively managed in a trading account with the objective of profiting from short-term price changes. These securities are held in the Group’s banks and insurance company, which frequently buy and sell securities with the objective of earning profits on short-term differences in price. All other investments in debt and equity securities are classified as available-for-sale.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

At December 31, 2002 short-term investments classified as available-for-sale represent mainly equity securities held by consolidated banks. At December 31, 2001, short-term investments included Tatneft Finance Eurobonds with a carrying value of RR 6,503 million (nominal value of US $186 million), of which RR 3,969 million (nominal value of US $116 million) were held in trust. All Tatneft Finance Eurobonds were repaid in October 2002 upon maturity. This resulted in the recognition of a holding gain in the amount of RR 3,408 million which is net of associated investment fees and recorded in other income for the year ended December 31, 2002.

Bonds and other Russian government securities at December 31, 2002 and 2001, include mainly Federal Currency Bonds (OVVZ) with a carrying value of RR 712 million and RR 770 million respectively.

At December 31, 2002, total debt securities with fair values totaling RR 453 million mature during 2003, and with fair values totaling RR 1,966 million mature between 2004 and 2030.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Net realized gains on trading and available-for-sale securities for the years ended December 31, 2002, 2001 and 2000 were RR 3,583 million, RR 1,736 million, RR 112 million, respectively.

Summary financial information pertaining to these investments has not been presented as the investments are not material to the Group’s consolidated financial statements.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Banking loans and advances to customers. Banking loans and advances to customers are presented net of allowance for losses of RR 1,011 million and RR 1,149 million as at December 31, 2002 and 2001, respectively.

At December 31, 2002 and 2001, the weighted average year-end interest rate on banking loans and advances was 18% and 20% on balances denominated in Russian Roubles and 14% and 17% on balances denominated in foreign currency, respectively. The fair value of banking loans and advances approximate the carrying values as interest rates typically adjust on a three month basis and the majority are short-term in nature.

Other Rouble denominated loans receivable. Other Rouble denominated loans receivable include non interest-bearing loans to third parties in the amount of RR 1,893 million, of which RR 651 million are classified as current and RR 1,242 million as long-term.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

The Group’s estimates of future aggregate dismantling, abandonment and site restoration costs for oil and gas properties were RR 16,068 million and RR 15,044 million as of December 31, 2002 and 2001, respectively. RR 12,902 million and RR 12,900 million have been recognized at December 31, 2002 and 2001, respectively, as a component of accumulated depreciation. The Group has estimated its liability based on current environmental legislation and its best estimate of future costs under existing operating conditions.

The Group’s oil and gas fields are situated on land belonging to the Government of Tararstan. The Group obtains licenses from the local authorities to explore and produce oil and gas from these fields. These licenses expire between 2013 and 2015, and may be extended at the initiative of the Group. Management expects to extend licenses for properties which are expected to produce hydrocarbons subsequent to the expiration of their respective licenses.

The Group’s cash flow from operations is dependent on the level of oil prices, which are historically volatile and are also significantly impacted by the proportion of production that it can sell on the export market. Historically, the Group has supplemented its cash flow from operations with additional borrowings and may continue to do so. Should oil prices decline for a prolonged period and should the Group not have access to additional capital, the Group would need to reduce its capital expenditures, which could limit its ability to maintain or increase production and in turn meet its debt service requirements and pay dividends.

In 1999, the Group entered into an agreement with Nizhnekamskneftekhim, and OAO Tataro-American Investment Fund (TAIF), related parties under the significant influence of a common shareholder, to form a joint venture company, OAO Nizhnekamsk Refinery. This joint venture is expected to expand, upgrade, and operate the existing refinery in Nizhnekamsk. The Group’s total investment in the refinery amounted to approximately US $215 million as of December 31, 2002, and is recorded within assets under construction and buildings and constructions. The ultimate level of the Group’s interest in the refinery is still under negotiation.

Social assets. During 2002, 2001 and 2000 the Group transferred social assets with a net book value of RR 1,293 million, RR 593 million and RR 128 million, respectively, to local authorities for no consideration. All the amounts transferred in 2002, 2001 and 2000 relate to assets that were constructed or procured by the Group subsequent to privatization. At December 31, 2002 and 2001, the Group held social assets with a net book value of RR 5,833 million and RR 5,831 million all of which were constructed after the privatization date. The Group incurred social infrastructure expenses of RR 199 million, RR 491 million and RR 252 million for the years ended December 31, 2002, 2001 and 2000, respectively, for maintenance that mainly relates to housing, schools and cultural buildings.

Impairment of fixed assets. In 2000, based on a reassessment of its future development plans and cash flows of a telecommunications subsidiary, the Group wrote off its investment resulting in a charge to operations of RR 1,083 million.

In 2001, based on a reassessment of its future development plans and cash flows of a second telecommunications subsidiary, the Group has written off its investment resulting in a charge to operations of RR 394 million.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Short-term foreign currency denominated debt. As of December 31, 2002 other short-term foreign currency denominated debt includes loans from Winter Bank, BNP Paribas, Donau bank, Credit Swiss Zurich, Whill Trading and interbank loans.

In July 2001 OAO Tatneft entered into a RR 1,042 million (US $30 million) loan agreement with Winter Bank. The loan bears an interest rate of 6 month LIBOR plus 4.5% per annum. The loan must be repaid in full every six months and may be renewed immediately for an additional six months during the three year term of the commitment. The loan matures in November 2004. The amount of loan outstanding as of December 31, 2002 was RR 954 million.

In 2002 the Group entered into a RR 1,570 million (US $50 million) loan agreement with BNP Paribas. The loan bears interest at 1 month LIBOR plus 3.5 % per annum and is collateralized by the crude oil export contracts of 45 thousand tonnes per month. The amount of loan outstanding as of December 31, 2002 was RR 993 million. The loan matures in May 2003.

In December 2002 the Group entered into a RR 636 million (US $20 million) loan agreement with Donau bank. The loan bears interest at 2.3 % per annum and matures in December 2003.

In 2002 the Group entered into a RR 636 million (US $20 million) one month revolving overdraft facility with Credit Swiss Zurich. The monthly revolving loan bears interest from 3.150% to 3.750% per annum and is collateralized by crude oil sales. The amount of loan outstanding as of December 31, 2002 was RR 438 million (US $14 million).

In 2002 the Group entered into a RR 22 million (US $0.7 million) loan agreement with Whill Trading. The loan bears interest at 12 % per annum, matures in March 2003 and is unsecured.

Interbank loans from foreign banks of RR 2,522 million and RR 3,276 million as of December 31, 2002 and 2001 had effective average year end interest rate of 7% and 4% per annum, respectively.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Short-term Rouble denominated debt. Rouble denominated short-term debt primarily comprises of loans with Russian banks. Short-term Rouble denominated loans of RR 4,941 million and RR 3,921 million bear contractual interest rates from 10% to 25% and 10% to 22% per annum for the years ended December 31, 2002 and 2001, respectively. The loans are collateralized by the assets of the Group.

Long-term foreign currency denominated debt. In November 2001, the Group entered into a loan agreement with BNP Paribas for US $100 million. The loan bears interest at LIBOR plus 3.5% per annum, is collateralized by crude oil export contracts of 50 thousand tonnes per month and matures in February 2004. The amount of loan outstanding as of December 31, 2002 was RR 2,251 million. In October 2002, the Group entered into another loan agreement with BNP Paribas for US $300 million. The amount outstanding under this loan as of December 31, 2002 was RR 9,492 million. The loan bears interest from LIBOR plus 3.75% to LIBOR plus 4.25%, per annum, is collateralized by crude oil export contracts of 120 thousand tonnes per month, and matures in October 2007. The loan agreements require compliance with certain financial covenants including, but not limited to, minimum levels of consolidated tangible net worth, and maximum debt and interest coverage ratios.

In March 2002 the Group entered into a US $200 million loan agreement with Credit Suisse First Boston. The amount of loan outstanding as of December 31, 2002 was RR 5,721 million (US $180 million). The loan bears interest at LIBOR plus 3.78% per annum, is collateralized by the crude oil export contracts of 200 thousand tonnes per month and matures March 2007.

In October 2001 the Group entered into a US $125 million loan agreement with Commerzbank AG. The amount outstanding under this loan as of December 31, 2002 was RR 2,207 million. The loan bears interest at LIBOR plus 3.75% per annum, is collateralized by the Group’s oil export contracts of 80 thousand tonnes per month and matures October 2003.

Other long-term foreign currency denominated debt. During the year ended December 31, 2002 the Group entered into a RR 278 million (US $9 million) loan agreement with West Deutsche Landesbank Vostok. The amount outstanding under this loan as of December 31, 2002 was RR 232 million. The loan bears interest at LIBOR plus 4.5% per annum and is collateralized by crude oil export contracts of approximately 7.5 thousand tonnes per month. The loan matures February 2004.

Long-term Rouble denominated debt. Long-term Rouble denominated debt includes debentures and other loans. In 2001 and 2002 the Group issued debentures with contractual interest rates from 11.78% to 18.72%. Debentures outstanding as of December 31, 2002 amounted to RR 200 million. Other loans include non-interest bearing Rouble denominated loans of RR 112 million with related parties (Note 18) and loans with other counter parties. The loans mature between 2003 to 2015.

The fair value of long-term debt is estimated using current yields to maturity of similar debt with similar credit risk or by using discounted cash flows. Based on these estimates, the fair value of the Group’s long-term debt, including the current portion of long-term debt is RR 19,791 million (US $623 million) and RR 22,785 million (US $717 million), at December 31, 2002 and 2001, respectively. This fair value assessment is subject to considerable uncertainty given the low trade volumes for similar debt.

Aggregate maturities of long-term debt outstanding at December 31, 2002 are as follows:

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Bank notes payable as of December 31, 2002 include short-term and long-term notes payable of Zenit Bank in the amount of RR 1,640 million and RR 13 million, respectively, and short-term notes payable of Devon Credit in the amount of RR 54 million. Bank notes payable for the year ended December 31, 2001 include short term notes payable of Zenit Bank in the amount of RR 1,154 million.

Other notes payable as of December 31, 2002 and 2001, include short-term and long-term promissory notes payable to third parties and bear contractual interest rates ranging from 2% to 19%, respectively.

Contractual interest rates were 12% and 13% for Russian Rouble interest deposits, and 6% and 9% for foreign currency interest deposits for the years ended December 31, 2002 and 2001, respectively.

The carrying values of notes payable and banking customer deposits approximate their fair values.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for statutory tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2002 and 2001:

At December 31, 2002 and 2001, deferred taxes were classified in the consolidated balance sheet as follows:

Presented below is a reconciliation between the provision for income taxes and taxes determined by applying the statutory tax rate to income before income taxes:

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Inflationary effects include the impact of inflation on shareholders’ equity, opening deferred tax assets and liabilities and current tax expense. Tax credits reduce taxable income in the period incurred and are granted by the governments of the Russian Federation and the Republic of Tatarstan.

In August 2000, the Russian Tax Code was amended effective January 1, 2001 increasing the income tax rate to 35%. In August 2001, changes in the Russian Tax Code were enacted, which introduced a new income tax rate of 24%, effective January 1, 2002. The net deferred tax (benefit) expense recognized as a result of remeasuring the deferred tax liability for tax rate changes on an enactment date basis, amounted to RR (9,352) million and RR 1,684 million for the years ended December 31, 2001 and 2000, respectively.

For the year ended December 31, 2002 the Group recorded a statutory revaluation of its property, plant and equipment tax base amounting to RR 11,893 million, resulting in a decrease in its deferred tax liability of RR 2,854 million.

No provision has been made for additional income taxes on undistributed earnings of a foreign subsidiary of RR 1,600 million. These earnings have been and will continue to be reinvested. These earnings could become subject to additional tax of approximately RR 240 million if they were remitted as dividends.

The Company is subject to a number of taxes other than income taxes, which are detailed as follows:

Effective January 1, 2002, the unified production tax was introduced and replaced the mineral restoration tax, royalty tax and excise tax on crude oil production. The base for the unified production tax is set at RR 340 per metric tonne of crude oil produced, and is adjusted depending on the market price of Urals blend and the US $/ RR exchange rate. The tax becomes zero if Urals blend price falls to or below US $8.00 per barrel.

Authorized share capital. At December 31, 2002 the authorized share capital consists of 2,178,690,700 voting common shares and 147,508,500 non-voting preferred shares; both classes of shares have a nominal value of RR 1.00 per share.

Golden share. One share of the Company, held by the Government of Tatarstan, carries the right to veto certain decisions taken at shareholders’ and Board of Directors’ meetings. Decisions subject to veto include: increases and decreases in share capital, amendments to the Company’s charter, liquidation or reorganization of the Company or any of its subsidiaries or branches, investment in other legal entities and disposal or encumbrance of the Company’s property. The term of the “Golden Share” was extended indefinitely in 1998 by a decree of the President of Tatarstan and may be utilized by the Government of Tatarstan if it owns less than 25% of the Company.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Restricted common and preferred shares. Under the privatization laws of Tatarstan, certain common shares were made subject to restrictions on transfer. These include shares sold to employees for a discount from nominal value and common shares sold to any individual for privatization vouchers. The preferred shares of the Company were also subject to restrictions on transfer. The preferred shares were originally allocated pursuant to applicable privatization laws to employees, former employees, and pensioners who had worked for the Group for a specified period of time. During 2001 by decree of the President of Tatarstan, all restrictions on common and preferred shares have been removed.

Rights attributable to preferred shares. Unless a different amount is approved at the annual shareholders meeting, preferred shares earn dividends equal to their nominal value. The amount of a dividend for a preferred share may not be less than the amount of a dividend for a common share.

The decisions listed above can be made only if approved by 75% of preferred shareholders.

Holders of preferred shares acquire the same voting rights as holders of common shares in the event that dividends are either not declared, or declared but not paid. On liquidation, the shareholders are entitled to receive a distribution of net assets.

Amounts available for distribution to shareholders. Amounts available for distribution to shareholders are based on the Company’s non-consolidated statutory accounts prepared in accordance with RAR, which differ from US GAAP. The statutory accounts are the basis for profit distribution and other appropriations. Russian legislation identifies the basis of distribution as the current year net profit calculated in accordance with RAR. However, this legislation and other statutory laws and regulations dealing with distribution rights are open to legal interpretation. For the years ended December 31, 2002 and 2001, the Company had a statutory current year profit of RR 6,309 million (unrestated) and RR14,792 million (unrestated), respectively, as reported in the published annual statutory accounts of the Company.

At the annual general meeting of shareholders on June 28, 2002, final dividends of RR 0.10 per common share and RR1.00 per preferred share, expressed in nominal Russian Roubles, were approved for 2001 for all shareholders. At December 31, 2002 the Company had paid all of its accrued dividends for 2001. No interim dividends for 2002 were declared.

Net income per share. Under the two-class method of computing net income per share, net income is computed for common and preferred shares according to dividends declared and participation rights in undistributed earnings. Under this method, net income is reduced by the amount of dividends declared in the current period for each class of shares, and the remaining income is allocated to common and preferred shares to the extent that each class may share in income if all income for the period had been distributed.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

The difference in the weighted average number of common shares outstanding between basic and diluted is due to the outstanding stock options discussed in Note 16.

On March 30, 2002, the Board of Directors approved a stock based compensation plan which provides for the issuance of options to purchase 9,300,000 common shares of OAO Tatneft. In September 2002, options to purchase 9,300,000 common shares with an exercise price of RR 9.5 were granted to senior management and directors of the Group. All options vest in 270 days from the grant date and expire in 365 days after the grant date. The market price of the Group’s ordinary stock as of the date of grant was RR 22.62 per share. Stock options were sold at RR 1 for each option giving the option holders the right to purchase 9,300,000 shares at RR 9.5 for each share. The full price of the stock option issue in the amount of RR 9.3 million was paid by the option holders on grant date. The full exercise price in the amount of RR 88.4 million is due when the stock options are exercised. As the exercise price of the options was lower than the market price at the date of grant, compensation expense of RR 120 million was recognized in the consolidated statement of operations for the year ended 31, December 2002, in accordance with the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and as the Company expects to redeem the stock options after vesting, a corresponding liability has been recorded in accrued liabilities in the consolidated balance sheet as of December 31, 2002.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

In January 2001, the Board of Directors approved a stock based compensation plan which provided for the issuance of options to purchase up to 10,000,000 common shares of OAO Tatneft. In July 2001, options to purchase 9,395,000 common shares with an exercise price of RR 0.1 were granted to senior management and directors of the Group. All options vested 270 days from the grant date and expired 365 days after the grant date. The market price of the Group’s ordinary stock as of the date of grant was RR 14.2 per share. The full exercise price of the stock option issue in the amount of RR 939,500 was paid by the option holders on grant date. Compensation expense of RR 163 million was recognized in the consolidated statements of operations for the year ended 31, December 2001. During 2002, after vesting, all of the options were redeemed by the Company by paying the option holders amounts equal to the market value of the underlying shares at the time of redemption less the exercise price.

The following table summarizes the stock option activity for the period presented:

In accordance with SFAS No. 123, Accounting for Stock-Based Compensation, pro-forma information regarding net income and earnings per share is required to be presented as if the Group had accounted for its Stock Compensation Plan under the fair value method of that statement.

The fair value of the Group’s stock options is the estimated present value at the date of grant using the Black-Scholes option pricing model with the following assumptions: expected volatility of 38% and 53%, respectively, a risk free interest rate of 13.6% and 18.75%, respectively, expected annual dividend yield of nil, and an expected term of 270 days for 2002 and 2001, respectively. Based upon the above assumptions, the fair value of stock options granted was RR 14.03 and RR 15.2 per share for 2002 and 2001, respectively.

The Black-Scholes option pricing model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, this option pricing model requires the input of highly subjective assumptions, including the expected stock price volatility, therefore the actual fair value of the Group’s options may be different.

If compensation expense for the Group had been determined using the fair-value method prescribed by SFAS No. 123, the Group’s net income and earnings per share would not substantially differ from what was recorded.

The Group’s business activities are conducted predominantly through four major business segments: Exploration and Production, Refining and Marketing, Petrochemicals, and Banking.

The segments were determined based on the way management recognizes the segments within the Group for making operating decisions and how they are evident from the Group structure.

Exploration and production segment activities consist of oil extraction by production divisions. Intersegment sales in exploration and production constitute transfers of crude oil and gas from production divisions to the refining and marketing divisions and subsidiaries. The intersegment sales are measured at the estimated market prices of those transactions and are eliminated on consolidation.

“Other” exploration and production sales include revenues from ancillary services provided by the specialized subdivisions and subsidiaries of the Group, such as sales of oilfield equipment and drilling services provided to other companies in Tatarstan. Business activities, which do not constitute reportable business segments, are also included in “Other” exploration and production sales.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Refining and marketing comprises purchases and sales of crude oil and refined products from the Group’s own production divisions and third parties, own refining activities and retailing operations. As in prior years, the Company sold significant volumes of oil to intermediaries, which refine oil in domestic refineries, and purchased refined products processed from its oil.

Sales of petrochemical products include sales of petrochemical raw materials and refined products, which are used in production of tires. Sales of tires are disclosed by geographic segment for the reporting periods. “Other” petrochemical sales represent revenues from the sales of auxiliary services and materials not included above.

Earnings of the banking segment include earnings of Devon Credit Bank and Zenit Bank.

Segment sales and other operating revenues. Reportable operating segment sales and other operating revenues are stated in the following table:

(1) CIS is an abbreviation for Commonwealth of Independent States (excluding the Russian Federation).

(2) Non-CIS sales of crude oil and refined products are mainly made to European markets.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

During 2002, 2001 and 2000, the Group’s refining and marketing revenues for non-CIS crude oil sales included RR 20,495 million, RR 29,851 million and RR 44,974 million, respectively, relating to crude oil export contracts securing certain of the Group’s debt agreements as described in Note 11.

Segment earnings and assets. The Group evaluates the performance of its operating segments on a before-tax basis, without considering the impacts of non-banking net interest expense, monetary effects and the earnings of minority interest shareholders. Segment earnings are as follows:

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Segment depreciation, depletion and amortization and additions to property, plant and equipment are as follows:

Transactions are entered into in the normal course of business with significant shareholders, directors and companies with which the Group has significant shareholders in common. These transactions include sales of crude oil and refined products, purchases of electricity and banking transactions.

The amounts of transactions for each year and the outstanding balances at each year end with related parties are as follows:

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

The Group continued to enter into back-to-back crude oil transactions with various parties. These transactions are not recorded as purchases and sales of crude oil but the net commission amounting to RR 1,514 million, and RR 1,414 million, of which nil and RR 595 million were associated with transactions with related parties, for the years ended December 31, 2002 and 2001, respectively, are included within selling, general and administrative expenses. The volumes of crude oil sold and purchased under these transactions were 2,829 thousand, and 2,500 thousand tonnes for the years ended December 31, 2002 and 2001, respectively.

Fair values. The carrying amounts of short-term financial instruments, other than short-term debt and the related loans receivable, approximates fair value because of the relatively short period of time between the origination of these instruments and their expected realization.

Information concerning the fair value of long-term investments is disclosed in Note 6.

Information concerning the fair value of loans receivable and advances is disclosed in Note 9.

Information concerning the fair value of short-term and long-term debt is disclosed in Note 11.

Information concerning the fair value of notes payable and banking customer deposits is disclosed in Note 12.

Credit risk. A significant portion of the Company’s accounts receivable are from domestic and export trading companies. Although collection of these receivables could be influenced by economic factors affecting these entities, management believes there is no significant risk of loss to the Group beyond provisions already recorded. The Group’s banks take on exposures to credit risk which is the risk that a counterparty will be unable to pay amounts in full when due. The banks structure the levels of credit risk they undertake by placing limits on the amount of risk accepted in relation to one borrower, or groups of borrowers, and to geographical and industry segments. Such risks are monitored on a revolving basis and subject to an annual or more frequent review. Limits on the level of credit risk by product, borrower and industry sector are reviewed regularly.

Operating environment. While there have been improvements in the economic situation in the Russian Federation in recent years, the country continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible in most countries outside of the Russian Federation, restrictive currency controls, and relatively high inflation. The prospects for future economic stability in the Russian Federation are largely dependent upon the effectiveness of economic measures undertaken by the government, together with legal, regulatory, and political developments.

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Taxation. Russian tax legislation is subject to varying interpretations and constant changes. Further, the interpretations of tax legislation by tax authorities as applied to the transactions and activities of the Group may not coincide with that of management. Also interpretations on the application of the tax legislation may vary between regional and Federal tax authorities. As a result, transactions may be challenged by tax authorities and the Group may be assessed for additional taxes, penalties and interest. Consolidated tax returns are not required under existing Russian tax legislation and tax audits are performed on an individual entity basis only. Tax periods remain open to review by the tax authorities for three years.

Environmental liabilities. The Group, through its predecessor entities, has operated in Tatarstan for many years without developed environmental laws, regulations and Group policies. Environmental regulations and their enforcement are currently being considered in the Russian Federation and the Group is monitoring its potential obligations related thereto. The outcome of environmental liabilities under proposed or any future environmental legislation cannot reasonably be estimated at present, but could be material. Under existing legislation, however, management believes that there are no probable liabilities that are in addition to amounts already accrued in the consolidated financial statements, which would have a material adverse effect on the operating results or financial position of the Group.

Legal contingencies. The Group is the named defendant in a number of lawsuits as well as the named party in numerous other proceedings arising in the ordinary course of business. While the outcomes of such contingencies, lawsuits or other proceedings cannot be determined at present, management believes that any resulting liabilities will not have a materially adverse effect on the operating results or the financial position of the Group.

On December 6, 2002 the Group filed a lawsuit in the Arbitration court of Tatarstan against the Tax Ministry of Tatarstan claiming a refund for mineral use tax (royalty tax) paid in the amount of RR 2,251 million. On January 17, 2003 the Arbitration court ruled in favor of the Group and permitted the Group to apply this amount against future tax payments. The Tax Ministry of Tatarstan appealed this decision to the Federal Arbitration court of Povolzhsky district which, on April 6, 2003, upheld the decision of the Arbitration court of Tatarstan. These decisions could be reversed by higher courts and thus the Group has not yet recorded any benefit attributable to this refund in its consolidated financial statements.

Social commitments. The Group contributes significantly to the maintenance of local infrastructure and the welfare of its employees within Tatarstan, which includes contributions towards the construction, development and maintenance of housing, hospitals and transport services, recreation and other social needs. Such funding is periodically determined by the Board of Directors after consultation with governmental authorities and recorded as expenditures are incurred.

Transportation of crude oil. The Group benefits from the blending of its crude oil in the Transneft pipeline system since the Group’s crude oil production is generally of a lower quality than that produced by other regions of the Russian Federation which supply the same pipeline system. There is currently no equalization scheme for differences in crude oil quality within the Transneft pipeline system and the implementation of any such scheme is not determinable at present. However, if this practice were to change, the Group’s business could be materially and adversely affected.

Banking commitments and contingent liabilities. Credit related commitments comprise Zenit Bank loan commitments and guarantees of RR 4,773 million and RR 2,398 million at December 31, 2002 and 2001, respectively. The contractual amount of these commitments represents the value at risk if the bank’s clients default and all existing collateral becomes worthless.

Zenit Bank fiduciary assets and trust arrangements at nominal value amounted to RR 4,148 million and RR 14,941 million at December 31, 2002 and 2001, respectively, and recorded off balance sheet as they are not assets of Zenit Bank. There is no insurance coverage maintained.

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

In accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities, this section provides supplemental information on oil and gas exploration and production activities of the Group.

The Group’s oil and gas production is exclusively in Tatarstan within the Russian Federation; therefore, all of the information provided in this section pertains entirely to that region.

The following tables set forth information regarding oil exploration and production costs. The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year.

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

The Group’s results of operations from oil producing activities are shown below. Proved natural gas reserves do not represent a significant portion of the Group’s total reserves.

In accordance with SFAS 69, results of operations do not include general corporate overhead and monetary effects nor their associated tax effects. Income taxes are based on statutory rates for the year, adjusted for tax deductions, tax credits and allowances.

As determined by the Group’s independent reservoir engineers, Miller and Lents, the following information presents the balances of proved oil reserves at December 31, 2002, 2001 and 2000. The definitions used are in accordance with applicable US Securities and Exchange Commission (“SEC”) regulations.

Proved reserves are the estimated quantities of oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change over time as additional information becomes available.

Management believes that proved reserves should include quantities which are expected to be produced after the expiry dates of the Group’s production licenses. Most significant licenses expire in 2013. Management believes the licenses may be extended at the initiative of the Group and management expects to extend such licenses for properties expected to produce subsequent to their license expiry date. The Group has disclosed information on proved oil and gas reserve quantities and standardized measure of discounted future net cash flows for periods up to and past license expiry dates separately.

Proved developed reserves are those reserves which are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those reserves which are expected to be recovered as a result of future investments to drill new wells and/or to install facilities to collect and deliver the production from existing and future wells.

A significant portion of the Group’s total proved reserves are classified as either developed non-producing or undeveloped. Of the non-producing proved reserves, a significant portion represents existing wells which are expected to be put back into production at a future date.

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Cash Flows

For the purposes of the following disclosures, estimates were made of quantities of proved reserves and the periods in which they are expected to be produced. Future cash flows were computed by applying year-end prices (as described below) to the Group’s estimated annual future production from proved oil reserves. Future development and production costs were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income taxes were computed by applying, generally, year-end statutory tax rates (adjusted for tax deductions, tax credits and allowances) to the estimated future pretax cash flows. The discount was computed by application of a 10% discount factor. The calculations assumed the continuation of existing political, economic, operating and contractual conditions at each of December 31, 2002, 2001, and 2000. However, such arbitrary assumptions have not necessarily proven to be the case in the past and may not in the future. Other assumptions of equal validity would give rise to substantially different results. As a result, future cash flows calculated under this methodology are not necessarily indicative of the Group’s future cash flows nor the fair value of its oil reserves.

The net price used in the forecast of future net revenue is the weighted average year end price received for sales domestically, for exports to Commonwealth of Independent States (“CIS”) countries, and for exports to non-CIS countries, after adjustments, where applicable, for certain costs, duties, and taxes. The weighted average net prices per tonne used in the forecasts for 2002, 2001, and 2000, are US $93.81, US $81.89 and US $115.25, respectively. As described in the previous section, the Group has disclosed standardized measure of discounted future net cash flows for periods up to and past license expiry dates separately.

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Cash Flows (continued)

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserve Quantities

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(expressed in millions of constant Russian Roubles of December 31, 2002 purchasing power, except as indicated)

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserve Quantities (continued)

At your request, we estimated the net oil and gas reserves and future net revenues as of January 1, 2003, for Tatneft JSC (Tatneft) in certain oil fields of Tatarstan. The properties evaluated are located in the Volga-Ural Oil Basin and include 63 developed and producing oil fields containing approximately 28,531 active completions (20,257 producers and 8,274 injectors) and 7 undeveloped oil fields. Attachment 1 is a location map of the Republic of Tatarstan that shows the producing areas.

We performed our evaluations, which are designated as the Constant Price Case, using the prices and expenses provided by Tatneft. The Constant Price Case assumes no future escalations of oil or gas prices, operating expenses, capital, or taxes above the respective January 1, 2003 values. The aggregate results of our evaluations for Tatneft are as follows:

Proved reserves may be further divided into volumes produced before and after the expiration dates of their respective field production licenses. On this basis, as of January 1, 2003, the estimated proved reserves and future net revenues that are forecast until the time of current license expirations are as follows:

The estimated proved reserves and future net revenues forecast for the time period following current license expiration dates, assuming renewal of the licenses, are as follows:

Proved, probable, and possible reserves were estimated in accordance with standards of the Society of Petroleum Engineers, Inc. and World Petroleum Congresses as defined on Attachment 2. The estimated net reserves are the same as the gross reserves. The unified tax (previously a combination of royalty, mineral replacement tax, and crude oil excise tax) was deducted from gross revenues in determining net revenues but was not deducted from gross reserves in determining net reserves. Reserves were projected for the economic life of the field, without consideration of production or exploration license terms.

Future net revenues as used herein are defined as the total gross revenues less unified tax, operating costs, and capital expenditures. The total gross revenues are the total revenues received by Tatneft after deduction of transportation costs, export and customs duties, port expenses, excise tax, value added tax, and special taxes. The oil and gas prices employed in the computations of gross revenues were provided by Tatneft and are shown on Attachments 3 and 4. Future net revenues do not include deductions for either federal or local taxes on net profit.

The operating expenses employed in estimating future net revenues are the average operating expenses for the year 2002 that were provided by Tatneft. We removed from the operating expenses the depreciation, well restoration costs, and the unified tax. Restoration costs were included as capital for the portion of the proved nonproducing reserves attributed to the restoration of shut-in wells. The operating expenses for Tatneft are shown on Attachment 5.

We allocated a portion of the operating expenses to the number of active wells on a per-well basis and the remainder to the oil production rates on a per-barrel basis, employing the allocations provided to us by Tatneft. We assumed that the number of active wells for the large waterfloods would decline to approximately one-half the fully developed well count estimated in last year’s evaluation as the fields declined in production and approached their economic limit.

Future capital costs for drilling and workover operations are based on 2002 costs provided by Tatneft and are shown on Attachment 6. The forecasts for capital expenditures, other than drilling and completions, were based on data provided by Tatneft through the year 2018 and are shown on Attachment 7.

The proved developed producing reserves and production forecasts were estimated by production decline extrapolations, water-oil ratio trends, or in a few cases, by volumetric calculations. For some reservoirs with insufficient performance history to establish trends, we estimated future production by analogy with other reservoirs having similar characteristics. Production declines were extrapolated to economic limits based on operating cost and oil price data. The past performance trends of many reservoirs were influenced by production curtailments, workovers, waterfloods, and/or infill drilling; extrapolations of future performance are based, whenever possible, upon the average performance trend of active wells during periods of stable field activity.

The estimated proved developed nonproducing reserves can be produced from existing well bores but require capital costs for workovers, recompletions, or restoration of shut-in wells. For wells shut in awaiting mechanical repair, we assumed that the wells producing at rates greater than the economic limit at the time of shut in will be returned to production at pre-shut-in levels and will decline in production at the average reservoir decline rate. For wells requiring recompletion, the estimates of reserves and producing rates are based on volumetric calculations and analogies with other wells that commercially produce from the same formation in the same field.

The estimated proved undeveloped reserves require significant capital expenditures, such as (1) costs for future development and infill wells and (2) surface facilities. The proved undeveloped reserves are

expected to be produced from undeveloped portions of known reservoirs that have been adequately defined by wells. Reserve estimates are based upon volumetric calculations that employ recovery factors based on the performance of analogous reservoirs. Producing rates are based upon analogy.

The estimated probable and possible reserves are mainly undeveloped and require significant capital expenditures. As new wells are drilled, portions of these probable and possible reserve quantities will be either upgraded to a higher reserve category or dropped entirely. The estimated probable reserves are expected to be produced from undeveloped portions of known reservoirs not adequately defined to be classified as proved. Two additional components of probable reserves were included for currently producing reservoirs. For reservoirs that are noncommercial or will become noncommercial while still producing significant volumes of oil, it was assumed that these reservoirs could be made commercial by shutting in high water-cut wells. These reserves are considered probable rather than proved because of the uncertainty of results from shutting in the high water-cut wells. Also, certain reservoirs under waterflood may decline in production by a hyperbolic decline trend rather than a linear exponential trend as was assumed for proved developed producing reserves. For these reservoirs, we classified the incremental reserves as probable. The estimated possible reserves are expected to be produced from undeveloped portions of known reservoirs (1) where the reservoir is thin and uncertain to be developed or (2) where subsurface control is limited. Estimates of reserves for undeveloped portions of known reservoirs were estimated by volumetric methods.

Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced.

The probable and possible reserve volumes and the estimated future net revenues therefrom have not been adjusted for uncertainty. None of the proved, probable, or possible reserve volumes, nor the revenues projected therefrom, should be combined with either of the other without adjustment for uncertainty. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves. Future costs of abandoning facilities and wells and any future costs of restoration of producing properties to satisfy environmental standards were not deducted from total revenues as such estimates are beyond the scope of this assignment.

Estimated net gas reserves are based upon the past ratio of sales gas to produced oil. Net gas reserves do not represent the total volumes of gas expected to be produced with the net oil reserves.

Structural maps, isopach maps of net oil sand, well status maps, seismic data, cross sections, oil and water production data, well logs and core information on key wells, and the Tatneft interpretation of key reservoir parameters were provided by Tatneft. These were reviewed in detail and were generally found to be acceptable interpretations. In certain cases, where appropriate, original maps were prepared. The reservoir maps were employed to estimate original oil in place and to classify the potentially productive areas as either proved developed producing, proved developed nonproducing, proved undeveloped, probable, or possible. Volumetric methods were employed to estimate the original oil in place for each classified area.

Attachment 8 shows a composite production forecast for Tatneft. This figure shows the contribution of production from each proved reserve category. Following the attachments are one-line summaries in both barrels and tonnes that show reserves and cumulative future net revenues for each evaluated field. Tatneft assigned fields to specific groups, which are also identified in the one-line summaries.

Following the one-line summaries are exhibits that are projections of future production and net revenues for each reserve category and group.

In conducting this evaluation, we relied upon (1) production histories, (2) accounting and cost data, (3) ownership, (4) geological, geophysical, and engineering data, and (5) drilling, recompletion, and workover schedules supplied by Tatneft. These data were accepted as represented, as verification of such data and information was beyond the scope of this assignment.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.

Yours very truly,

MILLER AND LENTS, LTD.

By		/s/ GEORGE SCHAEFER
		George Schaefer, P. E. Senior Vice President

Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further subclassified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.

The intent of the SPE and WPC in approving additional classifications beyond proved reserves is to facilitate consistency among professionals using such terms. In presenting these definitions, neither organization is recommending public disclosure of reserves classified as unproved. Public disclosure of the quantities classified as unproved reserves is left to the discretion of the countries or companies involved.

Estimation of reserves is done under conditions of uncertainty. The method of estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data. The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities. Identifying reserves as proved, probable, and possible has been the most frequent classification method and gives an indication of the probability of recovery. Because of potential differences in uncertainty, caution should be exercised when aggregating reserves of different classifications.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations. Proved reserves can be categorized as developed or undeveloped.

If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate.

Establishment of current economic conditions should include relevant historical petroleum prices and associated costs and may involve an averaging period that is consistent with the purpose of the reserve estimate, appropriate contract obligations, corporate procedures, and government regulations involved in reporting these reserves.

In general, reserves are considered proved if the commercial producibility of the reservoir is supported by actual production or formation tests. In this context, the term proved refers to the actual quantities of petroleum reserves and not just the productivity of the well or reservoir. In certain cases, proved reserves may be assigned on the basis of well logs and/or core analysis that indicate the subject reservoir is hydrocarbon bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

The area of the reservoir considered as proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) the undrilled portions of the reservoir that can reasonably be judged as commercially productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known occurrence of hydrocarbons controls the proved limit unless otherwise indicated by definitive geological, engineering, or performance data.

Reserves may be classified as proved if facilities to process and transport those reserves to market are operational at the time of the estimate or there is a reasonable expectation that such facilities will be installed. Reserves in undeveloped locations may be classified as proved undeveloped provided (1) the locations are direct offsets to wells that have indicated commercial production in the objective formation, (2) it is reasonably certain such locations are within the known proved productive limits of the objective formation, (3) the locations conform to existing well spacing regulations where applicable, and (4) it is reasonably certain the locations will be developed. Reserves from other locations are categorized as proved undeveloped only where interpretations of geological and engineering data from wells indicate with reasonable certainty that the objective formation is laterally continuous and contains commercially recoverable petroleum at locations beyond direct offsets.

Reserves which are to be produced through the application of established improved recovery methods are included in the proved classification when (1) successful testing by a pilot project or favorable response of an installed program in the same or an analogous reservoir with similar rock and fluid properties provides support for the analysis on which the project was based, and, (2) it is reasonably certain that the project will proceed. Reserves to be recovered by improved recovery methods that have yet to be established through commercially successful applications are included in the proved classification

program where the response provides support for the analysis on which the project is based and (2) it is reasonably certain the project will proceed.

Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be further classified as probable reserves and possible reserves.

Unproved reserves may be estimated assuming future economic conditions different from those prevailing at the time of the estimate. The effect of possible future improvements in economic conditions and technological developments can be expressed by allocating appropriate quantities of reserves to the probable and possible classifications.

Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

In general, probable reserves may include (1) reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area, (3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favorable for commercial application, (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area, (6) reserves attributable to a future workover, treatment, re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behavior in analogous reservoirs, and (7) incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.

Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used, there should be at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves.

In general, possible reserves may include (1) reserves which, based on geological interpretations, could possibly exist beyond areas classified as probable, (2) reserves in formations that appear to be petroleum bearing based on log and core analysis but may not be productive at commercial rates, (3) incremental reserves attributed to infill drilling that are subject to technical uncertainty, (4) reserves attributed to improved recovery methods when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics are such that a reasonable doubt exists that the project will be commercial, and (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and geological interpretation indicates the subject area is structurally lower than the proved area.

Reserve status categories define the development and producing status of wells and reservoirs.

Developed: Developed reserves are expected to be recovered from existing wells including reserves behind pipe. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be subcategorized as producing or nonproducing.

Producing. Reserves subcategorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Nonproducing. Reserves subcategorized as nonproducing include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

Undeveloped: Undeveloped reserves are expected to be recovered (1) from new wells on undrilled acreage, (2) from deepening existing wells to a different reservoir, or (3) where a relatively large expenditure is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

One-line summaries of reserves and cumulative future net revenues for each evaluated field and projections of future production and net revenues for each reserve category and group have been omitted.

The information presented herein is presented on the basis of official public documents, including, without limitation, the laws, regulations and rules cited therein, and has been presented on the authority of such documents unless otherwise indicated.

Since the dissolution of the Soviet Union, the oil industry in Russia has undergone a major restructuring. Under the Soviet regime, the incentive system focused on the quantity of crude oil produced without regard to the quality of the oil. Furthermore, the prices for oil and refined products were maintained by the state at artificially low levels, and the maximization of economic value played little or no part in the production decisions. As a result, producers had little incentive to produce crude oil from which a relatively high percentage of premium products could be refined, and over-production and under-maintenance of equipment were widely prevalent in the system.

The privatization of the Russian oil industry was launched by Presidential Decree No. 1403, issued on November 17, 1992, which established the federal framework for privatizing Russian oil companies and the basis for the transformation of state-owned exploration, production, refining and distribution enterprises into several major vertically integrated companies. At December 31, 2002, there were eight major integrated Russian oil companies: LUKOIL, YUKOS, Surgutneftegas, Slavneft, Sidanco, Tyumen Oil Company (TNK), Sibneft and Rosneft. Initially, these entities essentially functioned as holding companies with shares in separate production, refining and distribution subsidiaries. The process of vertical integration of such companies was facilitated by a further Russian Presidential decree No. 327 issued on April 1, 1995, allowing the integration of subsidiaries into vertically integrated companies through share exchanges.

Other major Russian oil companies, such as Tatneft, also possess significant crude oil reserves and exploration and production capabilities, but do not currently possess significant independent refining capabilities. These entities were also formed through the transformation of separate state-owned exploration and production enterprises into new companies during the privatization process.

The Russian government’s shares in several vertically-integrated oil companies were placed under trust management with banks and other institutions in the “loan-for-shares” program held in late 1995 under which the institutions extended loans to the Government in return for the right to manage the shares. When these loans were not repaid at maturity, the lending institutions generally acquired the right to sell the stakes they had managed to settle the loans, which has resulted in the sale of the managed shares of Surgutneftegas, Sidanco, Sibneft and YUKOS.

The Russian government continues to privatize Russian oil companies which are currently under its control. Only one of these, Rosneft, currently remains wholly state-owned. The Russian government stated in the past that it intended to create a new oil holding company, National Oil Company, by merging Rosneft with Slavneft and Onako, but in June 2000 indicated its intention to sell the Government’s stakes in Slavneft and Onako separately through privatization auctions. Privatization of an 85% government stake in Onako was completed in 2000. In May 2002, the government sold 36.82% of Eastern Oil Company (VNK) through an auction to YUKOS and sold approximately 6% in LUKOIL in December 2002. In November 2002, the government of the Belarus Republic sold its 10.83% stake in Slavneft to a consortium of shareholders of TNK and Sibneft, and the Russian government sold its 74.95% in Slavneft at an auction held on December 18, 2002 to the same consortium.

The Russian oil industry has also recently undergone a wave of consolidation. On February 11, 2003, Alfa Group, Access-Renova (together, TNK’s, Onako’s and Sidanko’s majority shareholders) and BP announced plans to combine their oil and gas operations in Russia and Ukraine. The new holding company, to be created on the basis of the combined assets of TNK, ONAKO and Sidanco on the one hand and BP’s Russian assets on the other hand and owned 50% each by BP and the combined Alfa-Access-Renova, will become the third-largest oil company in Russia by reserves and production. On April 22, 2003, YUKOS and Sibneft announced that their respective shareholders had reached an agreement in principal on effecting a merger. If this merger is consummated, the combined YukosSibneft will be the largest oil company in Russia by both reserves and production and one of the largest oil companies in the world.

The various oil companies differ as to their size of operations, geographic focus and management philosophy. Moreover, the Russian government has applied different policies with respect to such companies at various times during the privatization process.

Some companies seek foreign ventures beyond neighboring countries, while others concentrate primarily on opportunities in their historical region of operations or within the former Soviet Union. In addition, Russian oil companies may acquire additional assets in the ongoing privatization process, or through mergers or other forms of combination.

Russian methodologies for calculating reserves and Russian reserves classifications differ materially from accepted practices in the United States and other parts of the world. Reserves calculations performed using different methodologies cannot be accurately reconciled.

Under the Russian classification system, reserves are subdivided depending on their degree of substantiation into the following categories: explored reserves represented by the categories A, B and C1; preliminary estimated reserves represented by the category C2; and forecast resources represented by the categories D1 and D2. Russian reserves calculations have historically not used economic assumptions in estimating reserves. Generally, Russian methodologies classify oil and gas deposits as reserves if such deposits are technically recoverable, even if the recovery of a portion of such reserves using currently available technology is uneconomic. In contrast, the U.S. methodology classifies oil and gas deposits as reserves only if such deposits are economically extractable on the basis of existing technologies, prices and costs. Legislation is being considered that would incorporate economic criteria, but reserves calculated under the existing classification system will not have the benefit of any economic analysis.

Oil production in Russia declined between the late 1980s and 1997. The decrease in production was attributable to many factors, including overproduction of wells during the Soviet period, lack of funds for capital expenditures to maintain operations, inefficient secondary recovery methods, insufficient transportation capacity in the pipeline system, losses during transit and reduced demand attributable to the Russian economic recession. In 1997, production increased by approximately 1.3% to approximately 305 million tons. In 1998, production decreased by approximately 0.8% to 303.2 million tons. In 1999, Russia produced 305.0 million tons, an increase of 0.6% over 1998. In 2000, Russia produced approximately 312.7 million tons of crude oil, a 2.5% increase over 1999. In 2001, Russia produced approximately 336.9 million tones of crude oil, a 7.7% increase over 2000. In 2002, Russia produced approximately 379.6 million tons of crude oil, a 12.7% increase over 2001. The rise in production in recent years resulted from

several factors, including relatively high world and domestic oil prices, increased rehabilitation of non-operational wells and increased export opportunities.

In general, reforms in regulation are now prompting the Russian oil industry to adopt commercially-oriented production practices. These reforms included the liberalization of crude oil and refined product prices and the elimination of export quotas and licensing requirements in early 1995. Domestic pricing remains, however, significantly below world levels, hampering the ability of companies to reinvest or modernize production practices, equipment and facilities. The following table shows approximate crude oil production levels of the largest Russian oil companies in 2002, 2001 and 2000:

Domestic oil prices in Russia do not reflect world levels or international supply and demand fundamentals. While crude oil production in Russia has fallen in recent years, demand has fallen further, leading to excess domestic supplies of crude oil. This decline in demand, combined with constraints on exports, has kept domestic prices low and hindered a significant real increase in the domestic price of crude oil. In addition, in June 1999 the Russian government signed an agreement with leading Russian industries to impose price controls on energy, metals and transportation, furthermore hindering the increase in the domestic price of crude oil. Nonetheless, at times, selling crude oil domestically has been more profitable than exporting it in light of transportation costs, the taxation regime and the margins available on refined products. In addition, the Russian vertically-integrated oil companies are generally seeking to increase the utilization of their refining capacities.

Prior to 1995, Russia carried out a policy of controlling domestic oil prices and exports in order to ensure a low-cost domestic supply of crude oil. Beginning in 1995, oil prices have been liberalized by elimination of these controls. Moreover, there has been substantial liberalization of the program of mandatory sales at fixed prices to governmental authorities.

In the second quarter of 1998, domestic crude oil prices, which had been previously unaffected by the decline in world market prices, decreased significantly. This reduced the profitability of domestic crude oil sales and had a negative impact on the operations of Russian oil companies. The increase in world and domestic oil prices in the second part of 1999 has significantly helped Russian oil companies to increase profitability. World oil prices have increased significantly since January 1999, when the price was approximately US$10.33 per barrel. The average prices of Brent crude, an international benchmark oil, for the three years ended December 31, 2002, 2001 and 2000, were approximately US$24.98, US$24.46 and US$28.50 per barrel, respectively. Crude oil prices increased during 2002 over the level at the end of 2001 as a result of export restrictions imposed by OPEC and certain other crude oil producing nations, including Russia, improving global economic conditions, uncertainty with respect to the situation in Iraq and the Middle East move generally and domestic unrest in Venezuela that temporarily restricted production. Domestic prices have also risen approximately from US$30-US$35 per ton in January 1999 to an average of US$91.60 per ton for 2001, declining in 2002 to an average of US$83.70.

Russian oil companies have significantly increased their crude oil exports since 1991 in light of the fall in domestic demand, a substantial gap between domestic and foreign prices and the elimination of export quotas and licensing requirements. Access to Transneft’s pipeline network is regulated by Russian government authorities. Since September 11, 2001, the pipeline capacity, including export pipeline capacity, and sea terminal access have been allocated among oil producers and their parent companies in proportion to the volumes of oil produced and delivered to the Transneft pipeline system, and not in proportion to mere oil production levels, as in the past. Limitations on access to the pipeline network act as a constraint on the ability of producers to export crude oil, and limited port, shipping and railway facilities further constrain exports of crude oil. Furthermore, Russian oil companies are required to pay taxes owed to the Russian government in order to maintain their access to export pipelines and sea ports. See “—Crude Oil and Refined Product Transportation.”

In 2002, Russia exported approximately 154.6 million tons of crude oil to non-CIS countries, a 6.4% increase from 2001. The following table shows approximate export volumes of crude oil for deliveries to non-CIS countries by certain Russian oil companies in 2002, 2001 and 2000:

The current refinery market in Russia is characterized by overcapacity. Refinery utilization since 1995 has remained at approximately 60%. Primary oil refining changed slightly from 174.5 million tons in 2000, to 178.4 million tons in 2001 and to 174.8 million in 2002. These low utilization rates reflect the reduced demand for refined products, the inability of a substantial number of customers to pay for refined products and lack of capital expenditures to maintain operations.

Regulation of the oil industry in Russia is still evolving, with federal, regional and local authorities each promulgating rules.

At the federal level, the Ministry of Energy is the principal authority that sets governmental policy for the industry and coordinates the activities of oil companies. The Federal Energy Commission and the Government Commission on the Use of Trunk Oil and Gas Pipelines and Oil Products Pipelines, or the Pipelines Commission, coordinates the activities of various federal executive agencies to address issues in the oil industry, including issues related to access to Transneft’s truck oil pipelines and tariffs. The Ministry of Natural Resources, or its regional department, licenses the use of subsoil resources together with the relevant regional authority, as described below, and oversees exploration and geological prospecting for the oil and gas industries. In certain circumstances (such as the use of subsoil resources on the continental shelf), licenses are granted by the government of the Russian Federation.

Federal legislation also affords a measure of autonomy to regional and local authorities to exercise rights to the use of natural resources and provides that the use of subsoil is under the joint jurisdiction of the federal and regional authorities. While the federal Law on Use of Subsoil of February 21, 1992, as amended (the “Subsoil Law”) contains a supremacy clause establishing the preeminence of Russian federal law over contradictory regional or local laws, authorities at the regional or local level may have

substantial practical authority over the operations of an oil company in a particular location. Regional authorities must generally approve any subsoil resource license granted by the Ministry of Natural Resources. Regional and local authorities enforce their taxation regimes, administer land-use regulations and oversee compliance with environmental and worker safety rules. Local and regional authorities also exercise some control over the use of the national and local pipeline grid through their jurisdiction to regulate land use and environmental matters.

Government Resolution No. 307, dated April 8, 1994 (“Resolution 307”), permitted oil companies to stop all oil deliveries to customers who fail to make payments within fifteen days of delivery. Even though the Resolution 307 was subsequently abolished, Article 523 of the Civil Code of the Russian Federation enables the supplier of goods to unilaterally refuse to fulfill supply contract in the event of repeated violations of supply terms of payment for the goods by the buyer. However, Government Resolution No. 364, dated May 29, 2002, exempted strategic organizations providing for national security, such as the military, federal nuclear centers, and centers for air, rail, and maritime traffic control, from the force of the Resolution 307 and the exemption is still valid. Oil deliveries to these organizations within the limits set by Russian federal agencies, may neither be limited nor cut off regardless of non-payment.

The licensing regime for use of subsoil for geological research, exploration and production of mineral resources is established primarily by the Russian Federal Law on Subsoil, dated February 21, 1992 and March 3, 1995 (as amended), referred to in this section as the Subsoil Law, is Regulations on Licensing of Subsoil Use, dated July 15, 1992, and the Regulation on Licensing of Certain Activities with Respect to Geological Exploration and the Use of Subsoil, dated July 31, 1995. Until January 2000, when important amendments to the Subsoil Law were introduced, exploration licenses were typically granted for up to five years, while production licenses were granted for up to 20 years and licenses for combined activities were granted for up to 25 years. Under the Subsoil Law, as currently in effect, the maximum term of an exploration license remains five years and a production license may be issued for the useful life of the mineral reserves field, calculated on the basis of a feasibility study for exploration and production that ensures rational use and protection of the subsoil. A license recipient is also usually granted rights to use the land surrounding the license area.

Generally, production licenses and combined exploration and production licenses are awarded by tender or auction held by the Ministry of Natural Resources or its regional Resources division and the executive body of the corresponding political subdivision of the Russian Federation. The winning bidder in a tender is expected to submit the most technically competent, financially attractive and environmentally sound proposal that meets published tender terms and conditions. However, in accordance with the January 2000 amendments to the Subsoil Law, licenses for geological exploration and production may be issued by decision of the Russian Federal government or by the joint decision of the authorized agencies at the Russian Federation and regional levels (without the holding of an auction or tender), to subsoil users that have discovered mineral resource deposits through exploration work conducted at their own expense.

Under the January 2000 amendments to the Subsoil Law, exploration licenses may also be issued by the Ministry of Natural Resources or its regional division without a tender or auction. A holder of an exploration license who conducts geological exploration at its own expense and discovers mineral reserves may receive a production license without submitting to a tender or auction process.

Licenses may be transferred only under certain limited circumstances that are identified in the Subsoil Law, including the reorganization or merger of the license holder or in the event that an initial license holder transfers its license to a legal entity in which it has at least a 50% ownership interest, provided that the transferee possesses the equipment and authorizations necessary to conduct the exploration or production activity that is covered by the transferred license.

A license holder has the right to develop and sell oil extracted from the license area. The Russian Federation, however, retains ownership of all subsoil resources at all times, and the license holder only has rights to the crude oil when extracted.

The licenses generally require the license holder to make various commitments, including:

Article 10 of the Russian Federal Law on Subsoil, dated February 21, 1992 and March 3, 1995 (as amended) provides that a license to use a field may be extended at the initiative of the license holder where the license holder complies with the terms of the license and where the development of the field requires completion or liquidation. We intend to extend our licenses for each of our fields that are expected to continue to produce subsequent to the end of their current periods. However, in the event that the Russian government determines that we have not complied with the terms of one of our licenses, it may not exceed the license upon the expiration of its current period.

Governmental authorities may undertake periodic reviews for ensuring compliance by subsoil license users with the terms of their licenses and applicable legislation. A licensee can be fined for failing to comply with the subsoil production license and the subsoil production license can be revoked, suspended or limited in certain circumstances, including:

In addition to a subsoil production license, permission to use surface land within the specified licensed area is necessary and is normally granted by the regional authority.

Land use permits are typically issued with respect to specified areas, upon the submission of standardized reports, technical studies, pre-feasibility studies, budgets and impact statements. A land use permit generally requires that the holder make lease payments and revert the land plot to a condition sufficient for future use, at the licensee’s expense, upon the expiration of the permit.

Beginning January 1, 2002, the previously existing system of payments for the use of subsoil was modified by merging royalties, excise taxes and mineral restoration payments into a single tax called the unified natural resources production tax. Further, based on amendments to the Subsoil Law, the following types of payment obligations were established:

The rates at which payments are to be levied are usually established by regional authorities within a range of minimum and maximum rates established by the Russian government pursuant to the Subsoil Law.

Petroleum operations carried out under production sharing agreements, or PSAs, are governed by separate laws. A PSA is a contract between the Russian government on the federal level and the regional authority or its authorized body on the regional level, acting on the Russian government’s behalf, and one or more investors whereby the investor agrees to bear the costs and risks of exploration and production of a mineral resource and the parties agree to share the output in predetermined proportions. PSAs aim to reduce an investor’s risk by providing a stable legal and fiscal framework for long-term and large investments. Since the enactment of the Law on Production Sharing Agreements in 1995, a number of oil fields were approved by other federal laws as eligible for PSAs. However, to date, very few PSAs have been conducted with respect to these fields.

PSA laws provide that operations conducted under a PSA are to be governed by the PSA itself and not be affected by contrary provisions of any other legislation, including laws relating to subsoil licenses. Furthermore, PSAs entered into by the Russian government prior to the enactment of the PSA laws are recognized under a grandfather clause.

From 1995, as part of its plan to deregulate prices and liberalize export controls, the Russian government established equal pipeline and sea terminal access procedures for all oil companies in proportion to the actual production volume of each company. This system allowed Russian oil companies to export, on average, 30-35% of crude oil produced.

Approximately 92% of the oil produced in Russia is transported through Transneft, a state-owned monopoly oil pipeline owner and operator. Transportation of oil is based on contracts with Transneft and its subsidiaries, which set forth the basic obligations of the contracting parties, including the right of Transneft to blend or substitute a company’s oil with oil of other producers. Transneft establishes and collects on prepayment terms a ruble tariff on domestic shipments and an additional hard currency tariff on exports. The Federal Energy Commission periodically reviews and sets the tariff rates applicable for each segment of the pipeline. The Druzhba pipeline, which is operated by Transneft in Russia and extends from central Russia to markets in Poland, Germany, Hungary and Slovakia, has throughput capacity of approximately 1.5 million barrels of oil per day and currently accommodates over a third of total Russian exports.

Currently, the allocation of pipeline and sea terminal access rights is overseen by the Pipelines Commission, which approves quarterly schedules that, among other things, detail the precise volumes of oil that each oil producer can pump through the Transneft system. These quarterly schedules provide certain stability in the export regime for Russian oil companies. Once the access rights are allocated, oil producers generally cannot increase their allotted capacity in the export pipeline system, although they do have limited flexibility in altering delivery routes. Oil producers are generally allowed to assign their access rights to third parties.

In 2001, the Russian government began reforming the system of pipeline allocation and sea terminal access rights. Since September 2001, pipeline and sea terminal access rights have been distributed among oil producers and their parent companies in proportion to the volumes of oil produced and delivered to the Transneft pipeline system (and not in proportion to oil production volumes).

Transneft has a very limited ability to transport individual batches of crude oil, which results in the blending of crude oil of differing qualities. Transneft does not currently operate a system whereby companies shipping heavy and sour (high sulfur) crude would compensate the shippers of higher-quality crude oil for deterioration in crude quality due to blending. Although the introduction of a blending compensation system is currently under discussion between Transneft and the Russian government, these proposals are generally met with aggressive resistance from producers with reserves of a lower quality and regional authorities where such reserves are located.

Petroleum products are transported by similar means as crude oil, including railways, sea transportation and specially designed pipelines for petroleum products. The majority of petroleum products, however, are transported by railways. The regime for the transportation of petroleum products is generally similar to the regime for the transportation of crude oil. In particular, the rules provide for equal access to petroleum products pipelines, which currently transport primarily gasoline and diesel fuel.

In the past, the Russian government imposed seasonal limitations on the export of certain petroleum products (such as diesel fuel, fuel oil, gasoline and jet fuel). No such restrictions are in effect at present. However, the Ministry of Energy has proposed seasonal regulation of export duties on petroleum products and the imposition of state non-tariff limitations on the domestic petroleum products market.

To protect national economic interests, the Russian government implements tariff regulations through the use of export duties. The amount of export duties vary depending on the country’s demand for petroleum products and existing crude oil prices.

Petroleum operations are subject to extensive federal and regional environmental laws and regulations. These laws and regulations set various standards for health and environmental quality, provide for penalties and other liabilities for the violation of such standards, and establish, in certain circumstances, obligations to compensate for environmental damage and restore environmental conditions.

The Russian Federal Law on Environmental Protection, dated January 10, 2002, established a “pay-to-pollute” regime administered by the Ministry of Natural Resources and regional authorities.

Natural resources development matters are subject to periodic environmental evaluation. While these evaluations have in the past generally not resulted in substantial limitations on natural resources exploration and development activities, they are expected to become increasingly strict in the future.

In general, the Russian oil industry is subject to the same burdensome tax regime as other industrial companies. In addition, the oil companies are subject to industry-specific taxes. As noted above under “Crude Oil and Refined Product Transportation,” the Russian government has imposed restrictions on the export of crude oil and oil products by companies that have arrears to tax authorities at any level of government.

Federal Law No. 126-FZ of August 8, 2001, which became effective on January 1, 2002 (the “Natural Resources Tax Law”), amended the previously existing regime of mineral resource restoration payments, royalties and excise taxes on the production of oil and gas condensate and replaced all such taxes with a unified natural resources production tax.

From January 1, 2002 until December 31, 2004, the natural resources production tax with respect to crude oil will be based on the amount of oil produced. The tax rate applicable from January 1, 2002 until December 31, 2004, will be RR340 per ton of crude oil, subject to an adjustment using a special coefficient reflecting the dynamics of world oil prices and the ruble/U.S. dollar exchange rate. This coefficient will be applicable on a monthly basis and will represent a ratio in which (i) the numerator is the product of (x) the ruble/U.S. dollar average monthly exchange rate and (y) the difference between monthly average oil prices per barrel for “Urals” blend and US$8 and (ii) the denominator equals 252. For the year ended December 31, 2002, the average rate was RR668 per ton of crude oil, and as at December 31, 2002 the rate was RR753 per ton. On June 21, 2003, the State Duma, the lower house of Russia’s parliament, passed a bill increasing the rate of the unified natural resources production tax to RR357 per ton of crude oil produced starting from January 1, 2004. The Federation Council passed this bill on June 25, 2003. For this increase to become effective, the President must also approve it.

Starting from January 1, 2005, the tax base for the natural resources production tax will be determined as the value of extracted natural resources which may be calculated by reference to actual sale prices of natural resources or the deemed value of natural resources. With respect to the production of oil and oil condensate, the natural resources production tax will be levied at the rate of 16.5% of the value of extracted natural resources.

In early 1999, the government reintroduced export customs duties on crude oil and oil products. Following increases in world oil prices, the export customs duties have been steadily increasing. In September 2001 the Law on Customs Tariff (the “Law on Customs Tariff”) was amended to establish the rates of export customs duties for crude oil based on the average price of “Urals” blend for the two preceding months.

The rates of customs duties established by the Russian government in accordance with the framework set in the amended Law on Customs Tariff are as follows:

Oil-related Payments for the Right to Explore and Appraise Oil Fields and Prospect for Natural Resources

Historically, Russian oil companies made payments for the right to explore and appraise oil fields, as well as payments for the right to prospect for natural resources as a percentage of the value of exploration and appraisal works (1-2%) and the value of prospecting works (3-5%).

Starting from 2002, Federal Law No.126-FZ of August 8, 2001 introduced a new approach to the calculation of both the base and rate for these payments. This law linked the payments to the size of the license area provided to the user of the subsoil. The minimum and the maximum rates of quarterly payments are set by Federal law No 57-FZ of May 29,2002: (i) the rate for the right to explore and appraise oil fields is from RR120 (RR50 for offshore areas) per square kilometer to RR360 (RR150 for offshore areas) rubles per square kilometer and set by the regional authorities; (ii) the rate for the right to prospect for natural resources from RR5,000 (RR4,000 for offshore areas) per square kilometer to RR20,000 (RR16,000 for offshore areas) square kilometer as set by the regional authorities. Exact rates for specific areas are to be set by regional authorities for onshore areas and the Ministry of Natural Resources for offshore areas. Where these specific rates have not been set, the above maximum rates shall apply.

Historically gasoline, diesel fuel and motor oils were subject to a Fuel Sales Tax at 25% of their value. Excise tax was payable only with respect to gasoline. At January 1, 2001, the Fuel Sales Tax has been abolished, whereas Excise Tax became applicable to all of the above products. The current rates are as follows:

The following is not intended to be a comprehensive description of Tatarstan or its laws, but only to summarize briefly some of the principal factors that may affect the position of the Company in relation to other Russian oil producers. The information presented herein is presented on the basis of official public documents, including, without limitation, the laws, regulations and rules cited therein, and has been presented on the authority of such documents unless otherwise indicated.

Tatarstan occupies an area of 68,000 square kilometers in the center of the Volga-Urals basin, approximately 750 kilometers east of Moscow. It has a population of 3.8 million people, of whom nearly half are ethnic Tatars and over 40% are ethnic Russians. Tatars are predominantly Muslim and, in addition to Russian, generally speak Tatar, a Turkic language.

During the Soviet era, Tatarstan was known as the Tatar Autonomous Soviet Socialist Republic (“Tatar ASSR”) and was one of 22 such autonomous republics. In August 1990, Mintimer Shaimiev, Chairman of Tatarstan’s highest legislative body, the Supreme Soviet, who later became President of the Republic, signed the Declaration of State Sovereignty (“Declaration”) proclaiming that Tatarstan had primary jurisdiction over all Russian and Soviet state enterprises in the territory of Tatarstan and that the constitution and the laws of Tatarstan prevailed on its territory. The Russian government ignored these claims. At the time of the dissolution of the Soviet Union and the establishment of the Russian Federation by Decree of the Russian President in December 1991, Tatarstan was one of only two autonomous republics not to sign the Federal Treaty defining the Russian Federation (the other was Chechnya). In February 1992, Tatarstan officially changed its name to the Republic of Tatarstan, and in March 1992 a popular referendum declared Tatarstan to be “a sovereign state and a subject of international law associated with the Russian Federation.”

The Constitutional Court of Russia declared this referendum invalid, and Russia began to exert economic and political pressure on Tatarstan, including the denial to Tatar enterprises of access to the Russian financial system. As a result of bilateral negotiations, the “Treaty on the Demarcation of Areas of Responsibility and the Mutual Delegation of Powers Between the Organs of State Power of Russia and the Organs of State Power of the Republic of Tatarstan” (the “Russia-Tatarstan Treaty”) was signed in February 1994. The Russia-Tatarstan Treaty recognizes both the economic interdependence of Russia and Tatarstan and Tatar sovereignty over the natural resources in the region. Pursuant to the Russia-Tatarstan Treaty, Tatarstan is a state “united with the Russian Federation” with sovereign jurisdiction over its own natural resources, state enterprises and organizations and movable and immovable property situated on the territory of Tatarstan (with the exception of enterprises in “federal property”, and Tatarstan law controls with respect to such matters. Russian federal legislation is controlling, however in respect of rights to “federal property”; financial, currency, credit and customs regulations; the issuance of money; the federal budget and the imposition of federal taxes; civil and criminal law; and a number of other fields.

Since the signing of the Russia-Tatarstan Treaty, relations between Russia and Tatarstan have been stable, but uncertainty remains as to the validity of the laws of Tatarstan adopted prior to the conclusion of the Treaty and the scope of Tatarstan authority under new legislation. There has been no reassertion of power on the part of Russia, and no notable incident of disagreement concerning the Russia-Tatarstan Treaty provisions or the interpretation of the bilateral agreements adopted pursuant to the Russia-Tatarstan Treaty, some of which were automatically extended in 1999 for an additional five-year period.

Pursuant to Tatarstan’s Constitution enacted by Law No. 1665-XXI, dated November 6, 1992, pursuant to the results of a Tatarstan–wide referendum (the “Tatarstan Constitution”), as amended, the primary executive authority of Tatarstan is the Tatarstan President. The Tatarstan President has broad powers, including, among other things, directing the activities of local administrations within the Republic, signing all laws of Tatarstan, vetoing proposed legislation adopted by the State Council and canceling resolutions and orders of the Cabinet of Ministers. The current Tatarstan President, Mintimer Shaimiev, was re-elected for a five-year term on March 25, 2001.

The Tatarstan Prime Minister is nominated by the President and approved by the State Council. Other members of the Cabinet of Ministers, including the First Deputy Prime Minister, are appointed by the President in coordination with the State Council. The Cabinet of Ministers is responsible for day-to-day regulation of Tatarstan affairs. On May 11, 1998, the Republican State Council elected former Prime Minister Muhametshin as its Chairman, and Rustam Minnikhanov became Prime Minister in July 1998.

The legislative branch of Tatarstan is the State Council, a unicameral elected legislative body. Members of the State Council serve for terms of five years. The current members of the State Council were elected on January 21, 2000.

As a result of the division of powers between Russia and Tatarstan established in the Russia-Tatarstan Treaty, Tatarstan legislation differs from Russian legislation in a number of areas. See “—History of Relationship with Russia.” Some Tatarstan laws, particularly certain statutes adopted before the Russia-Tatarstan Treaty, are inconsistent with Russian law and some Tatarstan laws arguably do not fall within the exclusive jurisdiction of Tatarstan as defined by the Russia-Tatarstan Treaty. The validity and scope of such laws is therefore uncertain. In recent years, the Tatarstan legislature has adopted new legislation that has improved the correlation with existing federal legislation.

Below is a brief summary of the key areas of law regulated by Tatarstan and the main conflicts between federal and Tatarstan laws.

Two principal laws define the constitutional status of Tatarstan: the Declaration of the Supreme Council of the Republic of Tatarstan No. 334-XII, “On State Sovereignty of the Tatar Soviet Socialist Republic,” dated August 30, 1990 (the “Sovereignty Declaration”) and the Tatarstan Constitution, as amended. The Sovereignty Declaration proclaimed the independence of Tatarstan, as well as its exclusive right to ownership of all land, subsoil, natural and other resources. The Tatarstan Constitution was adopted pursuant to the Sovereignty Declaration. It contains several provisions common to those in the Russian Constitution, including provisions regarding human rights and an extensive chapter concerning the economic system. The Tatarstan Constitution provides that the basis of the Tatarstan economy shall be a social market economy and economic relations shall be grounded in a social partnership between the state and citizens, consumers and manufacturers, and employees and employers.

The Law of Tatarstan No. 1403-XII, “On Privatization of State Property in the Republic of Tatarstan,” dated February 5, 1992 (the “Tatarstan Privatization Law”), as amended, before May 27, 1998 provided that privatization of the property that belongs to Tatarstan, to other republics of Russia or to Russia itself, located on the territory of Tatarstan, should be conducted pursuant to the Tatarstan Privatization Law unless otherwise provided by agreements and treaties.

The Tatarstan Privatization Law differed from Russian privatization law in a number of respects. It gave full authority to the Tatarstan GKI, then Tatarstan’s privatization agency, to carry out privatization in Tatarstan without requiring the approval of the Russian privatization authorities. In the case of Tatneft, Russian Presidential Decree No. 1403, dated November 17, 1992, provided that it was to be privatized in accordance with Russian privatization law, with certain of its shares retained as federal property for three years.

The Tatarstan Privatization Law also provided, unlike Russian law, that shares sold for Tatarstan privatization vouchers were to be subject to a three-year holding period. Moreover, employees were permitted under the Tatarstan Privatization Law to purchase only up to 30% of the shares of their company at a discount from nominal value, while Russian law permitted purchases by employees of as much as 51% of the shares of the company in certain cases. After the expiration of the three-year holding period for the shares sold for Tatarstan privatization vouchers, an amendment to the Tatarstan Privatization Law, adopted on May 27, 1998, extended the holding period for an indefinite period of time for the Tatarstan enterprises that have a strategic importance to the Tatarstan economy, such as Tatneft. The same amendment has extended for an indefinite period of time the term of the Golden Share, that allows the Tatarstan government to participate in the management of the strategically important Tatarstan companies. The Tatarstan Privatization Law currently provides that the Golden Share can be terminated only by the decision of the authority that introduced it.

The identity of the Tatarstan governmental body which manages state property has changed several times. Pursuant to Resolution of the Tatarstan State Council No. 135, “On the Structure of the Cabinet of Ministers of the Republic of Tatarstan — the Government of the Republic of Tatarstan,” dated June 22, 1995, the original Tatarstan GKI was transferred to the State Committee of the Republic of Tatarstan on Industrial Policy and Management of State Property. Resolution of the Tatarstan State Council No. 527, dated April 25, 1996, changed the name of the committee to the State Committee of the Republic of Tatarstan on Matters of Industry and Management of State Property (the “GKPI”). At that time authority to conduct the Republic’s privatization program was shifted to a new entity, the State Committee on Privatization. Resolution of the State Council of the Republic of Tatarstan No. 873, dated November 27, 1996, merged the GKPI and the State Committee on Privatization and transferred authority to the re-established Tatarstan GKI, the Committee on Management of State Property, to hold and manage the interests of Tatarstan in companies undergoing privatization and to conduct the privatization of Tatarstan enterprises. Pursuant to the Decree of the President of the Republic of Tatarstan No. UP-360, dated May 11, 2001, as amended, the Tatarstan GKI has been replaced by the Ministry of Land and Property Relations.

The Russian Labor Code provides that constituent Russian states, regions, municipalities and other governmental entities are free to adopt labor rules more favorable to employees than those provided under Russian law. Historically, the most significant addition to existing Russian legislation contained in the Tatarstan labor legislation was a higher minimum monthly wage in Tatarstan. Currently, the minimum monthly wage in Tatarstan equals the minimum monthly wage established by the federal legislation, or RR450. However, for the purposes of calculating certain social payments in Tatarstan, the base amount of the monthly minimum wage is deemed to be RR350, compared to RR100 for the base amount for similar calculations at the federal level, resulting in higher social payments in Tatarstan.

Title of each class		Name of each exchange on which registered
Ordinary Shares, nominal value 1 Russian ruble per share		New York Stock Exchange, Inc.*
American Depositary Shares (“ADSs”) each representing 20 Ordinary Shares		New York Stock Exchange, Inc.

			Page

INTRODUCTION			1

FORWARD-LOOKING STATEMENTS			2

PART I			3

	ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT, AND ADVISORS	3

	ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	3

	ITEM 3.	KEY INFORMATION	4

		SELECTED FINANCIAL DATA	4

		EXCHANGE RATES	7

		CAPITALIZATION AND INDEBTEDNESS	7

		REASONS FOR THE OFFER AND USE OF PROCEEDS	7

		RISK FACTORS	8

	ITEM 4.	INFORMATION ON THE COMPANY	26

		BUSINESS OVERVIEW	26

		HISTORY AND DEVELOPMENT	26

		ORGANIZATIONAL STRUCTURE	28

		STRATEGY	30

		EXPLORATION AND PRODUCTION	31

		TRANSPORTATION	37

		REFINING AND MARKETING	37

		PETROCHEMICALS	41

		BANKING OPERATIONS	41

		COMPETITION	51

		ENVIRONMENTAL MATTERS	52

		CORPORATE REORGANIZATION	52

		RELATIONSHIP WITH TATARSTAN	53

		PROPERTY, PLANT AND EQUIPMENT	55

	ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	56

		OVERVIEW	56

		RESULTS OF OPERATIONS	62

		LIQUIDITY AND CAPITAL RESOURCES	73

		RESEARCH AND DEVELOPMENT	79

		LICENSES	80

		TRENDS INFORMATION	81

	ITEM 6.	DIRECTORS, SENIOR MANAGEMENT, AND EMPLOYEES	82

			Page

		DIRECTORS AND SENIOR MANAGEMENT	82

		COMPENSATION	87

		BOARD PRACTICES	87

		EMPLOYEES	90

		SHARE OWNERSHIP	91

	ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	93

		MAJOR SHAREHOLDERS	93

		RELATED PARTY TRANSACTIONS	95

		INTERESTS OF EXPERTS AND COUNSEL	95

	ITEM 8.	FINANCIAL INFORMATION	96

		CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION	96

		EXPORT SALES	96

		LEGAL PROCEEDINGS	96

		DIVIDENDS AND DIVIDEND POLICY	96

		SIGNIFICANT CHANGES	97

	ITEM 9.	THE OFFER AND LISTING	98

		MARKETS	98

	ITEM 10.	ADDITIONAL INFORMATION	102

		MEMORANDUM AND ARTICLES OF ASSOCIATION	102

		MATERIAL CONTRACTS	105

		EXCHANGE CONTROLS	105

		TAXATION	106

		DOCUMENTS ON DISPLAY	110

	ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	112

	ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	113

PART II			114

	ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES, AND DELINQUENCIES	114

	ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	114

	ITEM 15.	CONTROLS AND PROCEDURES	114

PART III			115

	ITEM 17.	FINANCIAL STATEMENTS*	115

	ITEM 18.	FINANCIAL STATEMENTS	115

	ITEM 19.	EXHIBITS	115

CERTIFICATIONS PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002			117

INDEX TO FINANCIAL STATEMENTS			F-1

APPENDICES

		Page
Appendix A Report of Reserves Consultants		A-1
Appendix B Overview of the Russian Oil Industry		B-1
Appendix C The Republic of Tatarstan		C-1
Appendix D Glossary of Terms and Conversion Table		D-1

	Year Ended December 31,
	2002		2001		2000		1999		1998
	(in RR millions, except per share information)
CONSOLIDATED STATEMENT OF OPERATIONS DATA
Sales and other operating revenues⁽¹⁾	145,483		155,511		199,503		82,707		51,016
Exploration and production⁽¹⁾	94,066		103,727		121,559		68,627		48,931
Intersegment sales	84,394		91,528		108,615		61,711		41,515
All other sales	9,672		12,199		12,944		6,916		7,416
Refining and marketing⁽¹⁾	125,673		139,082		184,085		75,791		43,600
Domestic sales	36,279		51,342		56,056		28,439		22,534
Export sales (CIS)	11,540		7,702		1,757		2,772		1,516
Export sales (Non-CIS)	77,854		80,038		126,272		44,580		19,550
Petrochemicals⁽¹⁾	10,460		5,541		2,528		—		—
Intersegment sales	322		1,311		54		—		—
Tire sales (Domestic)	7,046		2,517		—		—		—
Tire sales (CIS)	908		38		—		—		—
Tire sales (Non-CIS)	814		163		—		—		—
Refined products	1,152		1,415		2,373		—		—
Other	218		97		101		—		—
Eliminate intersegment sales	(84,716	)	(92,839	)	(108,669	)	(61,711	)	(41,515	)
Total costs and other deductions	(128,334	)	(132,513	)	(148,263	)	(57,687	)	(64,569	)
Operating expenses	(36,390	)	(31,297	)	(24,836	)	(17,938	)	(20,605	)
Purchased oil and refined products	(28,372	)	(34,104	)	(61,587	)	(6,554	)	(1,271	)
Exploration expenses	(463	)	(839	)	(740	)	(201	)	(633	)
Transportation	(5,683	)	(5,183	)	(4,349	)	(3,490	)	(3,073	)
Selling, general and administrative expenses	(15,770	)	(18,309	)	(11,060	)	(8,063	)	(5,490	)
Depreciation, depletion and amortization	(7,325	)	(5,822	)	(5,292	)	(4,246	)	(6,474	)
Loss on impairment of fixed assets and investments	(851	)	(2,502	)	(2,604	)	—		(9,005	)
Taxes other than income taxes⁽²⁾	(31,988	)	(33,373	)	(37,415	)	(16,644	)	(16,483	)
Maintenance of social infrastructure expense	(199	)	(491	)	(252	)	(325	)	(1,063	)
Transfer of social assets constructed after privatization	(1,293	)	(593	)	(128	)	(226	)	(472	)
Other income (expenses)	2,370		1,917		1,406		(1,944	)	(8,880	)
Earnings (losses) from equity investments	148		501		914		474		(262	)
Exchange loss	(1,042	)	(851	)	(591	)	(10,318	)	(20,815	)
Monetary gain⁽³⁾	871		1,764		3,706		10,554		14,326
Net interest income, banking	845		1,350		—		—		—
Other net income, banking	(673	)	(525	)	—		—		—
Interest expense, net	(2,051	)	(1,358	)	(3,509	)	(3,329	)	(3,495	)
Other income	4,272		1,036		886		675		1,366
Income (loss) before income taxes and minority interest	19,519		24,915		52,646		23,076		(22,433	)
Total income tax expense (benefit)	3,255		(1,133	)	19,717		8,505		12,000
Current⁽²⁾	4,743		7,072		10,822		4,916		344
Deferred	(1,488	)	(8,205	)	8,895		3,589		11,656
Income (loss) before minority interest	16,264		26,048		32,929		14,571		(34,433	)
Minority interest	(471	)	(1,698	)	(475	)	(513	)	472
Net income (loss)	15,793		24,350		32,454		14,058		(33,961	)
Foreign currency translation adjustments	143		163		—		—		—
Unrealized holding gains on available-for-sale securities, net of RR nil tax	33		2,329		763		511		—
Less: reclassification adjustment for realized gains included in net income	(3,144	)	(622	)	—		—		—
Comprehensive income (loss)	12,825		26,220		33,217		14,569		(33,961	)
Basic net income (loss) per Ordinary Share⁽⁴⁾	7.32		11.04		14.33		6.16		(15.89	)
Diluted net income (loss) per Ordinary Share⁽⁴⁾	7.32		11.01		14.33		6.16		(15.89	)
Net income (loss) per ADS⁽⁵⁾	146		221		287		123		(318	)

Ordinary Shares, nominal value 1 Russian ruble per share		2,178,690,700
Preferred Shares, nominal value 1 Russian ruble per share		147,508,500

Dividends declared per Ordinary Share⁽⁶⁾		0.10		0.10		0.30		0.10		0.04
Dividends declared per Preferred Share⁽⁶⁾		1.00		1.00		0.60		0.15		0.10

Year Ended December 31,	Period end	Average(1)	High	Low
1998	20.65	10.12	20.99	5.96
1999	27.00	24.67	27.00	20.65
2000	28.16	28.13	28.87	26.90
2001	30.14	29.22	30.30	28.16
2002	31.78	31.39	31.86	30.13
2003
January	31.82	31.82	31.88	31.78
February	31.58	31.70	31.85	31.55
March	31.38	31.45	31.60	31.38
April	31.10	31.21	31.38	31.01
May	30.71	30.90	31.12	30.62
June (through June 25, 2003)	30.35	30.49	30.76	30.32

	As of January 1,
	2003		2002		2001
Reserve Category	Tons	MBbls	Tons	MBbls	Tons	MBbls
Proved Developed Reserves	774.8	5,518.6	706.8	5,034.8	772.8	5,504.0
Proved Undeveloped Reserves	63.6	453.4	58.9	419.9	61.7	439.7
Total Proved Reserves	838.4	5,972.0	765.7	5,454.7	834.6	5,943.6

	Proved Developed Reserves
	2003		2002		2001
Field	Tons	MBbls	Tons	MBbls	Tons	MBbls
Romashkinskoye	446.2	3,178.4	426.7	3,039.3	535.3	3,812.0
Novo-Yelkhovskoye	68.8	490.3	66.6	474.1	89.2	635.6
Bavlinskoye	35.1	250.1	28.5	202.8	16.8	119.5
Sabanchinskoye	14.6	104.0	14.2	101.0	15.7	111.9
Others	210.0	1,495.8	171.0	1217.6	115.8	825.1
Total	774.8	5,518.6	707.0	5,034.8	772.8	5,504.0


	Proved Undeveloped Reserves
	2003		2002		2001
Field	Tons	MBbls	Tons	MBbls	Tons	MBbls
Romashkinskoye	9.2	65.2	5.5	39.3	9.0	64.3
Novo-Yelkhovskoye	0.6	4.4	0.7	5.0	2.1	15.0
Bavlinskoye	16.4	116.5	16.4	117.1	14.8	105.2
Sabanchinskoye	1.0	6.8	1.2	8.8	1.5	10.8
Others	36.6	260.4	35.1	249.7	34.3	244.5

Total	63.6	453.4	58.9	419.9	61.7	439.7

	Proved Reserves
	2003		2002		2001
Field	Tons	MBbls	Tons	MBbls	Tons	MBbls
Romashkinskoye	455.4	3,243.6	432.1	3,078.6	544.3	3,876.3
Novo-Yelkhovskoye	69.5	494.7	67.3	479.1	91.3	650.6
Bavlinskoye	51.5	366.6	44.9	319.9	31.5	224.6
Sabanchinskoye	15.6	110.8	15.4	109.8	17.2	122.7
Others	246.6	1,756.2	206.0	1,467.3	150.2	1,069.5

Year Ended December 31,
2002⁽¹⁾⁽²⁾		2001⁽¹⁾		2000⁽¹⁾⁽³⁾
Tons	Barrels	Tons	Barrels	Tons	Barrels
24.9	177.3	24.9	177.3	24.6	175.2

	At December 31,
	2002	2001	2000
Production wells	23,887	24,246	24,834
in operation	19,832	19,831	18,892
not in operation⁽¹⁾	4,055	4,415	5,942
Injection wells	8,831	8,578	8,262
in operation	8,259	7,960	7,627
not in operation⁽²⁾	572	618	635

Total production and injection wells	32,718	32,824	33,096
Others⁽³⁾	9,205	8,634	7,561
Total	41,923	41,458	40,657

	Year Ended December 31,
Type of Drilling	2002	2001	2000
Operation	853.7	946.6	799.6
Exploration	79.8	54.3	25.8

	Year Ended December 31,
	2002	2001	2000	1999	1998
	(in RR millions)
CONSOLIDATED BALANCE SHEET DATA
Total assets	228,000	229,069	202,999	154,588	142,198
Total current assets	65,243	72,747	63,511	39,475	35,083
Property, plant and equipment, net	154,047	147,858	129,014	109,842	98,314
Other assets	8,710	8,464	10,474	5,271	8,801
Total liabilities	84,553	95,683	96,697	80,941	83,977
Total current liabilities⁽⁷⁾	47,970	66,789	51,310	47,921	52,870
Total long-term liabilities⁽⁸⁾	36,583	28,894	45,387	33,020	31,107
Minority interest	5,069	5,302	2,521	1,285	83
Total shareholders’ equity	138,378	128,084	103,781	72,362	58,138

	Average balance(1)		Interest income/expense		Average yield/rate
	2002	2001	2002	2001	2002	2001
Interest earning assets
Cash and cash equivalents	967	703	25	63	2.6	9.1
Due from other banks	1,919	1,273	151	137	7.9	10.8
Trading and available-for-sale securities	2,414	2,119	353	230	14.6	10.9
Loans and advances to customers⁽²⁾	9,600	7,969	1,491	1,257	15.5	15.8


Total interest earning assets	14,900	12,064	2,020	1,687	13.2	13.9


Cash and cash equivalents	1,054	647
Mandatory cash balances with the Central Bank	1,171	967
Other non-interest bearing assets	1,415	1,210


Intercompany balances, net	2,372	1,875


Total assets	20,912	16,763


Liabilities and shareholders equity

Interest bearing liabilities
Customers deposits	4,022	2,828	512	223	12.7	7.7
Due to other banks	3,154	2,407	108	151	3.4	6.3
Other borrowed funds	403	450	2	10	0.5	2.3
Securities issued by the bank	4,596	2,574	421	131	9.2	5.1


Total interest bearing liabilities	12,175	8,259	1,043	515	8.6	6.3


Demand deposits	4,097	4,241
Other non interest bearing liabilities	447	908


Total liabilities	16,719	13,408


Shareholders equity	4,193	3,355

Total liabilities and shareholders’ equity	20,912	16,763

Net interest income			977	1,172
Interest spread					5.0	7.6

Net yield on interest earning assets					6.6	9.7
Interest earning assets to interest bearing liabilities					122.4	146.1

	2002		2001
	USD	RR	USD	RR
Assets
Cash and cash equivalents	0.7	0.9	3.1	—
Trading securities	1.5	13.2	37.1	28.8
Available-for-sale securities	—	8.2	—	—
Due from other banks	8.1	12.7	1.9	32.4
Loans and advances to customers	14.0	18.3	16.8	20.4

Liabilities
Due to other banks	7.0	4.0	3.7	19.8
Customer term accounts	5.8	12.0	9.0	12.6
Securities issued by Bank Zenit	8.0	10.0	5.6	11.3
Other borrowed funds	11.1	—	6.4	—

	December 31,
	2002	2001	2000
	(in RR millions)
Ruble denominated securities
Corporate bonds	334	863	206
Promissory notes	273	411	546
Municipal bonds	158	296	—
Corporate shares	19	1	8
Federal loan bonds (OFZ)	3	—	67
U.S. dollar and other foreign currency denominated securities
Corporate Eurobonds	521	341	—
Russian Federation Eurobonds	76	—	12
Vnesheconombank 3% coupon bonds (VEB)	15	64	8
U.S. dollar-denominated securities sold under repurchase agreements
Russian Federation Eurobonds	—	—	711
Vnesheconombank 3% coupon bonds (VEB)	307	705	—
Total trading securities	1,706	2,681	1,558

	Demand and less than 1 month	From 1 to 6 months	From 6 to 12 months	More than 1 year	Overdue	Total
	(in RR millions)
Loans and advances to customers	2,008	5,092	2,506	1,038	235	10,879

—Term deposits	—	60	144
Other legal entities
—Current/settlement accounts	3,052	3,785	3,455
—Term deposits	3,178	2,057	1,558
Individuals
—Current/demand accounts	383	332	182
—Term deposits	1,921	828	1,011
Total customer accounts	8,651	7,587	6,554

	Domestic				Foreign
	Principal or agreed amount		Unrealized Loss	Unrealized Gain	Principal or agreed amount		Unrealized Loss		Unrealized Gain
Deliverable forwards
Precious metals
—sale of precious metals	(18	)	—	—	(125	)	—		2
—purchase of precious metals	10		—	—	27		—		—
Foreign currency				—					—
—sale of foreign currency	—		—	—	(89	)	—		—
Securities			—						—
—purchase of securities	67		—	1	52		(1	)	—
Spot			—
Foreign currency			—
—sale of foreign currency	(67	)	—	—	—		—		—
Precious metals			—		—		—		—
—sale of precious metals	(22	)	—	—	—		—		—

Date of Sale	US$ Amount of Sale	RR to US$ Exchange Rate At Time of Sale	RR Amount of Sale Initially Recognized	Decrease in Value of RR Against US$ from Date of Sale to December 31, 2002		Increase in CPI from Date of Sale to December 31, 2002		RR Amount of Sale in Constant RR of December 31, 2002 Purchasing Power
January 1, 2000	1	27.00	27.00	18	%	64	%	44.37
January 1, 2001	1	28.16	28.16	13	%	37	%	38.52
January 1, 2002	1	30.14	30.14	5	%	15	%	34.70
December 31, 2002	1	31.78	31.78	—		—		31.78

Date of Sale	Thousands of Barrels of Crude Oil exported in Non-CIS Sale	US$ Platt’s Price per Barrel on Date of Sale	US$ Amount of Sale	RR to US$ Exchange Rate at Time of Sale	RR Amount of Sale Initially Recognized	RR Amount of Sale in Constant RR of December 31, 2002 Purchasing Power
January 1, 2000	1,000	24	24,000	27.00	648,000	1,064,697
January 1, 2001	1,000	23	23,000	28.16	647,680	885,933
January 1, 2002	1,000	19	19,000	30.14	572,660	659,246
December 31, 2002	1,000	30	30,000	31.78	953,400	953,400

	Year Ended December 31,
Tax	2002			2001			2000			Taxable base
Income tax - maximum rate		24	%		35	%		30	%	Taxable income
VAT		20	%		20	%		20	%	Added value
Unified natural resources production tax	RR	668			—			—		Metric ton produced (crude oil)
Mineral restoration tax⁽¹⁾		—			10	%		10	%	Sales revenues⁽²⁾
Royalty tax⁽¹⁾		—			6-16	%		6-16	%	Sales revenues⁽²⁾
Crude oil excise tax⁽¹⁾		—			RR66		RR	55		Metric ton produced and sold (crude oil)

Refined products excise tax:
High octane gasoline	RR	2,072		RR	1,850		RR	585		Metric ton produced and sold domestically
Low octane gasoline	RR	1,512		RR	1,350		RR	455
Diesel fuel	RR	616		RR	550			—
Motor fuel	RR	1,680		RR	1,500			—
Crude oil export duty, average⁽³⁾	US$	18.6		EUR	29.1		EUR	22.7		Metric ton exported
Refined products export duty, average:
Light distilled products (gasoline products)	EUR	30.0		EUR	38.7		EUR	22.3		Metric ton exported
Mid distilled products (diesel fuel)	EUR	30.0		EUR	38.7		EUR	17.4
Fuel oil	EUR	15.1		EUR	24.4		EUR	6.2
Road users tax		1	%		1	%		2.5	%	Net revenues
Property tax – maximum rate		2	%		2	%		2	%	Taxable property

	Year Ended December 31,
	2002	% Change on prior year		2001	% Change on prior year		2000
Crude oil production (millions of tons)⁽¹⁾	24.9	0.1	%	24.9	1.2	%	24.6
Crude oil production (millions of barrels)⁽¹⁾	177	0.1	%	177	1.2	%	175
Refining and tolling throughput (millions of tons)	8.5	16.2	%	7.3	108.4	%	3.5
Refining and tolling throughput (millions of barrels)	61	16.2	%	52	108.4	%	25
Cash flow from operating activities	15,768	(27.2	%)	21,665	(5.5	%)	22,937

Basic net income per share (RR)
Common	7.32	(33.7	%)	11.04	(23.0	%)	14.33
Preferred	8.20	(26.4	%)	11.14	(24.1	%)	14.68

Diluted net income per share (RR)
Common	7.32	(33.5	%)	11.01	(23.2	%)	14.33
Preferred	8.20	(26.2	%)	11.11	(24.3	%)	14.68

Volume (thousand tons)		5,216		6,737
Price (RR per ton)		3,829		3,590

	Year Ended December 31,
	2002	2001
Purchases of refined products (in RR millions)	14,337	13,091
Volume (thousand tons)	4,490	6,171
Average price per ton (RR)	3,193	2,121
Purchases of crude oil (in RR millions)	14,035	21,013
Volume (thousand tons)	4,679	6,361
Average price per ton (RR)	2,999	3,303

Loss on disposals and impairment	2,502	2,604
Taxes other than income taxes	33,373	37,415
Maintenance of social infrastructure	491	252
Transfer of social assets constructed after privatization	593	128

Total costs and other deductions	132,513	148,263

Fixed interest rate debt	626		11,453
Weighted average interest rates for fixed rate debt	5.97	%	8.5	%
Variable interest rate debt	20,108		12,259
Weighted average interest rates for variable rate debt	5.3	%	6.03	%

Total long-term borrowings	20,734		23,712

Foreign currency denominated long-term debt	20,162		22,790
Ruble-denominated long-term debt	572		922

Total long-term borrowings	20,734		23,712

Less: current portion of long-term debt	(6,112	)	(18,010	)

Total long-term debt obligations	14,622		5,702

Total debt	31,240		32,783

Name	Title	Year of Birth

Rustam Nurgalievich Minnikhanov	Chairman of the Board, Prime Minister of the Republic of Tatarstan	1957

Shafagat Fahrazovich Takhautdinov	Director, General Director	1946

Rishat Fazlutdinovich Abubakirov	Director, Head of Almetyevsk Region and City Administration	1959

Rinat Gimadelishlamovich Galeev	Director, Chairman of the Board of Directors of Bank Devon-Credit	1939

Radik Raufovich Gaizatulin	Director, Finance Minister of the Republic of Tatarstan	1964

Nail Gabdulbarievich Ibragimov	Director, First Deputy General Director for Production, Chief Engineer	1955

Rais Salikhovich Khisamov	Director, Deputy General Director, Chief Geologist	1950

Vladimir Pavlovich Lavushchenko	Director, Deputy General Director for Economics	1949

Nail Ulfatovich Maganov	Director, First Deputy General Director, Head of Oil and Refined Products Sales Department	1958

Renat Halliulovich Muslimov	Director, State Counsel to the President of the Republic of Tatarstan	1934

Ardinat Galievich Nugaibekov	Director, Chief of NGDU Elkhovneft	1947

Albert Kashafovich Shigabutdinov	Director, General Director of TAIF	1952

Victor Vasilievich Smykov	Director, Chief of NGDU Yamashneft	1949

Aleksey Arkadievich Sokolov	Director, Chairman of the Executive Board of Bank Zenit	1956

Valery Pavlovich Vasiliev	Director, Minister of Land and Property Relations of the Republic of Tatarstan	1947

Name		Share Ownership Percentage⁽¹⁾

Rustam Nurgalievich Minnikhanov		none

Shafagat Fahrazovich Takhautdinov		0.12

Rishat Fazlutdinovich Abubakirov		0.06

Rinat Gimadelishlamovich Galeev		0.08

Radik Raufovich Gaizatulin		none

Nail Gabdulbarievich Ibragimov		0.020

Rais Salikhovich Khisamov		0.0197

Vladimir Pavlovich Lavushchenko		0.048

Nail Ulfatovich Maganov		0.079

Renat Halliulovich Muslimov		0.07

Ardinat Galievich Nugaibekov		0.0456

Albert Kashafovich Shigabutdinov		none

Aleksey Arkadievich Sokolov		none

	Number of Shares	Percent of Charter Capital
Ordinary Shares
Shares owned by Tatarstan MLPR (including the Golden Share)
Held by OAO Central Depositary, as nominee for the Tatarstan MLPR	95,939,179	4.12
Held by OAO Tatneftekhiminvestholding, in trust for the Tatarstan MLPR	612,255,600	26.32
Total	708,194,779	30.44
Other Ordinary Shares
Held by employees (including management)	105,491,014	4.54
Held by other individuals	40,795,066	1.75
Held by other legal entities⁽¹⁾	1,324,209,841	56.93
Total	1,470,495,921	63.22
Total Ordinary Shares	2,178,690,700	93.66
Preferred Shares Held by employees (including management)	56,095,524	2.41
Held by other individuals	11,851,973	0.51
Held by OAO Central Depositary, as nominee for the Tatarstan MLPR	95,500	0.0041
Held by other legal entities	78,553,502	3.38
Held by non-residents	912,001	0.04
Total Preferred Shares	147,508,500	6.34

Total number of shares outstanding	2,326,199,200	100.00

Ordinary Shareholder⁽¹⁾	Number of Ordinary Shares	Percent of Ordinary Shares
Tatarstan MLPR⁽²⁾	708,194,779	32.51
OAO UK Nikoil-Sberezheniye, acting in trust for the Fund for Assistance in Comprehensive Research in the Energy Industry	116,284,150	5.34
TAIF	115,845,105	5.32
Directors and executive officers as a group⁽³⁾	21,783,800	1.00

Class of Shares	1998			1999			2000			2001			2002
	% of nominal value		Share Dividend (RR)	% of nominal value		Share Dividend (RR)	% of nominal value		Share Dividend (RR)	% of nominal value⁽²⁾		Share Dividend (RR)	% of nominal value		Share Dividend (RR)
Ordinary Shares⁽³⁾	40	%	0.04	100	%	0.10	300	%	0.30	10	%	0.10	10	%	0.10
Preferred Shares	100	%	0.l0	150	%	0.15	600	%	0.60	100	%	1.00	100	%	1.00

	US$ per ADS⁽¹⁾
Period	High	Low
1998⁽²⁾	22.50	1.38
1999	9.50	1.38
2000	14.50	6.50
2001
First Quarter	10.90	6.69
Second Quarter	11.73	7.44
Third Quarter	10.58	8.08
Fourth Quarter	10.93	8.11
2002
First Quarter	14.02	9.88
Second Quarter	17.05	12.64
Third Quarter	15.83	11.16
Fourth Quarter	16.91	14.70
2003
January	15.31	14.25
February	16.87	15.30
March	18.25	16.81
April	18.30	16.58
May	22.24	17.35
June (through June 25, 2003)	23.70	19.08