20-F 1 d20f.htm OAO TATNEFT OAO TATNEFT
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As filed with the Securities and Exchange Commission on July 14, 2005


UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 20-F

 


 

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

 

OR

 

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

 

For the fiscal year ended: December 31, 2003

 

OR

 

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

 

For the transition period from N/A to N/A

 

Commission file number: 1-14804

 


 

OAO TATNEFT

(also known as AO TATNEFT or TATNEFT)

(Exact name of Registrant as specified in its charter)

 

TATNEFT

(Translation of registrant’s name into English)

 


 

Republic of Tatarstan

Russian Federation

(Jurisdiction of incorporation or organization)

 

75 Lenin Street

Almetyevsk

Tatarstan 423450

Russian Federation

(Address of principal executive offices)

 


 

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

 

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.

 

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

 

None

(Title of Class)

 

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

 

None

(Title of Class)

 


 

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:

 

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

 

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  ¨    No  x    Not applicable  ¨

 

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

 

* Not for trading, but only in connection with the registration of the American Depositary Shares.

 



Table of Contents

Table of Contents

 

               Page

EXPLANATORY NOTE

   1

INTRODUCTION

   1
FORWARD-LOOKING STATEMENTS    2
PART I    4
     ITEM 1.    IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS    4
     ITEM 2.    OFFER STATISTICS AND EXPECTED TIMETABLE    5
     ITEM 3.    KEY INFORMATION    6
          SELECTED FINANCIAL DATA    6
          EXCHANGE RATES    9
          CAPITALIZATION AND INDEBTEDNESS    10
          REASONS FOR THE OFFER AND USE OF PROCEEDS    11
          RISK FACTORS    12
     ITEM 4.    INFORMATION ON THE COMPANY    34
          BUSINESS OVERVIEW    34
          HISTORY AND DEVELOPMENT    34
          ORGANIZATIONAL STRUCTURE    37
          STRATEGY    39
          OVERVIEW OF THE RUSSIAN OIL INDUSTRY    41
          EXPLORATION AND PRODUCTION    49
          TRANSPORTATION    55
          REFINING AND MARKETING    56
          PETROCHEMICALS    60
          BANKING OPERATIONS    60
          COMPETITION    61
          ENVIRONMENTAL MATTERS    62
          CORPORATE REORGANIZATION    63
          RELATIONSHIP WITH TATARSTAN    64
          PROPERTY, PLANT AND EQUIPMENT    66
     ITEM 5.    OPERATING AND FINANCIAL REVIEW AND PROSPECTS    67
          OVERVIEW    68
          RESULTS OF OPERATIONS    72
          LIQUIDITY AND CAPITAL RESOURCES    84
          CONTRACTUAL OBLIGATIONS    89

 

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Table of Contents

 

(continued)

 

               Page

          OFF-BALANCE SHEET ARRANGEMENTS    90
          CRITICAL ACCOUNTING POLICIES AND ESTIMATES    90
          RESEARCH AND DEVELOPMENT    94
          LICENSES    95
          TRENDS INFORMATION    96
     ITEM 6.    DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES    97
          DIRECTORS AND SENIOR MANAGEMENT    97
          COMPENSATION    102
          BOARD PRACTICES    102
          EMPLOYEES    107
          SHARE OWNERSHIP    107
     ITEM 7.    MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS    109
          MAJOR SHAREHOLDERS    109
          RELATED PARTY TRANSACTIONS    111
          INTERESTS OF EXPERTS AND COUNSEL    112
     ITEM 8.    FINANCIAL INFORMATION    113
          CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION    113
          EXPORT SALES    113
          LEGAL PROCEEDINGS    113
          DIVIDENDS AND DIVIDEND POLICY    113
          SIGNIFICANT CHANGES    114
     ITEM 9.    THE OFFER AND LISTING    115
          MARKETS    115
     ITEM 10.    ADDITIONAL INFORMATION    120
          MEMORANDUM AND ARTICLES OF ASSOCIATION    120
          MATERIAL CONTRACTS    123
          EXCHANGE CONTROLS    123
          TAXATION    126
          DOCUMENTS ON DISPLAY    131
     ITEM 11.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    132
     ITEM 12.    DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES    135

 

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Table of Contents

 

(continued)

 

               Page

PART II    136
     ITEM 13.    DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES    136
     ITEM 14.    MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS    137
     ITEM 15.    CONTROLS AND PROCEDURES    138
     ITEM 16A.    AUDIT COMMITTEE FINANCIAL EXPERT    139
     ITEM 16B.    CODE OF ETHICS    140
     ITEM 16C.    PRINCIPAL ACCOUNTANT FEES AND SERVICES    141
PART III    143
     ITEM 17.    FINANCIAL STATEMENTS    143
     ITEM 18.    FINANCIAL STATEMENTS    144
     ITEM 19.    EXHIBITS    145
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS    F-1
APPENDIX A TATNEFT’S BANKING OPERATIONS    A-1

* The registrant has responded to Item 18 in lieu of responding to Item 17.

 

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EXPLANATORY NOTE

 

Ernst & Young was engaged by us in June 2003 to audit our U.S. GAAP financial statements for the year ended December 31, 2003. PricewaterhouseCoopers had audited our financial statements in prior years. As Ernst & Young conducted their audit, they identified weaknesses in our control environment, some of which had also been noted by PricewaterhouseCoopers and reported in our Annual Reports on Form 20-F for prior periods. In addition, Ernst & Young identified certain transactions the nature and business purposes of which were not immediately apparent. Ernst & Young notified the Audit Committee of the Board of Directors (the “Audit Committee”) and advised them to retain independent counsel to conduct an investigation of these transactions. Our Audit Committee retained Kennedys, as its independent legal counsel, to conduct the investigation. Based on the documentation, information and evidence obtained by it, Kennedys’ investigation, completed in April 2005, found no evidence of fraud but also found that our control environment (including our maintenance of books and records and internal controls) was inadequate under the applicable requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We have taken and are taking remedial measures to deal with these inadequacies. The investigation and consequent delay in completing the audit of our 2003 financial statements prepared under U.S. GAAP has led to a delay in filing this annual report. See “Item 3— Risk Factors—Risks Relating to the Company—Our independent registered public accounting firm reported material weaknesses in our internal controls and we may not be able to remedy these material weaknesses or prevent future weaknesses” and “Item 15—Controls and Procedures.”

 

In addition, we previously announced the need to restate our consolidated financial statements for the years ended December 31, 2002 and 2001. The consolidated statements of operations, changes in equity and comprehensive income (loss) and cash flows for the years ended December 31, 2002 and 2001 and the consolidated balance sheet as of December 31, 2002, including the applicable notes, contained in this Annual Report on Form 20-F have been restated.

 

For a description of the restatements, see “Restatement” in Note 4 to the accompanying audited consolidated financial statements and “Item 5—Operating and Financial Review and Prospects—Restatements of Previously Issued Financial Statements” contained in this Annual Report on Form 20-F.

 

INTRODUCTION

 

This annual report on Form 20-F includes audited consolidated financial statements of OAO Tatneft (“Tatneft”) and its consolidated subsidiaries as at December 31, 2003 and 2002, and for each of the years in the three-year period ended December 31, 2003, 2002 and 2001. These financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“U.S. GAAP”). Information contained in such financial statements for periods prior to January 1, 2003 is expressed in constant rubles of December 31, 2002 purchasing power, except as otherwise indicated.

 

On December 31, 2003, the official ruble/U.S. dollar exchange rate reported by the Central Bank of the Russian Federation (the “Central Bank”) was U.S.$1.00 = RR29.45. On July 1, 2005 the official ruble/U.S. dollar exchange rate reported by the Central Bank was U.S.$1.00 = RR28.63. 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 natural gas reserves derived from the report of Miller and Lents, Ltd. (“Miller and Lents”), oil and gas consultants based in Houston, Texas, dated May 28, 2004 and June 14, 2005 (collectively, the “Reserves Reports”), incorporated by reference from our reports on Form 6-K furnished to the SEC on July 23, 2004 and June 29, 2005, respectively. While the Reserves Reports have been prepared in accordance with the definitions contained in U.S. Securities

 

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and Exchange Commission (“SEC”) Regulation S-X, Rule 4-10(a), they are 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 are subject to a high degree of uncertainty. Readers should not place undue reliance on the forward-looking statements in the Reserves Reports, on the ability of the Reserves Reports 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 Reports, the reserves information is based on the reserves of 63 and 73 developed and producing and seven undeveloped oil fields covered by exploration, production or combined exploration and production licenses as of January 1, 2004 and January 1, 2005, respectively.

 

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. See “Item 4—Information on the Company—Exploration and Production.”

 

Columns in tables may not add to the stated totals due to rounding.

 

FORWARD-LOOKING STATEMENTS

 

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:

 

    projections of revenues, income (or loss), earnings (or loss) per share, dividends, capital structure or other financial items or ratios;

 

    statements of our plans, objectives or goals, including those related to products or services;

 

    statements of future economic performance; and

 

    statements of assumptions underlying such statements.

 

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:

 

    inflation, interest rate, and exchange rate fluctuations;

 

    the price of oil;

 

    the effect of, and changes in, Russian or Tatarstan government policy;

 

    the effect of terrorist attack or other geopolitical instability, either within Russia or elsewhere;

 

    the effects of competition in the geographic and business areas in which we conduct operations;

 

    the effects of changes in laws, regulations, taxation or accounting standards or practices;

 

    our ability to increase market share and control expenses;

 

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    acquisitions or divestitures;

 

    technological changes; and

 

    our success at managing the risks of the aforementioned factors.

 

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.

 

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PART I

 

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT, AND ADVISORS

 

This Item is not applicable.

 

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ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

 

This Item is not applicable.

 

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ITEM 3. KEY INFORMATION

 

SELECTED FINANCIAL DATA

 

The selected financial data set forth below is derived from the consolidated financial statements of Tatneft for each of the years in the five year period ended December 31, 2003. The financial statements for the year ended December 31, 2003 have been audited by Ernst & Young, independent auditors. The financial statements for each of the years in the four-year period ended December 31, 2002 have been audited by PricewaterhouseCoopers, independent auditors. The selected financial data as at December 31, 2003 and 2002 and for each of the years in the three-year period ended December 31, 2003 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 also 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 11.7%, 12%, 15.1%, 18.8%, 20.1% and 37.0% in 2004, 2003, 2002, 2001, 2000 and 1999 respectively. Given Russia’s past inflation history, Russia’s economy was considered hyperinflationary for purposes of our consolidated financial statements for the year ended December 31, 2002 and prior periods, and such consolidated financial statements were prepared in accordance with Accounting Principles Board Statement 3, Financial Statements Restated for General Price-Level Changes. These figures were thus expressed in millions of constant rubles as of December 31, 2002 purchasing power. At a meeting of the AICPA International Practices Task Force on November 25, 2002, the Task Force concluded that Russia would no longer be considered highly inflationary effective from January 1, 2003. See “Item 5—Operating and Financial Review and Prospects—Overview—Inflation and foreign currency exchange rate fluctuations.”

 

The monetary gain included in our consolidated statements of operations for periods prior to January 1, 2003 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.

 

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     Year Ended December 31,(1)

 
     2003

    2002
(as restated)


    2001
(as restated)


    2000
(as restated)


    1999
(as restated)


 
     (in RR millions, except per share information)  

CONSOLIDATED STATEMENT OF OPERATIONS DATA

                              

Sales and other operating revenues(2)

   155,818     146,328     156,861     199,503     82,707  

Exploration and production(2)

   93,155     84,394     91,528     108,615     61,711  

Intersegment sales

   93,155     84,394     91,528     108,615     61,711  

Refining and marketing(2)

   134,158     125,673     139,082     184,085     75,791  

Domestic sales

   34,891     36,279     51,342     56,056     28,439  

Export sales (CIS)

   9,806     11,540     7,702     1,757     2,772  

Export sales (Non-CIS)

   89,461     77,854     80,038     126,272     44,580  

Petrochemicals(2)

   11,816     10,242     5,444     2,427     —    

Intersegment sales

   233     322     1,311     54     —    

Tire sales (Domestic)

   7,764     7,046     2,517     —       —    

Tire sales (CIS)

   1,799     908     38     —       —    

Tire sales (Non-CIS)

   739     814     163     —       —    

Refined products

   1,281     1,152     1,415     2,373     —    

Banking(11)

   1,531     1,180     1,615     —       —    

Net interest income intersegment

   530     335     265     —       —    

Net interest income

   1,001     845     1,350     —       —    

Other sales

   9,177     10,038     12,797     13,959     7,390  

Eliminate income from equity investments reported separately in the consolidated statements of operations and comprehensive income

   (101 )   (148 )   (501 )   (914 )   (474 )

Eliminate intersegment sales

   (93,918 )   (85,051 )   (93,104 )   (108,669 )   (61,711 )

Total costs and other deductions

   (141,474 )   (128,549 )   (132,830 )   (148,934 )   (57,790 )

Operating

   (31,799 )   (36,389 )   (31,297 )   (24,836 )   (17,938 )

Purchased oil and refined products

   (28,997 )   (28,372 )   (34,104 )   (61,587 )   (6,554 )

Exploration

   (812 )   (463 )   (839 )   (740 )   (201 )

Transportation

   (7,635 )   (5,683 )   (5,183 )   (4,349 )   (3,490 )

Selling, general and administrative

   (15,499 )   (16,031 )   (17,282 )   (11,293 )   (7,586 )

Bad debt charges and credits, net

   262     261     (1,027 )   233     (477 )

Depreciation, depletion and amortization

   (8,850 )   (7,541 )   (6,139 )   (5,963 )   (4,349 )

Loss on disposals of property, plant and equipment and impairment of investments

   (2,325 )   (851 )   (2,502 )   (2,604 )   —    

Taxes other than income taxes(3)

   (43,378 )   (31,988 )   (33,373 )   (37,415 )   (16,644 )

Maintenance of social infrastructure

   (279 )   (199 )   (491 )   (252 )   (325 )

Transfer of social assets

   (2,162 )   (1,293 )   (593 )   (128 )   (226 )

Other income (expenses)

   313     1,525     567     1,406     (1,944 )

Earnings from equity investments

   101     148     501     914     474  

Exchange loss

   (225 )   (1,042 )   (851 )   (591 )   (10,318 )

Monetary gain(4)

   —       871     1,764     3,706     10,554  

Interest income

   303     804     1,517     —       —    

Interest expense, net

   (827 )   (855 )   (2,875 )   (3,509 )   (3,329 )

Other income

   1,961     3,599     511     886     675  

Income (loss) before income taxes and minority interest

   14,657     19,304     24,598     51,975     22,973  

Total income tax expense (benefit)

   4,582     5,363     (1,244 )   19,482     8,475  

Current(3)

   6,070     4,743     7,072     10,822     4,916  

Deferred

   (1,488 )   620     (8,316 )   8,660     3,559  

Income (loss) before minority interest

   10,075     13,941     25,842     32,493     14,498  

Minority interest

   63     (471 )   (1,698 )   (475 )   (513 )

Cumulative effect of change in accounting principle, net of RR1,498 million tax

   4,742     —       —       —       —    

Net income (loss)

   14,880     13,470     24,144     32,018     13,985  

Foreign currency translation adjustments

   3     (20 )   163     —       —    

Unrealized holding gains on available-for-sale securities, net of RR nil tax

   43     33     2,329     763     511  

Less: reclassification adjustment for realized gains included in net income

   (33 )   (2,981 )   (622 )   —       —    

Comprehensive income (loss)

   14,893     10,502     26,014     32,781     14,496  

Basic net income (loss) per Ordinary Share(5)

   6.93     6.24     10.94     14.33     6.16  

Diluted net income (loss) per Ordinary Share(5)

   6.90     6.23     10.92     14.33     6.16  

Net income (loss) per ADS(6)

   139     125     219     287     123  

Dividends declared per Ordinary Share(7)

   0.10     0.10     0.10     0.30     0.10  

Equivalent U.S.$ per Ordinary Share(8)

   0.0034     0.0031     0.0031     0.0094     0.0031  

Dividends declared per Preferred Share(7)

   1.00     1.00     1.00     0.60     0.15  

Equivalent U.S.$ per Preferred Share (8)

   0.0340     0.0315     0.0315     0.0189     0.0047  

 

     Year Ended December 31,(1)

 
     2003

    2002
(as restated)


    2001
(as restated)


    2000
(as restated)


    1999
(as restated)


 
     (in RR millions)  

CONSOLIDATED STATEMENT OF CASH FLOWS DATA

                              

Net cash provided by (used for) operating activities

   16,421     10,153     15,259     21,466     13,760  

Net cash used for investing activities

   (10,614 )   (8,002 )   (17,512 )   (17,907 )   (4,192 )

Net cash provided by (used for) financing activities

   (4,424 )   325     4,024     (2,579 )   (7,728 )

Net change in cash and cash equivalents

   1,380     2,198     1,341     465     1,596  

 

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     Year Ended December 31,(1)

     2003

   2002
(as restated)


   2001
(as restated)


   2000
(as restated)


   1999
(as restated)


     (in RR millions)

CONSOLIDATED BALANCE SHEET DATA

                        

Total assets

   262,717    226,288    229,069    201,937    154,194

Total current assets

   73,500    64,903    72,747    63,511    39,475

Property, plant and equipment, net

   177,008    152,448    147,858    127,952    109,448

Other assets

   12,209    8,937    8,464    10,474    5,271

Total liabilities

   108,436    86,067    95,683    96,331    80,807

Total current liabilities(9)

   54,233    48,140    66,789    51,310    47,921

Total long-term liabilities(10)

   54,203    37,927    28,894    45,021    32,886

Minority interest

   5,101    5,069    5,302    2,521    1,285

Total shareholders’ equity

   149,180    135,152    128,084    103,085    72,102
     As of December 31,(1)

     2003

   2002
(as restated)


   2001
(as restated)


   2000

   1999

     (in RR millions)

Capital Stock

   2,327    2,327    2,327    2,327    2,327

Ordinary Shares

   2,179    2,179    2,179    2,179    2,179

Preferred Shares

   148    148    148    148    148

(1) Our consolidated financial statements for the year ended December 31, 2002 have been restated to reflect a change in calculation of deferred taxes. For the year ended December 31, 2002, as permitted by the legislation of the Russian Federation, we recorded a statutory revaluation of our property, plant and equipment tax base amounting to RR11,893 million, and inappropriately recorded a decrease in deferred tax liability of RR2,854 million calculated on the entire amount of this statutory revaluation. Only a portion of this statutory revaluation, however, could be deductible in the future for tax purposes and as such the tax base of property, plant and equipment was overstated resulting in an understatement of deferred tax liabilities as of December 31, 2002, amounting to RR2,158 million. Deferred tax liabilities as of December 31, 2002, 2001, 2000 and 1999 and corresponding deferred tax expenses and benefits for the years then ended were also restated as a result of a restatement of property, plant and equipment, net of accumulated depreciation, depletion and amortization, as of December 31, 2002, 2001, 2000 and 1999 as discussed below. As a result of these restatements, our deferred income tax expense changed from a benefit of RR1,488 million to an expense of RR620 million for the year ended December 31, 2002, increased from RR8,205 million to RR8,316 million for the year ended 2001, decreased from RR8,895 million to RR8,660 million for the year ended December 31, 2000 and decreased from RR3,589 to RR3,559 for the year ended December 31, 1999.

 

In addition, the consolidated financial statements for the years ended December 31, 2002, 2001, 2000 and 1999 have been restated to reflect the effects of a change in calculation of depreciation, depletion and amortization. We historically have been depleting oil and natural gas properties on a units-of-production basis over total proved reserves, and not proved developed reserves, as required by U.S. GAAP. We originally believed that the difference between the two classes of reserves was not material for us and that the impact on the calculation of depreciation, depletion and amortization would also not be material. As a result of a recalculation of depreciation, depletion and amortization using proved developed reserves on a cumulative basis, we no longer believe that assumption to be appropriate. As a result of this restatement, our depreciation, depletion and amortization for the year ended December 31, 2002 increased from RR7,325 million to RR7,541 million for the year ended December 31, 2001, increased from RR5,822 million to RR6,139 million, for the year ended December 31, 2000 increased from RR5,292 million to RR5,963 million and for the year ended December 31, 1999 increased from RR4,246 million to RR4,349 million. The net effect of these changes was to reduce our net income by RR2,323 million, RR206 million, RR436 million and RR73 million for the years ended December 31, 2002, 2001, 2000 and 1999, respectively. For more information on our restatements see “Item 5—Operating and Financial Review and Prospects—Restatements of Previously Issued Financial Statements” and Note 4 to our audited consolidated financial statements included in this annual report.

(2) For a discussion of certain important features of our crude oil and refined products sales reported under the exploration and production, refining and marketing and petrochemicals segments, see “Item 5—Operating and Financial Review and Prospects—Overview.”
(3) See “Item 5—Operating and Financial Review and Prospects—Overview.”
(4) See “Item 5—Operating and Financial Review and Prospects—Overview.”
(5) Based on the number of Ordinary and Preferred Shares outstanding at December 31, 2003, 2002, 2001, 2000 and 1999, respectively. Per share data are calculated based on the two-class method. 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.
(6) Per ADS data reflects a ratio of 20 Ordinary Shares per ADS.
(7) Dividends declared are stated in nominal rubles.
(8) 2003 dividends are presented at the exchange rate of U.S.$1.00=RR29.45 reported by the Central Bank on December 31, 2003. Dividends for 1999-2002 are presented at the exchange rate of U.S.$1.00=RR31.78 reported by the Central Bank on December 31, 2002.
(9) Includes short-term debt, notes payable and banking customer deposits of RR36,826 million, RR31,508 million, RR44,327 million, RR25,914 million and RR27,587 million at December 31, 2003, 2002, 2001, 2000 and 1999, respectively.
(10) Includes long-term debt, notes payable and banking customer deposits of RR15,618 million, RR16,640 million, RR8,632 million, RR21,739 million, and RR13,309 million at December 31, 2003, 2002, 2001, 2000 and 1999, respectively.
(11) For a discussion of certain features of our banking operations, see “Appendix A—Tatneft’s Banking Operations.”

 

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EXCHANGE RATES

 

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 and rounded to the nearest 1/100th of a ruble. These rates may differ from the actual rates used in the preparation of our consolidated financial statements and other financial information appearing herein.

 

Year Ended December 31,


   Period end

   Average(1)

   High

   Low

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

   29.45    30.61    31.88    29.24

2004

   27.75    28.73    29.45    27.75

2005

                   

January

   28.08    28.02    28.16    27.87

February

   27.77    28.01    28.18    27.75

March

   27.83    27.63    27.83    27.46

April

   27.77    27.80    27.94    27.71

May

   28.09    27.95    28.09    27.78

June

   28.67    28.50    28.67    28.19

(1) The average of the exchange rates on the last business day of each month for the relevant annual period, and on each business day for which the Central Bank quotes the ruble to U.S. dollar exchange rate for the relevant monthly period.

 

On July 1, 2005, the exchange rate of ruble to U.S. dollar reported by the Central Bank was U.S.$1.00 = RR28.63. 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.

 

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CAPITALIZATION AND INDEBTEDNESS

 

This Item is not applicable.

 

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REASONS FOR THE OFFER AND USE OF PROCEEDS

 

This Item is not applicable.

 

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RISK FACTORS

 

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.

 

Risks Relating to the Russian Federation

 

Political and Social Risks

 

Political and governmental instability could adversely affect the value of investments in Russia and the value 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. 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. Mr. Putin was reelected for a second four-year term on March 14, 2004. While President Putin has maintained governmental stability and even accelerated the reform process in some areas, he may adopt a different approach over time. In late February 2004, President Putin dismissed Mr. Kasyanov’s government and appointed Mikhail Fradkov as Prime Minister. Shortly after the appointment of Mr. Fradkov as Prime Minister, a Presidential decree significantly reduced the number of federal ministries, redistributed certain functions amongst various government agencies and announced plans for a major overhaul of the federal administrative system. In addition, from December 31, 2004, federal law gives the president a significant role in choosing regional governors. See “—Relations between Tatarstan and Russia may deteriorate, adversely affecting our business” under this Item. Future changes in government, major policy shifts or lack of consensus between President Putin, the prime minister, Russia’s parliament, regional governors and legislatures and powerful economic groups could also disrupt or reverse economic and regulatory reforms. Any disruption or reversal of the reform policies, recurrence of political or governmental instability or occurrence of conflicts with powerful economic groups could have a material adverse effect on our company and the value of investments in Russia, including our ADSs.

 

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 89 sub-federal political units (to be reduced to 88 units from December 1, 2005), consisting 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 Tatarstan, exercise considerable power over their internal affairs pursuant to the Russian Constitution or, in certain cases, pursuant to agreements with the federal authorities. 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. Such tension and conflict have in the past often resulted in the enactment of conflicting legislation at various levels. Although the balance of authority between the federal government and sub-federal units has, with some exceptions, stabilized in recent years, a return to lack of consensus could hinder our long-term planning efforts and create uncertainties in our operating environment, both of which may prevent us from effectively and efficiently carrying out our business strategy and adversely affect our operations.

 

Additionally, ethnic, religious, historical and other divisions have, on occasion, given rise to tensions, and in certain cases, to military conflict, such as the continuing conflict in Chechnya, which has brought normal economic activity within Chechnya to a halt and disrupted the economies of neighboring regions. Various armed groups in Chechnya have regularly engaged in guerrilla attacks in that area. Violence and attacks relating to this conflict have also spread to other parts of Russia, and several terrorist attacks were carried out by Chechen terrorists in Moscow in recent years. For example, in October 2002, a large group of Chechen guerrillas seized a Moscow theatre and held 700 people hostage for three days until Russian special forces overpowered them, leading to the death of 129 hostages and 41 terrorists. Terrorists, allegedly linked to Chechen guerillas, also seized a school in Beslan, North Ossetia in September 2004, leading to the deaths of over 330 persons. The further intensification of violence, including terrorist attacks and suicide bombings, or its spread to other parts of Russia, could have significant political consequences, including the imposition of a state of emergency in some or all of Russia. Moreover, any terrorist attacks and the resulting heightened security measures may cause disruptions to domestic commerce and exports from Russia, and could materially adversely affect our business and the value of investments in Russia, including our ADSs.

 

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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 resulted in significant dislocation of authority, reduced policing and increased lawlessness. The local and international press have reported that significant organized criminal activity has arisen, particularly in large metropolitan centers. Property crimes in large cities have increased substantially. In addition, the local and international press have reported high levels of official corruption, including the bribing of officials for the purpose of initiating investigations by government agencies. Press reports have also described instances in which government officials engaged in selective investigations and prosecutions to further commercial interests of government officials or certain individuals. Additionally, published reports have indicated that a significant number of Russian media outlets regularly publish disparaging articles in return for payment. The depredations of organized or other crime, demands of corrupt officials or claims that we have been involved in official corruption or illegal activities may in the future bring negative publicity, which could disrupt our ability to conduct our business effectively and could thus materially adversely affect the value of our ADSs.

 

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.

 

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 in Russia 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 large-scale nationalization or expropriation of foreign-owned assets or businesses or to restrictions on foreign ownership of Russian companies in the oil and gas industry. Any of these outcomes could restrict our operations and lead to the loss of revenue, materially adversely affecting us.

 

Economic Risks

 

Economic instability in Russia could adversely affect our business.

 

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

 

    significant declines in gross domestic product;

 

    hyperinflation;

 

    an unstable currency;

 

    high government debt relative to gross domestic product;

 

    a weak banking system providing limited liquidity to Russian enterprises;

 

    high levels of loss-making enterprises that continued to operate due to the lack of effective bankruptcy proceedings;

 

    significant use of barter transactions and illiquid promissory notes to settle commercial transactions;

 

    widespread tax evasion;

 

    growth of black and gray market economies;

 

    pervasive capital flight;

 

    high levels of corruption and the penetration of organized crime into the economy;

 

    significant increases in unemployment and underemployment; and

 

    the impoverishment of a large portion of the Russian population.

 

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

 

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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.

 

Russia’s inexperience with a market economy relative to more developed economies also poses numerous risks. The failure to satisfy liabilities is widespread among Russian businesses and the government. Furthermore, it is difficult for us to gauge the creditworthiness of some of our customers, as there are no reliable mechanisms, such as reliable credit reports or credit databases, for evaluating their financial condition. Consequently, we face the risk that some of our customers or other debtors will fail to pay us or fail to comply with the terms of their agreements with us, which could adversely affect our results of operations.

 

We also cannot assure you 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. Additionally, because Russia produces and exports large quantities of oil and natural gas, the Russian economy is especially vulnerable to fluctuations in the price of such commodities on the world market and a decline in the price such commodities could significantly slow or disrupt the Russian economy. Recent military conflicts and international terrorist activity have created significant uncertainty about the supply of oil and natural gas and such future events may continue to adversely affect the global economic environment, which could result in a decline in the demand for oil and natural gas. A strengthening of the ruble in real terms relative to the U.S. dollar, changes in monetary policy, inflation or other factors could adversely affect Russia’s economy and our business in the future. Any such market downturn or economic slowdown could also severely limit our and our customers’ access to capital, also adversely affecting our and our customers’ businesses 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 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 telephone system, and restructuring of the electricity and rail sectors is in progress. Any such reorganization or restructuring may result in increased charges and tariffs while failing to generate the anticipated capital investment needed to repair, maintain and improve these systems.

 

Russia’s poor physical infrastructure disrupts the transportation of goods and supplies, adds costs to doing business in Russia and can interrupt regular business operations. Further deterioration in the physical infrastructure 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 natural gas, the Russian economy is especially vulnerable to changes in the prices of such commodities on world markets, 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.

 

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 subsided to 12.0% in 2003 and 11.7% in 2004. 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 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.

 

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Risks Relating to the Russian Legal System and Russian Legislation

 

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:

 

    conflicting local, regional and federal rules and regulations;

 

    a lack of judicial and administrative guidance on interpreting Russian legislation;

 

    substantial gaps in the regulatory structure created by the delay or absence of implementing regulations for certain legislation;

 

    the relative inexperience of judges and courts in interpreting Russian legislation;

 

    corruption within the judiciary;

 

    lack of independence of the judiciary from other political branches;

 

    a high degree of discretion on the part of governmental authorities; and

 

    bankruptcy procedures that are not well developed and are subject to abuse.

 

All of these weaknesses could affect our ability to enforce our rights under our licenses and our contracts, or to defend ourselves against claims by others. Furthermore, due to these risks 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:

 

    increasing state control over the activities of private companies;

 

    restricting exports of oil;

 

    increasing tariffs on oil exports;

 

    increasing governmental control over, or imposing limitations or restrictions, on foreign investment, imports and foreign personnel employed in business;

 

    increasing financial and currency controls relating to mandatory conversion of export proceeds and repatriation of profits;

 

    imposing limits on dividends and other payments;

 

    increasing protection of state-owned companies;

 

    increasing anti-monopoly controls that may limit our ability to consummate certain acquisitions; and

 

    raising the standards of environmental regulations to conform to more stringent international standards that may subject us to increased costs and expenses.

 

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Lack of independence and inexperience of some members of the Russian judiciary, 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, which could have a material adverse effect on our business or on the value of 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, and 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. Additionally, court orders are not always enforced or followed by law enforcement agencies.

 

These uncertainties also extend to property rights. During Russia’s transformation from a centrally planned economy to a market economy, legislation was 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 potential political factors, 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, could have a material adverse effect on us.

 

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

 

Governmental authorities have a high degree of discretion in Russia and at times exercise their discretion selectively or 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, selective or arbitrary governmental actions have included denial or 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, selective or arbitrary government action, if directed at us, could have a material adverse effect on our business and on the value of our ADSs.

 

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 person 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:

 

    this decision-making capability is provided for in the charter of the effective subsidiary or in a contract between the companies; and

 

    the effective parent gives obligatory directions to the effective subsidiary.

 

In addition, an effective parent may be secondarily liable for an effective subsidiary’s debts if an effective subsidiary becomes insolvent or bankrupt as a result of the action or inaction of 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 or by contract. In these instances, other shareholders 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 or fail to take action knowing that such action or failure to take action would result in losses. Accordingly, in our position as an effective parent, we could be liable in some cases for the debts of our effective subsidiaries. This total liability, which is joint and several with the liability of the subsidiary, 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.

 

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Because of the weaknesses in Russian shareholder protection legislation, your ability to bring, or to recover in, an action against us will be limited.

 

In general, minority shareholder protection under Russian law derives from supermajority shareholder approval requirements for certain corporate actions, 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 did not participate in voting on certain types of action. Companies are also required by Russian law to obtain the approval of disinterested shareholders for certain transactions with interested parties. 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. Shareholders of some companies have also suffered as a result of fraudulent bankruptcies initiated by hostile creditors.

 

In addition, 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 the outstanding shares of a company may have 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 amendments to the charter of the company and other measures requiring supermajority shareholder approval, which could be prejudicial to the interests of minority shareholders.

 

Disclosure and reporting requirements and anti-fraud legislation have only recently been enacted in Russia. 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 ability to pursue legal redress against us may be limited, reducing the protections available to you as a holder of ADSs.

 

Shareholder rights provisions under Russian law may impose additional costs on us, which could cause our financial results to suffer.

 

Russian law provides that shareholders, including holders of our ADSs, that voted against or did not participate in voting on certain matters, have the right to sell their shares to the company at market value, as determined in accordance with Russian law. The decisions that trigger this right to sell shares include:

 

    reorganization;

 

    approval by shareholders of a “major transaction,” which, in general terms, is a transaction involving property worth more than 50% of the book value of our assets calculated according to RAR; and

 

    amendment of our charter that restricts the shareholder’s rights.

 

Our obligation to purchase the shares in these instances is limited to 10% of our net assets calculated according to RAR, at the time the matter at issue is voted upon. Our or our subsidiaries’ obligation to purchase shares in these circumstances could have an adverse effect on our cash flows and on our business.

 

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, as amended, most recently on June 25, 2004 (the “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 General Director, members of any of our management bodies, any person that owns, together with that person’s close relatives and affiliates, at least 20% of our voting shares and any 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:

 

    a party to a transaction with the company, whether directly or as a representative or intermediary, or a beneficiary of the transaction;

 

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    the owner, together with any close relatives and affiliates, of at least 20% of the shares in the company that is a counterparty to a transaction, whether directly or as a representative or intermediary, or a beneficiary of the transaction; or

 

    a member of the board of directors or any management body of the company which is a counterparty to a transaction, whether directly or as a representative or intermediary, or a beneficiary of the transaction.

 

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 that define which transactions must be approved as “interested party” transactions are subject to different interpretations, and we cannot be certain that our application of these concepts will not be subject to challenge. Any successful challenge could result in the invalidation of transactions that are important to our business.

 

Developing and uncoordinated regulation of Russian capital markets and corporate and securities laws could lead to insufficient protection of your rights as an investor in our ADSs.

 

The regulation and supervision of the securities market, financial intermediaries and issuers are considerably less developed in Russia than in the United States and Western Europe. Securities laws, including those relating to corporate governance, disclosure and reporting requirements have only recently been adopted and laws relating to anti-fraud safeguards, insider trading restrictions and fiduciary duties are rudimentary. In addition, the Russian securities market is regulated by several different authorities which are often in competition with each other. These include:

 

    the Ministry of Finance;

 

    the Federal Antimonopoly Service;

 

    the Federal Service for Financial Markets (the “FSFM”);

 

    the Central Bank; and

 

    various professional self-regulatory organizations.

 

The regulations of these various authorities are not always coordinated and may be contradictory. In addition, Russian corporate and securities rules and regulations can change rapidly, which may adversely affect our ability to conduct securities-related transactions. 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.

 

The lack of a central and rigorously regulated share registration system in Russia may result in improper record ownership of our shares, including the shares underlying your ADSs.

 

Ownership of shares in Russian joint stock companies is determined by entries in a share register and is evidenced by extracts from that register. Currently, there is no central registration system in Russia. Share registration is carried out by the companies themselves or, as in our case, if a company has more than 50 shareholders or so elects, by registrars located throughout Russia. In addition, shareholders may elect to hold their shares through a depositary, which in turn is registered as the nominal holder of the shares in the registrar’s records. Regulations have been issued by the Federal Commission on the Securities Market, the predecessor of the FSFM, regarding the licensing conditions for such registrars and depositaries and the procedures to be followed by them when performing the functions of a registrar or a depositary. In practice, however, these regulations have not been strictly enforced, and registrars generally have relatively low levels of capitalization and inadequate insurance coverage. Moreover, registrars and depositaries are not necessarily subject to effective governmental supervision. Due to the lack of a central and rigorously regulated share registration system in Russia, transactions in respect of a company’s shares could be improperly or inaccurately recorded, and share registration could be lost through fraud, negligence or oversight by registrars or depositaries incapable of compensating shareholders for their misconduct.

 

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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 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 exchanges outside Russia). However, no procedural mechanism currently exists to collect any tax from capital gains with respect to sales of shares made between non-resident holders.

 

The Russian tax authorities currently require Russian residents 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 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.”

 

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

 

We have significant ruble-denominated revenues. Over the past decade, the ruble has at times fluctuated dramatically against the U.S. dollar. The Central Bank has from time to time imposed various currency control regulations in attempts to support the ruble, and may take further actions in the future. For example, Russian companies are currently required to repatriate our proceeds from export sales and convert into rubles 10% of such proceeds (25% prior to December 27, 2004), though in the past this percentage has been as high as 75%. Under the existing regulation the percentage of proceeds we are required to convert into rubles may be increased or decreased from time to time by the Russian authorities but may not exceed 30%. 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.

 

Federal Law No. 173-FZ “On Currency Regulation and Currency Control,” dated December 10, 2003 (the “New Currency Law”), introduced a new currency control regime, which broadly came into force in June 2004. The New Currency Law empowered the Russian government and the Central Bank to further regulate and restrict currency control matters, including operations involving foreign securities and foreign currency borrowings by Russian companies. It also abolished the need for Russian companies to obtain transaction-specific licenses from the Central Bank, envisaging instead the implementation of generally applicable restrictions on currency control operations, such as the deposit of mandatory reserves with the Central Bank and authorized banks for certain currency operations, prior registration to open certain foreign accounts and to perform certain other currency operations, and the use of special accounts for certain foreign currency operations. The Central Bank has issued some regulations that introduce rules with respect to depositing mandatory reserves, opening offshore bank accounts and certain other regulations implementing the new currency controls regime. However, Central Bank practice has not yet developed with respect to the application and enforcement of these new regulations.

 

The ruble is not convertible outside Russia and the Commonwealth of Independent States (the “CIS”), and the ability of companies operating in Russia to convert rubles into other currencies may be subject to a special account and/or mandatory reserve requirements from time to time. Because of the limited development of the foreign currency market in Russia, we may experience difficulty converting rubles into other currencies. Furthermore, the Central Bank and the Russian government may impose from time to time additional requirements under the New Currency Law, such as restricting investments by Russian companies outside of Russia, restricting any grant by Russian companies of payment deferments of more than 180 days for commodities exports or requiring the deposit, interest free, of mandatory reserves where a Russian company receives a loan from a foreign entity the maturity of which is less than three years.

 

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.

 

Furthermore, 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 major foreign currencies. Moreover, these restrictions may prevent or delay our efforts to pursue attractive acquisition opportunities outside of Russia.

 

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Risks Relating to Tatarstan

 

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 that 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.

 

Until December 31, 2004, the heads of the 89 sub-federal political units were directly elected by the residents of the relevant region. However, pursuant to Federal Law No. 184-FZ “On General Principles of Organization of Legislative (Representative) and Executive Bodies of Sub-Federal Political Units of the Russian Federation,” local executives, including President Shaimiev of Tatarstan, are nominated by the president of the Russian Federation and then confirmed by the region’s legislative body. In March 2005, President Putin first exercised this authority, dismissing Vladimir Loginov as the governor of Koryaksky autonomous district, after the region suffered a heating shortage. President Shaimiev was nominated by President Putin, and subsequently confirmed by the legislature of Tatarstan, in March 2005. Nonetheless, future appointments may cause a deterioration of the relationship between Tatartstan 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 indirect ownership interest in Tatneft, its legislative, taxation and regulatory powers, and significant informal pressures. As of May 12, 2005, Svyazinvestneftekhim, an entity wholly-owned by the Tatarstan government, held approximately 33.59% of our capital stock and 35.87% of our Ordinary Shares. As of the date of this annual report, four members of our Board of Directors are members of the Tatarstan government.

 

Tatarstan also holds a “Golden Share” – a special governmental right – in Tatneft. The exercise of its powers under the Golden Share enables 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.

 

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 OAO Tatenergo (“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

 

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our privatization, but if challenged, our privatization might not be deemed valid under Russian law. Moreover, 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.” 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.

 

Risks Relating to the Company

 

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

 

As of December 31, 2003, our total indebtedness other than promissory notes, banking deposit certificates and banking customer deposits was RR26,009 million, of which approximately RR12,796 million was long-term indebtedness and RR13,213 million was short-term indebtedness. As of December 31, 2003, RR20,237 million of our indebtedness was denominated in U.S. dollars, incurred under loan facilities with various foreign banks and which includes the issuance of Eurobonds with a face value of $125 million by Bank Zenit. 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, 2003, we had outstanding RR4,694 million in promissory notes, RR3,739 million in bank promissory notes and RR18,002 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, most notably the financial crisis in Russia in 1998, 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 (U.S.$354 million) of our hard currency indebtedness, including the principal and capitalized deferred interest. All amounts due under the restructuring agreement were repaid by March 2002.

 

In 2001 and 2002, we entered into secured syndicated loans arranged by BNP Paribas and Credit Suisse First Boston for an aggregate amount of U.S.$625 million. In April 2004, we repaid a syndicated loan of U.S.$100 million and borrowed a further U.S.$375 million in bridge loans from BNP Paribas and Credit Suisse First Boston, U.S.$187.5 million from each, for a period of six months. We repaid both of these bridge loans in 2005. Our syndicated loans are currently collateralized by aggregate oil exports of 200,000 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:

 

    limiting our access to additional financing;

 

    limiting our ability to invest in business development due to the obligation to divert a substantial portion of our hard currency revenues to debt service; and

 

    increasing our vulnerability to economic downturns and changing market conditions.

 

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.

 

Future delays in the timely completion of our financial statements or filing of our annual reports could lead to negative consequences for us, including sanctions by the New York Stock Exchange or the London Stock Exchange, or cause us to be in default under our loan agreements.

 

The delay in completing the audit of our 2003 financial statements prepared under U.S. GAAP and the consequent delay in the filing of this annual report has caused us to be in breach of the listing requirements of the New York Stock Exchange, Inc. (the “New York Stock Exchange”). Pending the filing of this annual report, the New York Stock Exchange has permitted our ADSs to

 

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continue to be traded on the exchange. Nonetheless, should such delays occur again in the future we may be subject to a number of possible consequences, including the possible commencement of suspension or delisting procedures by the New York Stock Exchange. In addition, the commencement of suspension or delisting procedures by the New York Stock Exchange may also lead the United Kingdom Listing Authority to review our listing on the London Stock Exchange Limited (the “LSE”) and to take possible action, which could, among other possible sanctions, include suspension or delisting. If a suspension or delisting were to occur, on either the New York Stock Exchange or the LSE, there would be significantly less liquidity in our ADSs, which could result in a decline in the market price of our ADSs. See “—Our independent registered public accounting firm reported material weaknesses in our internal controls and we may not be able to remedy these material weaknesses or prevent future weaknesses” under this item.

 

In addition, the delay in completing our audited 2003 financial statements led BNP Paribas to notify us that it considered an event of default to have occurred under the terms of our loan agreement with BNP Paribas for U.S.$300 million. See “Item 5—Operating and Financial Review and Prospects—Liquidity and Capital Resources—Debt—Long-term foreign currency-denominated debt.” However, we have provided BNP Paribas with our audited 2003 financial statements and consequently believe that we have cured any event of default under our loan agreement. As such, we do not believe that BNP Paribas plans to attempt to accelerate payment of this loan or to enforce the related security. Nonetheless, should such delays occur again in the future we may be considered to be in default under certain of our loan agreements. Inability to obtain waivers for any such defaults could lead to acceleration of the payment of such loans, enforcement of the related security or, more generally, impairment of our ability to raise additional capital. See “—Our independent registered public accounting firm reported material weaknesses in our internal controls and we may not be able to remedy these material weaknesses or prevent future weaknesses” under this item.

 

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 2003, we sold approximately 28.1% of our crude oil volumes (including purchased crude oil) and 61.3% of our refined products volumes (including purchased refined products) within Russia, accounting for approximately 12.6% of our total revenues from sales of crude oil and 53.7% of our total revenues from sales of refined products, respectively. Russian crude oil prices remain below international spot market price levels due to significantly lower transport costs, 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 most 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, failure to pay expenses or taxes to the Russian government 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.

 

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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, 2004, 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 47.5% in 2004, 42.5% in 2003, 41.1% in 2002 and 40.9% in 2001) 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, virtually all 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 U.S.$2.50 per ton (exclusive of VAT) 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, often referred to as the “quality bank,” are adopted, the current system will be changed to our significant detriment and our business and results of operations would be adversely affected. See “Item 4—Information on the Company—Exploration and Production.”

 

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. Moreover, there are a limited number of refineries in Europe that have the technical capabilities necessary to refine high sulfur crude oil. We have taken steps to diversify our outlets for high sulfur content crude oil 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.

 

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. 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 of our crude oil or refined products at below market prices. See “Item 4—Information on the Company—Exploration and Production—Refining and Marketing—Crude Oil—Government-Directed Deliveries.”

 

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

 

A dispute with one of our business partners over the lease of a refining unit at the Nizhnekamsk oil refinery may have a material adverse effect on the value of the refining units owned by us and on our ability to process crude oil in Tatarstan.

 

Since 1999, our most significant capital expenditures were for the upgrade of the Nizhnekamsk oil refinery. Acting at the urging of Tatarstan President Shaimiev, in 1999 we formed a joint venture company, OAO Nizhnekamsk Oil Refinery, with OAO Nizhnekamskneftekhim and OAO Tataro-American Investments and Finance (“TAIF”) to expand, upgrade, and operate the refinery in Nizhnekamsk – the only oil refinery in Tatarstan. At the start of the upgrade, the refinery consisted of the TAIF-owned unit, built in 1976, leased by us and providing its refined products output to Nizhnekamskneftekhim. The upgrade included improvements to that unit and construction of a base refining complex consisting of six additional refining units supplied by the TAIF unit and producing products of higher added value. Following the completion of the upgrade, the partners were expected to contribute their assets to the charter capital of OAO Nizhnekamsk Oil Refinery, receiving a stake in the company in proportion to the value of their contribution. Pending the contribution of assets into its charter capital, OAO Nizhnekmask Oil Refinery leased all refining units from their owners. Our total investment in the refinery through January 1, 2005 amounted to approximately RR8,438.4 million, and we own the units whose construction we financed directly.

 

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Following the completion of the Phase I base complex in December 2002, we were not able to agree with TAIF on the value of its refining unit. In 2003, TAIF won a judgment terminating the lease of its refining unit to Nizhnekamsk Oil Refinery, and in 2004 this judgment was confirmed on appeal. Following the judgment, TAIF has not taken any steps to immediately evict Nizhnekamsk Oil Refinery, which currently continues to operate and make payments for the use of the unit. Should Nizhnekamsk Oil Refinery be required to vacate the unit this may adversely affect the operation of the other units that are technologically integrated with it, reducing the value of our investment in such units. In addition, should TAIF take over the operation of its unit, it may decide to diversify its supplier base, which may lead to the reduction of our deliveries of crude oil to Nizhnekamsk Oil Refinery and force us to seek other domestic customers. In 2004, 5.84 million tons of crude oil representing approximately 63% of all our domestic crude oil deliveries were to the Nizhnekamsk Oil Refinery.

 

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 taxes and export duties, income tax, value added tax, tax on the extraction of commercial minerals, property tax, social tax and pension contributions. 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 31% and a total tax burden of 31% (income taxes and taxes other than income taxes as a percentage of sales and other operating revenue) in 2003.

 

Laws related to these taxes, such as the Russian 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 Federal Tax Service, 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. Several Russian companies have recently been subjected to additional claims for taxes in prior years, including YUKOS, Vimpelcom and TNK-BP. These facts create tax risks in Russia substantially greater than typically found in countries with more developed tax systems. In addition, in April 2005 we received a claim for back taxes from the federal tax authorities, based on its review of our tax filings for the years 2001, 2002 and 2003, in the amount of RR1,380 million. This amount includes both alleged non-payment and under-payment of taxes as well as fines and penalties. While we could challenge this claim, given other Russian companies’ recent experiences in this area, we have decided not to do so and paid all sums due in May 2005. Moreover, we recognize that this claim is significantly smaller than similar claims recently received by other Russian companies.

 

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 the possible imposition of 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 (if dividends are paid by a Russian company to another Russian company, the tax base would be determined as the difference between dividends to be paid and dividends received). Currently, dividends payable to a Russian entity are taxed at 6%, and the payer is required to withhold the tax when paying the dividend.

 

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. For example, in May 2004, a law was approved that increased the base tax rate for the unified natural resources production tax from RR347 to RR419 per ton of crude oil starting from January 1, 2005, and in June 2004 crude oil export duty rates were adjusted upwards. Accordingly, we may have to pay significantly higher taxes, which could have a material adverse effect on our business.

 

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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. Our failure to pay these expenses could result in the termination or temporary suspension of our access to these export pipelines and seaports, which 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.

 

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:

 

    unexpected drilling conditions;

 

    pressure or irregularities in formations;

 

    equipment failures or accidents;

 

    shortages in experienced labor or delays in the delivery of equipment;

 

    blowouts (i.e., uncontrolled releases of fluids, solids or gases) and surface cratering;

 

    pipe or cement failures;

 

    casing collapse; and

 

    embedded oil field drilling and service tools.

 

We only have a certain and potentially 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 the death or incapacitation of our senior managers. Accordingly, losses or liabilities arising from such events could increase our costs and have an 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. During 2003 and 2004, approximately 30% of our approximately 1.1 million tons per month of non-CIS crude oil exports were 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.

 

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Our exploration, development and production licenses may be suspended, amended or revoked prior to their scheduled expiration.

 

The licensing regime in Russia for the exploration, development and production of oil and natural gas is governed primarily by the Federal Law on Use of Subsoil of February 21, 1992, 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 must be extended by the relevant authorities at the initiative of the license holder if the extension is necessary to finish production in the field, provided that the licensee has not violated the terms of the license. We believe that our existing production licenses will be extended at or prior to their scheduled expiration and we are currently in the process of requesting extensions for our most significant fields, including Romashkinskoye, our largest field.

 

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. If the Russian government determines that we have failed 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. See “Item 4—Information on the Company—Exploration and Production.”

 

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. See “Item 4—Information on the Company—Exploration and Production.”

 

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 materially adversely affect 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. See “Item 4—Information on the Company—Corporate Reorganization.”

 

Our independent registered public accounting firm reported material weaknesses in our internal controls and we may not be able to remedy these material weaknesses or prevent future weaknesses.

 

In connection with their audit of our consolidated financial statements for the year ended December 31, 2003, Ernst & Young, our independent auditor, reported weaknesses in our internal controls, as had PricewaterhouseCoopers, our independent auditor in respect of prior periods. Specifically, our independent auditor found that our system of internal control lacks adequate processes and controls relating to the timely and accurate capture and recording of transactions in accordance with U.S. GAAP that would reduce to a relatively low level the risk that errors in amounts that would be material in relation to those financial statements may

 

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occur and may not be detected within a timely period by management in the normal course of business. In particular, our independent auditor found that:

 

    There is no process in place to ensure that the personnel charged with financial statement preparation are timely and fully informed by senior management about business transactions in order to assess the necessity of their recognition in the consolidated financial statements prepared in accordance with U.S. GAAP. In addition, while management with knowledge about the business in general and specific significant transactions review the U.S. GAAP financial statements, their knowledge of U.S. GAAP and the SEC rules is limited. Accordingly, there is a risk that the financial statements may be materially misstated, since they might not reflect all our business transactions.

 

    Our personnel directly involved in financial reporting under U.S. GAAP consist of seven employees. Given our size, the complexity of our business transactions, the number of locations involved, the increasing requirements from regulatory bodies and the absence of integrated information systems to support the process for U.S. GAAP financial reporting, the size of our financial reporting department is inadequate to meet the applicable U.S. GAAP and the SEC reporting requirements. There is a risk therefore that financial information may be materially misstated, since in the process of financial statement closing the results of various transactions may not be correctly summarized, reviewed, consolidated, edited and included into a variety of regulatory and financial reports.

 

    There is no process in place to ensure that all entities (including those deemed immaterial) where we exercise control/significant influence are consolidated/equity accounted for U.S. GAAP purposes. As a part of this control weakness, it was noted that no analysis was performed to determine the effects of Interpretation No. 46 “Consolidation of variable interest entities” and subsequently issued revised Interpretation No. 46 (FIN 46R) on the U.S. GAAP financial statements. There is a risk therefore that the financial statements may be materially misstated, since they might not reflect all assets, liabilities and financial results of our entities or entities where we are the primary beneficiary.

 

    There is no process in place to ensure that all related parties, as defined by U.S. GAAP and the SEC, are identified and the nature of relationships and respective transactions are reflected in the consolidated financial statements. Such determination is generally made on the basis of Russian legislation, which has a different definition of related parties compared to the requirements prescribed by U.S. GAAP and the SEC. There is a risk therefore that the financial statements may not reflect all material related party transactions.

 

In addition, an independent legal investigation, undertaken at the request of our Audit Committee, indicated the following weaknesses in our internal controls: a lack of written policies and procedures at the group level; certain transactions not properly communicated to accounting and finance; incorrect recording of transactions, including failure to properly record substantial amounts of money being loaned; and procuring stock for a possible stock-based compensation plan without a complete formulation of the plan resulting in a failure to properly record treasury stock. The investigation found that our control environment (including our maintenance of books and records and internal controls) was inadequate under the applicable requirements of the Exchange Act.

 

One of the components of internal control is the control environment. The control environment reflects the tone of the organization, which influences the control consciousness of its personnel. The key factors affecting the control environment include among other things, participation of the Board of Directors, management’s philosophy and clearly defined operating style, organizational structure, assignment of authority and responsibility and policies and procedures. Our independent auditor found that the lack of clearly defined and articulated policies and procedures, combined with a management tone which does not stress the importance of controls within the organization, increases the risk of error or misstatement in reported financial results. In a weak control environment such as ours, there is usually a greater likelihood that the specific risks created by one identified deficiency will not be overcome by strengths in other areas or by the basic attitude of the organization toward controls.

 

For further discussion of the independent legal investigation, its conclusions and the steps that we are taking to remedy our control deficiencies, see “Item 15—Controls and Procedures.” Notwithstanding the steps we are taking to address these issues, we may not be successful in remedying these material weaknesses or preventing future material weaknesses. If we are unable to remedy these material weaknesses, there is a risk that we may not be able to prevent or detect a material misstatement of our annual or interim U.S. GAAP consolidated financial statements. In addition, any failure to implement new or improved internal controls, or resolve difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our shares and ADSs.

 

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

 

We expect that the ongoing restructuring of the oil and natural 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

 

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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 sale of the YUKOS subsidiary Yuganskneftegaz to the state-owned oil company Rosneft. 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, including in Tatarstan. See “Item 4—Information on the Company—Competition.”

 

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 markets for our Ordinary Shares are the Russian Trading System (“RTS”) and the Moscow Interbank Currency Exchange (“MICEX”). 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, has at times experienced significant downturns. For example, 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 the financial crisis in 1998, this trend may not continue, as indicated by high volatility during 2004.

 

Excessive appreciation of the ruble against the U.S. dollar would adversely affect our margins and cash flows.

 

After a protracted period of weakness, the ruble has appreciated against the U.S. dollar in recent years, including by 15% in 2003 and 13.6% in 2004 in real terms. Because our revenues are substantially linked to the U.S. dollar and our costs (other than a large portion of debt-service costs) are denominated primarily in rubles, the real appreciation of the ruble has already had and may continue to have an adverse effect on our business, results of operations, financial condition and cash flows by causing our costs to increase relative to our revenue.

 

Risks Relating to the Oil Industry

 

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:

 

    global and regional supply and demand, and expectations regarding future supply and demand, for crude oil and petroleum products;

 

    market uncertainty;

 

    weather conditions;

 

    domestic and foreign governmental regulations;

 

    prices and availability of alternative fuels;

 

    prices and availability of new technologies;

 

    the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”), and other crude oil producing nations, to set and maintain specified levels of production and prices;

 

    political and economic developments in oil producing regions, particularly the Middle East;

 

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    Russian and foreign governmental regulations and actions, including export restrictions and taxes;

 

    the recent tension and military action in Iraq and related activities; and

 

    global and regional economic conditions.

 

The decline in world oil prices from October 1997 to December 1998 by more than 54% to less than U.S.$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. According to the International Energy Agency, the average prices of Brent crude, an international benchmark oil price, for the three years ended December 31, 2003, 2002 and 2001, were approximately U.S.$28.83, U.S.$25.02 and U.S.$24.44 per barrel, respectively. The average price of Brent crude increased to U.S.$38.22 per barrel in 2004 and the price of Brent crude was U.S.$47.90 per barrel at May 19, 2005. Crude oil prices increased in 2003 and 2004, following a slight increase in 2002 and after declining significantly in 2001, as a result of export restrictions imposed by OPEC and certain other crude oil producing nations, including Russia, in 2003, improving global economic conditions and heightened tensions in the Middle East and war in Iraq. 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 Reports 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 this annual report and in the Reserves Reports, incorporated by reference into this annual report from our reports on Forms 6-K furnished to the SEC on July 23, 2004 and June 29, 2005, respectively, are estimates based primarily on internal engineering analyses that were audited by Miller and Lents, independent petroleum engineering consultants as of January 1, 2004 and 2005, respectively. The most recent reserves estimates were calculated using oil and natural gas prices in effect on January 1, 2005. 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 natural gas that cannot be measured in an exact manner. Estimates of the value and quantity of economically recoverable oil and natural 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:

 

    historical production from the area compared with production from other comparable producing areas;

 

    interpretation of geological and geophysical data;

 

    the assumed effects of regulations adopted by governmental agencies;

 

    assumptions concerning future percentages of international sales;

 

    assumptions concerning future oil and natural gas prices;

 

    capital expenditures; and

 

    assumptions concerning future operating costs, tax on the extraction of commercial minerals and excise taxes, development costs and workover and remedial costs.

 

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 Reports:

 

    the quantities and qualities of oil and natural gas that are ultimately recovered;

 

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    the production and operating costs incurred;

 

    the amount and timing of future development expenditures; and

 

    future oil and natural gas sales prices.

 

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. See “Item 4—Information on the Company—Exploration and Production.”

 

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 applications 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 licenses, increasingly strict enforcement of, or new interpretations of, existing laws, regulations and licenses, or the discovery of previously unknown contamination may require further expenditures to:

 

    modify operations;

 

    install pollution control equipment;

 

    perform site clean-ups;

 

    curtail or cease certain operations; or

 

    pay fees or fines or make other payments for pollution, discharges or other breaches of environmental requirements.

 

Furthermore, the implementation of the Kyoto Protocol to the United Nations Framework Convention on Climate Change from February 2005 (the “Kyoto Protocol”) may impose new and/or additional rules or more stringent environmental norms. Such requirements may require additional capital expenditures or modifications in our operating practices.

 

Under existing legislation, we believe that there are no significant environmental liabilities, beyond the amounts that we have already incurred in order to comply with the environmental requirements, that will have a material adverse effect on our operating results or our financial position.

 

Although the costs of the measures taken to comply with the 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 related to environmental damage caused by us may increase. Furthermore, we do not have any insurance for environmental damage caused by our activities.

 

Risks Relating to Investment in our ADSs

 

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.

 

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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 an existing market within Russia for the conversion of rubles into U.S. dollars, including the interbank currency exchange and over-the-counter and 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. In addition, our loan agreements with some of our hard currency lenders contain 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, Syria 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, Syria and Sudan. We have opened a representative office in Iran and in February 2005 the government of Tatarstan and the government of Iran concluded an agreement pursuant to which we are expecting to register a joint venture with an Iranian entity in order to participate in various projects in Iran, including tenders for the development of oil fields. The terms of our participation in this venture have not yet been finalized. 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 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. In March 2005, we concluded an agreement with the government of Syria and the Syrian Oil Company according to which we are to explore and to produce oil in eastern Syria. We and/or our affiliates have also discussed proposals for business projects with parties in Libya and Sudan. After the Libyan government opened its territory for international experts in September 2003, the U.N. lifted sanctions against Libya, and most U.S. trade sanctions were suspended in April 2004 and removed in September 2004.

 

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. However, we believe that none of our activities in Iraq was prohibited by U.S. or international sanctions. We do not currently engage in any significant activities in Iraq.

 

In the future, we may enter into permitted transactions with other countries against which sanctions have been applied. If we violate existing U.S. or international 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, and have not in the past been, involved in any transactions with Iran, Iraq, Libya, Syria 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, 2005, the Tatarstan government, through its wholly-owned entity, Svyazinvestneftekhim, held approximately 33.59% of our capital stock and 35.87% of our Ordinary Shares. Svyazinvestneftekhim is free to dispose of the Ordinary Shares it holds at any time. Significant dispositions of these shares could adversely affect the price of our ADSs.

 

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

 

According to the Law on the Securities Market and the regulations of the Russian Federal Commission on the Securities Market, the predecessor of the FSFM, the deposit of shares of a Russian company into an ADR program requires the permission of the FSFM. Such permission may be denied, among other reasons, if more than 40% of the class of shares eligible for deposit into the ADR program will circulate outside Russia, including in the form of ADSs, 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 FSFM regulation applies to ADR programs into which additional shares have been deposited and/or continue to be deposited in excess of 40% of the Ordinary Shares at the time of enactment of the regulation, or only to ADR programs established after the time of its enactment. Articles appearing in the press have noted that in January 2003, The Bank of New York ceased deposits of shares of another Russian company into its ADR program after the aggregate number of shares deposited into the program exceeded the amount permitted by the FSFM for this company. We have never applied to the FSFM or its predecessor entities for permission for our ADR program. The number of the Ordinary Shares deposited in our ADR program constitutes approximately 22.6% of our Ordinary Shares, and we may be required to limit the amount of the Ordinary Shares deposited in our ADR program to 40% of our Ordinary Shares. Accordingly, we can give no assurance that The Bank of New York, acting as a depositary for our ADR program, will allow additional deposits of the Ordinary Shares if they exceed the 40% limitation. Furthermore, the FSFM regulation does not specify the consequences of violating the regulation. An assertion that the FSFM regulation and/or the limitation on shares deposited in the program 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 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 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, the Joint-Stock Companies Law and the Charter require 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 ADS holders 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.

 

Because the depositary may be considered the beneficial holder of the shares underlying the ADSs, these shares may be arrested or seized in legal proceedings in Russia against the depositary, adversely affecting the holders of our ADSs.

 

Russian 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, on behalf of their clients and investors, holding in Russia through a Russian licensed custodian, securities issued by Russian companies, including our Ordinary Shares underlying our ADSs, are required to obtain a license from the FSFM 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. Because Russian law may not recognize ADS holders as beneficial owners of the underlying shares, it is possible that an ADS holder could lose all its rights to those shares if the depositary’s assets in Russia are seized or arrested. In that case, an ADS holder would lose all the money invested in our ADSs.

 

Russian law might treat the depositary as the beneficial owner of the shares underlying the ADSs. This is different from the way other jurisdictions treat ADSs. In most states of the United States, for example, although shares may be held in the depositary’s name or to its order, making it a “legal” owner of the shares, the ADS holders are the “beneficial,” or real owners. In those jurisdictions, an action against the depositary, the legal owner, would not result in the beneficial owners losing their shares. Russian law may not make the same distinction between legal and beneficial ownership, and a court may only recognize the rights of the depositary in whose name the shares are held, not the rights of ADS holders, to the underlying shares. 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 or arrest. We do not know yet whether the shares underlying the ADSs may be

 

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seized or arrested in Russian legal proceedings against a depositary. In the past, a lawsuit was filed against a depositary bank seeking the seizure of various Russian companies’ shares represented by ADSs issued by that depositary. In the event that this type of suit was successful in the future, and if the shares are seized or arrested, the ADS holders involved would lose their rights to the underlying shares.

 

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 Federal Antimonopoly Service, a successor to 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, 2005, the depositary for our ADR program held approximately 22.6% 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 your legal recourse against us. 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. 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. In addition, it may be difficult for you to enforce liabilities predicated upon U.S. securities laws in original actions brought in courts in jurisdictions outside 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% in other cases under the United States-Russia double tax treaty. See “Item 10—Additional Information—Taxation.”

 

Other Risks

 

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.

 

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ITEM 4. INFORMATION ON THE COMPANY

 

BUSINESS OVERVIEW

 

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 over 80% of the crude oil produced in Tatarstan. As of January 1, 2004, our total proved reserves of crude oil were approximately 836.6 million tons (5,959 million barrels (“mmbbl”)) and as of January 1, 2005, our total proved reserves of crude oil were approximately 837.1 million tons (5,962.5 mmbbl). See “—Exploration and Production.” 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 one of Russia’s largest tire producers OAO Nizhnekamskshina (“Nizhnekamskshina”) and providing banking services through our subsidiaries OAO Bank Zenit (“Bank Zenit”) and Commercial Bank Devon-Credit (“Bank Devon-Credit”). In April 2005, our wholly-owned subsidiary, Tatneft Oil AG, sold its 26.75% stake in Bank Zenit to three companies acting for the benefit of beneficiaries of Urals Energy NV. This transaction had the effect of reducing our ownership interest in Bank Zenit from 52.7% to 25.95%. See Annex A to this report. Our sales and other operating revenues were RR155,818 million, RR146,328 million and RR156,861 million for the years ended December 31, 2003, 2002 and 2001, respectively. We employed approximately 98,000 and 100,400 persons as of December 31, 2003 and 2004, respectively.

 

HISTORY AND DEVELOPMENT

 

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 in connection with any suit or proceeding arising out of our relating to our ordinary shares, ADSs or the deposit agreement pursuant to which they were issued is Puglisi & Associates, 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 in Tatarstan. 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 joint-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, and Romashkinskoye oil field, the largest oil field in Tatarstan, was discovered in 1948. PA Tatneft received the right to develop the Romashkinskoye field in 1950 when PA Tatneft was 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 one of the largest Russian tire producers, Nizhnekamskshina, and its technologically-integrated enterprises and management company OOO Tatneft-Neftekhim (“Tatneft-Neftekhim”)) and banking operations (including majority stakes in Bank Devon-Credit, an Almetyevsk-based retail and commercial bank that serves southeastern Tatarstan, and, until April 2005, Bank Zenit, the eighteenth largest Russian bank by shareholders’ equity, sixteenth largest by assets and eighteenth largest by net profits as of October 1, 2004, as calculated under RAR, according to Expert magazine). For a further discussion of our banking subsidiaries see Annex A to this annual report.

 

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We have a number of oil production joint ventures. These include ZAO TATEX (“TATEX”), which installs Tatneft’s unique vapor recovery system in its holding tanks and produces small amounts of crude oil from one field using horizontal drilling techniques; ZAO Tatoilgas (“Tatoilgas”), which specializes in the recovery of oil from sludge and operates several small oil fields in Tatarstan; and, until 2005, ZAO Kalmtatneft (“Kalmtatneft”), a small oil company engaged in crude oil exploration and production activities in the Republic of Kalmykia, Russia. In 2005 we sold 100% of our interest in Kalmtatneft. In addition, we have entered into a joint operations agreement with ZAO Ritek-Vnedreniye (“Ritek-Vnedreniye”), pursuant to which Ritek-Vnedreniye operates the third block of the Pavlovskoye area of the Romashkinskoye oil field. We are entitled to 60% of the economic benefit from Ritek-Vnedreniye’s production from this deposit.

 

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 13%. 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 transferred the assets of 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 2003, we increased our stake in Nizhnekamskshina from 51.7% to 76.01% following a new share issuance by Nizhnekamskshina. We also raised our ownership interest in Bank Ak Bars from approximately 17.9% to approximately 21.77% and in ZAO Chulpan (“Chulpan”) from 79.6% to 95.8%, divested our interests in 21 agricultural companies and sold our 75.01% stake in OAO Tatincom-T, a regional cellular telecommunications company. 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. In the beginning of 2003, we also increased our ownership in of OAO Finansovaya Lizingovaya Kompania, a leasing company, from 12% to 21%. In October of 2003, we sold our interest in this company for RR676 million, resulting in a loss of RR99 million.

 

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 RR2,162 million, RR1,293 million and RR593 million in the years ended December 31, 2003, 2002 and 2001, respectively.

 

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

 

Developments in 2004 and 2005

 

Our capital expenditures for 2004 (exclusive of acquisitions) were approximately RR10,800 million, which were be financed through debt and operating cash flows. Our most significant current capital commitment for 2004 was made on production development, drilling development and other equipment to maintain current crude oil production. However, we have also made significant investments in the Nizhnekamsk oil 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 RR8,438.4 million as of January 1, 2005, and we budgeted capital expenditures of approximately RR252.2 million for work on the refinery during 2005. We currently own 63% of OAO Nizhnekamsk Oil Refinery. However, we

 

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have not yet reached an 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. See “Item 3—Risk Factors—Risks Relating to the Company—A dispute with one of our business partners over the lease of a refining unit at the Nizhnekamsk oil refinery may have a material adverse affect on the value of the refining units owned by us and on our ability to process crude oil in Tatarstan.”

 

In December 2003, together with the government of Tatarstan, OAO Tatneftekhiminvest-Holding, OAO Nizhnekamskneftekhim, LG International Corp. and LG Engineering and Construction, we signed a letter of intent contemplating future joint work on the construction of an oil refining and petrochemical complex in Tatarstan. We subsequently formed OAO TKNK in order to carry out feasibility studies and arrange for financing of the construction of the oil refining and petrochemical complex. We hold a 45.5% interest in OAO TKNK; Nizhnekamksneftekhim holds a 36.4% interest; OAO Svyazinvestneftekhim holds a 9.1% interest; and LG International Corp. holds a 9.1% interest. In September 2004, TKNK entered into a non-binding engineering, procurement and construction works arrangement with LG International Corp. and LG Engineering and Construction Corp. that sets forth the basic terms by which the LG parties are to carry out engineering, procurement and construction work on oil refinery and petrochemical complexes in Nizhnekamsk. TKNK and the LG parties entered into a further non-binding engineering, procurement and construction work arrangement in December 2004 that provides for the construction of certain refining equipment in Nizhnekamsk. In May 2004, Tatneft provided TKNK with a U.S.$4.3 million loan for financing feasibility studies and services as part of developing the oil refining and petrochemical complex. In addition, Tatneft has invested RR40 million in the first phase of the construction of the oil refining plant. In accordance with preliminary feasibility studies of construction of the oil refining plant prepared by LG, the total necessary investment will amount to approximately U.S.$1.8 billion. However, at this stage we cannot predict the level of additional capital investment that may be required from us in connection with this project.

 

In January 2004, Efremov Kautschuk GmbH, a subsidiary of OAO “Efremovsky Zavod Sinteticheskogo Kauchuka” was announced as the winner of a privatization auction for 65.8% of Turkey’s oil refining monopoly Türkiye Petrol Rafinerileri A.S. (“Tupras”). OAO “Efremovsky Zavod Sinteticheskogo Kauchuka” is a related party to us as members of our senior management are on the board of directors of OAO ”Efremovsky Zavod Sinteticheskogo Kauchuka.” Subsequently Efremov Kautschuk GmbH formed a consortium with Zorlu Holding A.S. and established a joint venture, Tatneft Zorlu Petrol Yatirimlari Ve Ticaret A.S. (“Tatneft-Zorlu”), of which we agreed to purchase 50% if Tatneft-Zorlu acquired the shares in Tupras. On June 6, 2004, Turkey’s Administrative Court invalidated the tender for the sale of a controlling stake in Tupras in a suit brought by the trade union representing Tupras workers, and this decision was upheld on appeal by the Supreme Administrative Court of Turkey in November 2004. Consequently, our undertaking to purchase 50% in Tatneft-Zorlu from Efremov Kautschuk GmbH was terminated. In May 2005 the government of Turkey announced a new auction for 51% of Tupras. We are not participating in this new auction and have no commitment to participate in any future auction or tender for the sale of Tupras shares, which may be organized by the government of Turkey, or otherwise to acquire any shares in Tupras.

 

In 2004, we concluded an agency agreement with Integrated Petroleum Services Co. to market Tatneft’s technologies and services in Oman. In addition, in May 2005 we registered a joint venture with Omani company Hamed International Marketing and Services Co. LLC to promote our products and services in Oman and other countries in the region. In 2005, we held discussions with the state-owned Petroleum Development Company of Oman regarding local well-casing technology for problem wells. In 2005, we also signed an agreement with an Omani firm for the development of special-sized well casings.

 

We have opened a representative office in Iran, and in February 2005 the government of Tatarstan and the government of Iran concluded an agreement pursuant to which we are expecting to register a joint venture with an Iranian entity in order to participate in various projects in Iran, including tenders for the development of oil fields. Our participation in this venture and the terms of any such participation have not yet been finalized.

 

In March 2005, we concluded an agreement with the government of Syria and the Syrian Oil Company according to which we are to explore for oil in eastern Syria and to develop this field on the basis of a 25-year production sharing agreement. We are required to spend at least $7 million on exploration activities over three years, but we may extend this for two additional two-year periods, provided that we make additional minimum expenditures of $6.3 million and $12.8 million, respectively.

 

In 2004, we increased our ownership interest in Bank Zenit from 50% plus one share to 52.7%. However, in April 2005, our wholly-owned subsidiary, Tatneft Oil AG, sold its 26.75% stake in Bank Zenit to three companies acting for the benefit of beneficiaries of Urals Energy NV. This transaction had the effect of reducing our ownership interest in Bank Zenit to 25.95%. From the year ended December 31, 2005, our sale of Bank Zenit shares will result in a loss on securities disposals of approximately RR700 million. From April 2005 we will account for our investment in Bank Zenit under the equity method. See “Appendix A—Tatneft’s Banking Operations.”

 

In 2004 and 2005, we increased our shareholding in Bank Ak Bars to 29.98%.

 

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In 2005, we sold 100% of our interest in Kalmtatneft.

 

In addition, over the course of 2004 and 2005 we have acquired a number of oil production subsidiaries. These include OOO Tatneft-Abdulino, ZAO Abdulinskneftegaz, OOO Tatneft Severny, ZAO Tatneft-Samara, ZAO Severgeologia and ZAO Severgaznefteprom and OAO Ilekneft. We own 75.1% in each of OOO Tatneft-Abdulino and OOO Tatneft Severny, which hold one and two subsoil licenses, respectively, for the exploration of hydrocarbon materials in deposits in the Orenburg Region. OOO Tatneft-Abdulino and OOO Tatneft Severny each also received an additional license for the exploration of hydrocarbon materials in deposits in the Orenburg Region in a license tender held on March 29, 2005. We also acquired 51% of ZAO Abdulinskneftegaz, in 2004, which holds one geological survey license for oil fields in the Orenburg Region. Tatneft also holds a 74.9% interest in ZAO Tatneft-Samara, which holds three subsoil licenses for the exploration of hydrocarbon materials in deposits in the Samara Region and recently received an additional two licenses for the exploration and production of hydrocarbon materials in deposits in the Samara Region in a license tender held on February 22, 2005. In 2005, we acquired 50% of both ZAO Severgeologia and ZAO Severgaznefteprom, which each hold two geological survey licenses for oil fields in Nenetsk Autonomous District. We, along with Rosneft, which owns the remaining portion in these entities, have developed a geological exploration program for 2005 to 2007. While at this stage we cannot predict the level of capital investment that may be required of us in connection with ZAO Severgeologia and ZAO Severgaznefteprom, preliminary studies suggest that total necessary investment will amount to RR1.4 billion. In 2004 we acquired 70% of OAO Ilekneft, which holds one production license and two combined exploration and production licenses. In 2004, we also acquired 33.3% of Kalmneftegaz. See “—Exploration and Production.”

 

ORGANIZATIONAL STRUCTURE

 

General

 

Our operations are currently divided into the following main segments:

 

    exploration and production;

 

    refining and marketing;

 

    petrochemicals; and

 

    banking.

 

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; three 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 and Ukrtatnafta; OOO Tatneft-Centernefteproduct, a management company for Tatneft-branded gas station network; and certain other oil trading and ancillary companies.

 

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

 

Bank Zenit and Bank Devon-Credit constitute our banking segment. We also hold stakes in a number of other financial services companies.

 

We 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.

 

Joint Ventures, Subsidiaries and Associated Companies

 

We have a number of oil production joint ventures. These include TATEX, in which we own 50% and which are accounted for under the equity method in our consolidated financial statements, Kalmtatneft, in which we owned 50% and which was accounted for under the equity method until 2005 when we sold 100% of our stake in Kalmtatneft, and Tatoilgas, in which we

 

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currently own 50% but maintain management control and which is fully consolidated. We are also party to a joint operations agreement with Ritek-Vnedreniye pursuant to which Ritek-Vnedreniye operates an oil field that is licensed to us, and we provide various services to Ritek-Vnedreniye in connection with its operations. We are entitled to 60% of the economic benefit from Ritek-Vnedreniye’s operations of this field.

 

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, including our Western European marketing agent Tatneft Europe AG (“Tatneft Europe”), which are incorporated in Switzerland, all of our significant joint ventures, subsidiaries and associates are incorporated in the Russian Federation.

 

The joint ventures are:

 

    ZAO TATEX. TATEX is a joint venture with the U.S. company Texneft (a subsidiary of Ocean Energy Inc.) in which we each held a 50% interest as of December 31, 2003. TATEX has installed oil vapor recovery systems on all of Tatneft’s oil holding tanks to capture natural gas; TATEX subsequently sells this natural gas. TATEX has also obtained rights to the Onbiyskoye oil field, previously developed by Tatneft, where TATEX produces oil. In 2003, TATEX produced approximately 486,141 tons (3.46 mmbbl) of oil, and in 2004 it produced approximately 492,633 tons (3.50 mmbbl) of oil.

 

    ZAO Tatoilgas. At December 31, 2003, we owned 50% of the voting shares of Tatoilgas, a joint venture with the German firm Mineralol-Rohstoff-Handel, GmbH. Tatoilgas recovers oil from sludge and holds production licenses for two small oil fields. In 2003, Tatoilgas produced approximately 265,301 tons (1.89 mmbbl) of oil and in 2004 it produced approximately 257,198 tons (1.83 mmbbl) of oil. Tatoilgas is consolidated in our consolidated financial statements.

 

    ZAO Kalmtatneft. Until 2005, we owned 50% of Kalmtatneft, which holds four licenses to explore and develop four oil fields in Kalmykia. However, in 2005 we sold 100% of our interest in Kalmtatneft.

 

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.

 

    OAO Nizhnekamskshina. We purchased approximately 34.6% of Nizhnekamskshina in 2000 from the Tatarstan government as part of our strategy to become a vertically integrated oil company. In 2001, we increased our stake to 51.7% and Nizhnekamskshina was consolidated in our consolidated financial statements from September 30, 2001. In 2003 we increased our stake to 76.0% following an additional share issuance by Nizhnekamskshina. Nizhnekamskshina is one of the largest tire manufacturing plants in Russia, and supplies products to both domestic and foreign markets. The Tatarstan government holds a Golden Share in Nizhnekamskshina that permits it to veto certain board and shareholder decisions and to appoint representatives to Nizhnekamskshina’s management bodies.

 

    OAO Bank Zenit. In April 2005, we owned 52.7% of Bank Zenit, a Russian commercial bank founded in December 1994 and based in Moscow, having increased our holdings from 50% plus one share in 2004. Bank Zenit has branches in Rostov-on-Don, Nizhny Novgorod, Almetyevsk, Gorno-Altaisk, St. Petersburg, Kemerovo and Kursk, a representative office in Kazan and additional offices in Kazan and Nizhnekamsk. In April 2005, our wholly-owned subsidiary, Tatneft Oil AG, sold its 26.75% stake in Bank Zenit to three companies acting for the benefit of beneficiaries of Urals Energy NV. This transaction had the effect of reducing our ownership interest in Bank Zenit to 25.95%. See “Appendix A—Tatneft’s Banking Operations.”

 

    ZAO IFK Solid. We own approximately 59.7% of IFK Solid, a Russian broker-dealer. IFK Solid is a market maker in our shares in the Russian equity markets and also serves as a financial advisor and agent to us for transactions in the Russian equity markets and in connection with our stock option plan. See “Item 9—The Offer and Listing—Markets—Activities of the Company and its Affiliates in the Market” and “Item 6—Directors, Senior Management, and Employees—Compensation.”

 

    Bank Ak Bars. As of December 31, 2003 we owned approximately 21.77% of Bank Ak Bars, the largest private bank located in the Republic of Tatarstan in terms of assets and number of retail customers. In 2004 and 2005 we increased our shareholding and currently hold 29.98% of Bank Ak Bars.

 

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    Bank Devon-Credit. We own approximately 95.3% of Bank Devon-Credit, a Russian commercial and retail bank. Bank Devon-Credit serves Tatneft and much of the local population in Almetyevsk and the southeast of Tatarstan through a network of 13 branch offices.

 

    Tatneft, Solid & Co. Tatneft is both a general partner and a limited partner in Tatneft, Solid & Co., a limited partnership set up to purchase our Ordinary Shares. See “Item 9—The Offer and Listing—Markets—The Ordinary Share Market.”

 

    ZAO Chulpan. As of December 31, 2003, we owned approximately 95.8% of Chulpan, an Almetyevsk-based insurance company that provides voluntary medical and property insurance services. In 2004, Chulpan undertook two additional share issuances, in which we did not participate. This decreased our ownership share in Chulpan to 45.5%.

 

    Marketing Agents. We have formed a number of smaller companies that act as sales agents dedicated to working with specific refineries and markets. One of these agents, Tatneft Europe, registered in Switzerland, is one of the major offtakers of our oil. Each of the sales agents is consolidated in our consolidated financial statements.

 

    OAO Tatneftegeofizika. We own 88.1% of a geophysical services company, OAO Tatneftegeofizika (“Tatneftegeofizika”), which provides services in the discovery and exploration of oil and natural gas reserves in Tatarstan, Siberia and outside of Russia (including Egypt, India, Kazakhstan, Libya and Turkey). The Tatarstan government holds a Golden Share in Tatneftegeofizaka that permits it to veto certain board and shareholder decisions and appoint representatives to the company’s management bodies.

 

    OAO Nizhnekamsk Industrial Carbon Plant. We own 77.1% of Nizhnekamsk Industrial Carbon Plant. Nizhnekamskshina uses the carbon plant products as raw materials, and this acquisition is part of our efforts to create a vertically integrated group.

 

    OAO Nizhnekamsk Oil Refinery. We hold 63% of OAO Nizhnekamsk Oil Refinery, which operates the production facilities at the Nizhnekamsk oil refinery owned by us and other shareholders. See “—Refining and Marketing—Refined Products” under this Item and “Item 3—Key Information—Risk Factors—A dispute with one of our business partners over the lease of a refining unit at the Nizhnekamsk oil refinery may have a material adverse effect on the value of the refining units owned by us and on our ability to process crude oil in Tatarstan.”

 

    ZAO Yarpolymermash-Tatneft. In 2001, we formed ZAO Yarpolymermash-Tatneft, of which we currently own 51%, based on the assets of the Yaroslavl Polymer Machine Plant, to manufacture equipment for processing materials for tire production.

 

    ZAO Ukrtatnafta. We own 8.6% of ZAO Ukrtatnafta (“Ukrtatnafta”). Ukrtatnafta holds a 100% interest in the Kremenchug refinery in Ukraine, one of the largest refineries for high sulfur crude oil in the CIS. The Tatarstan government holds 28.8% of Ukrtatnafta.

 

STRATEGY

 

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, (iii) expanding and diversifying our reserves base outside Tatarstan and (iv) improving our corporate governance, 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. As part of this strategy we are engaged in expansion and upgrade of the oil refinery in Nizhnekamsk. The Phase I Base Complex of the refinery was brought on stream in 2002, and we intend to further expand and upgrade this facility in the future. Once the refinery begins to operate at its full rated capacity, this is expected to decrease our dependence on refineries outside of Tatarstan and will enable us to produce more environmentally friendly oil products from high sulfur content crude oil. However, the Nizhnekamsk Oil Refinery has been involved in a dispute with TAIF over the lease of a refining unit owned by TAIF. For further discussion see “Item 3—Risk Factors—Risks Relating to the

 

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Company—A dispute with one of our business partners over the lease of a refining unit at the Nizhnekamsk oil refinery may have a material adverse affect on the value of the refining units owned by us and on our ability to process crude oil in Tatarstan.” We have also formed OAO TKNK, a joint venture with OAO Nizhnekamskneftekhim, OAO Svyazinvestneftekhim and LG International Corp. to carry out a feasibility study and construction of an oil refining and petrochemicals complex in Tatarstan. In May 2004, Tatneft provided TKNK with a U.S.$4.3 million loan for financing feasibility studies and services as part of developing the oil refining and petrochemical complex. In addition, Tatneft has invested RR40 million into the first phase of the oil refining plant construction. In accordance with preliminary feasibility studies of the oil refining plant construction prepared by LG, total necessary investment will amount to approximately U.S.$1.8 billion. However, at this stage we cannot predict the level of additional capital investment that may be required from us in connection with this project. See “—History and Development.”

 

In addition to investing in our refining activities, we own a 76.0% stake in Nizhnekamskshina, one of the largest tire-producing factories in the Russian Federation, located in the city of Nizhnekamsk. We also own a 83.8% 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. We also constructed a plant in Nizhnekamsk for the production of synthetic lubricants for engines and machinery. To increase the efficiency of our petrochemicals operations, in 2002 we created the management company 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, optimize costs and improve management efficiencies, in 2002 we merged our natural gas production, refining and transportation assets into one division, Tatneftegaspererabotka, and established OOO Tatneft-Bureniye, a drilling management company. See “—Corporate Reorganization” under this Item.

 

We are also currently expanding the Tatneft-branded network of retail gasoline sales outlets both inside and outside Tatarstan, particularly in Moscow, St. Petersburg and the Moscow, Chuvashiya, Ulyanovsk, Arkhangelsk, Vladimir and Leningrad regions in Russia, as well as in Ukraine. We are conducting this expansion both directly and through our subsidiaries and affiliates. As of January 1, 2005, there were 402 Tatneft-branded gas stations in Russia and 145 in Ukraine.

 

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. 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 are able to provide the necessary financing. We also are actively pursuing opportunities to use new technologies in order to maximize the recovery from our existing reserves base. See “Item 4—Information on the Company—Exploration and Production.”

 

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, Astrakhan, 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, Syria, Libya, Oman and Sudan, where both we and Russia have strong historical ties, subject to compliance with applicable international sanctions regimes.

 

Improving our corporate governance. We are seeking to improve our corporate governance in accordance with Russian and international standards, such as the Principles of Corporate Governance of the Organization for European Cooperation and Development and the model Code of Corporate Conduct approved by the Russian government. Among the areas we are trying to improve are the transparency of financial activity, informational transparency, responsibility to shareholders and corporate social responsibility. Recent steps towards improving our corporate governance have included establishing the Audit Committee, Disclosure Committee and Corporate Governance Committee, introduction of SAP R/3 financial information system, diversification of production, fulfillment of cost reduction programs and divestiture of non-core assets.

 

However, Ernst & Young, our independent auditor, and PricewaterhouseCoopers, our independent auditor until 2003, have identified weaknesses in our control environment. For further information regarding weaknesses in our control environment, see “Item 3— Risk Factors—Risks Relating to the Company—Our independent registered public accounting firm reported material weaknesses in our internal controls and we may not be able to remedy these material weaknesses or prevent future weaknesses” and “Item 15—Controls and Procedures.”

 

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OVERVIEW OF THE RUSSIAN OIL INDUSTRY

 

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.

 

Background

 

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. Initially the major Russian oil companies 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 Surgutneftegaz, Sidanco, Sibneft and YUKOS.

 

The Russian government continued to privatize Russian oil companies that remained under its control. 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 Belarus 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 in December 2002 to the same consortium. The Russian government sold its remaining 7.6% stake in LUKOIL in a privatization auction to ConocoPhillips in September 2004.

 

The Russian oil industry has also recently undergone a wave of consolidation. In February 2003, Alfa Group and Access-Renova (together, TNK’s, Onako’s and Sidanko’s majority shareholders) and BP announced plans to combine their oil and natural gas operations in Russia and Ukraine, and this transaction was completed in August 2003. The new holding company, TNK-BP, created on the basis of the combined assets of TNK, ONAKO, Sidanco and BP’s Russian assets (excluding BP’s assets in the Sakhalin Islands), is owned 50% each by BP and the combined Alfa-Access-Renova and is the third-largest oil company in Russia by reserves and production. Alfa-Access-Renova and BP subsequently reached an agreement to contribute TNK’s 50% stake in Slavneft to TNK-BP, and announced the completion of this transaction in January 2004. In April 2003, YUKOS and Sibneft announced that their respective shareholders had reached an agreement in principle on effecting a merger and this transaction was completed with effect in October 2003. However, pursuant to claims for back taxes against YUKOS by the Russian government, the merger has since been reversed. In December 2004, the Russian government auctioned a 76.8% stake in Yuganskneftegaz, YUKOS’ largest production subsidiary, in partial settlement of back tax claims against YUKOS, to the state-owned oil company Rosneft.

 

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 through mergers or other forms of combination.

 

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Production

 

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 (2,172.5 mmbbl). In 1998, production decreased by approximately 0.8% to 303.2 million tons (2,159.7 mmbbl). In 1999, Russia produced 305.0 million tons (2,172.5 mmbbl), an increase of 0.6% over 1998. In 2000, Russia produced approximately 312.7 million tons (2,227.4 mmbbl) of crude oil, a 2.5% increase over 1999 and in 2001, Russia produced approximately 336.9 million tons (2,399.7 mmbbl) of crude oil, a 7.7% increase over 2000. In 2002, Russia produced approximately 379.6 million tons (2,703.9 mmbbl) of crude oil, a 12.7% increase over 2001, and in 2003 Russia produced 421.4 million tons (3,001.6 mmbbl) of crude oil, an 11.0% increase over 2002. Russia produced 458.8 million tons (3,268.1 mmbbl) of crude oil in 2004, a further 8.9% increase over 2003. The rise in production in recent years has 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 2004, 2003, 2002 and 2001:

 

Company


   2004

    2003(2)

    2002(2)

    2001(2)

 
     (millions of tons)  

YUKOS(1)

   85.7     80.7     69.9     58.1  

LUKOIL

   84.1     78.9     75.5     62.9  

TNK-BP(4)(5)

   70.3     43.0     37.5 (3)   41.3 (3)

Surgutneftegaz

   59.6     54.0     49.2     44.0  

Sibneft(5)

   34.0     31.4     26.3     20.3  

Tatneft

   25.4 (6)   24.9 (6)   24.9 (6)   24.9 (6)

Sidanco

   —   (7)   18.6     16.3     9.0  

Slavneft

   22.0     18.1     16.2     14.8  

Rosneft

   21.6     17.8     16.1     14.8  

Bashneft

   12.0     12.0     12.0     11.9  

Source: Interfax Petroleum Report, except for Tatneft.

(1) Includes production at Yuganskneftegaz.
(2) Totals exclude the share of production of affiliated joint ventures.
(3) Including the production of Onako.
(4) Data for periods prior to 2004 is for TNK only.
(5) Excludes production attributable to Slavneft.
(6) Including production attributable to our joint venture Tatoilgas, which is consolidated into our consolidated financial statements, of approximately 257,198 tons, 265,301 tons, 291,000 tons and 243,190 tons in the years ended December 31, 2004, 2003, 2002 and 2001, respectively.
(7) Included within TNK-BP starting from 2004.

 

Domestic Russian Crude Oil Prices

 

Domestic oil prices in Russia do not reflect world levels or international supply and demand fundamentals. Constraints on exports have 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, further restricting the increase in the domestic price of crude oil. 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.

 

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

 

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operations of Russian oil companies. The increase in world and domestic oil prices in the second part of 1999 significantly helped Russian oil companies to increase profitability. World oil prices have increased significantly since January 1999, when the price was approximately U.S.$10.33 per barrel. According to the International Energy Agency, the average prices of Brent crude, an international benchmark oil, for the four years ended December 31, 2004, 2003, 2002 and 2001, were approximately U.S.$38.22, U.S.$28.83, U.S.$25.02 and U.S.$24.44 per barrel, respectively. The price of Brent crude was U.S.$47.90 at May 19, 2005. Crude oil prices increased during 2004 over the level at the end of 2003 as a result of export restrictions imposed by OPEC and certain other crude oil producing nations, including Russia, increased demand and uncertainty with respect to the situation in Iraq and the Middle East more generally. Domestic prices have also risen from U.S.$30 to U.S.$35 per ton in January 1999 to an average of U.S.$91.60 per ton for 2001, declining in 2002 to an average of U.S.$83.70. Domestic prices were an average of RR1,692 per ton (U.S.$57.45 as of the exchange rate prevalent on December 31, 2003) in 2003 and RR2,439 per ton (U.S.$82.82 as of the exchange rate prevalent on December 31, 2003) in 2004.

 

Crude Oil Exports

 

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 only to oil production levels, as was previously the case. 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 “—Regulation of the Russian Oil Industry—Oil and Petroleum Products Transportation Regime.”

 

In 2003, Russia exported approximately 155.0 million tons of crude oil to non-CIS countries, a 12.4% increase from 2002. In 2004, Russia exported approximately 200.9 million tons of crude oil to non-CIS countries, a 29.6% increase from 2003. The following table shows approximate export volumes of crude oil for deliveries to non-CIS countries by certain Russian oil companies in 2004, 2003, 2002 and 2001:

 

Company


   2004

    2003(2)

   2002(2)

   2001(2)

     (millions of tons)

YUKOS(1)

   34.0     29.6    25.6    23.5

LUKOIL

   33.0     27.1    25.9    22.5

TNK –BP(3)

   30.8     18.8    14.8    16.3

Surgutneftegaz

   20.9     18.3    17.5    16.2

Sibneft

   13.4     11.6    10.5    7.3

Tatneft

   13.0     13.1    10.9    9.2

Sidanco

   —   (4)   8.3    5.2    2.8

Slavneft

   8.2     5.8    5.5    5.2

Rosneft

   6.8     6.4    6.1    5.5

Bashneft

   3.9     3.9    4.1    4.0

Source: Interfax Petroleum Report, except for Tatneft.

(1) Includes production at Yuganskneftegaz.
(2) These totals exclude production of affiliated joint ventures and oil purchased from third parties.
(3) Data for periods prior to 2004 is for TNK only.
(4) Included within TNK-BP starting from 2004.

 

Refining

 

The current refining market in Russia is characterized by overcapacity. Refinery utilization since 1995 has remained at approximately 60%. Primary oil refining was 178.4 million tons in 2001, 174.8 million tons in 2002, 190.0 million tons in 2003 and 195.0 million tons in 2004. This generally increasing trend reflects the overall rise in the demand of the Russian economy for refined products and the effects of the higher levels of production combined with the limited export capacity.

 

Regulation of the Russian Oil Industry

 

General

 

Regulation of the oil industry in Russia is still evolving, with federal, regional and local authorities each promulgating rules.

 

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At the federal level, the Ministry for Industry and Energy is the principal authority that sets governmental policy for the industry and coordinates the activities of oil companies. The Federal Tariff Service and the Ministry of Industry and Energy address issues in the oil industry related to access to Transneft’s truck oil pipelines and tariffs. The Ministry of Natural Resources is the principal authority that sets government policy for the use of subsoil and licenses the use of subsoil resources, as described below. The Federal Service for the Supervision of the Use of Natural Resources oversees compliance with the terms and conditions of licenses issued by the Ministry of Natural Resources and environmental legislation 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. 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.

 

Licensing

 

The licensing regime for use of subsoil for geological research, exploration and production of mineral resources is established primarily by the Subsoil Law, referred to in this section as the Subsoil Law. 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.

 

Important amendments to the Subsoil Law, passed in August 2004, significantly changed the procedure for awarding exploration and production licenses, in particular abolishing the joint grant of licenses by federal and regional authorities. Under the 2004 amendments, production licenses and combined exploration and production licenses are awarded by tender or auction conducted by the Federal Agency for Subsoil Use. While the auction or tender commission includes a representative of the relevant region, the separate approval of regional authorities is no longer required in order to issue subsoil licenses. 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. Licenses for geological exploration and production may also be issued without the holding of an auction or tender by the decision of the federal authorities to holders of exploration licenses that discover mineral resource deposits through exploration work conducted at their own expense.

 

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.

 

Licenses generally require the license holder to make various commitments, including:

 

    extracting annually an agreed target amount of reserves;

 

    conducting agreed drilling and other exploratory and development activities;

 

    protecting the ecology in the fields from damage;

 

    providing geological information and data to the relevant authorities;

 

    submitting on a regular basis formal progress reports to regional authorities; and

 

    paying certain royalty and other obligatory payments when due.

 

Article 10 of the Subsoil Law also provides that a license to use a field must be extended by the relevant authorities at the initiative of the license holder if the extension is necessary to finish production in the field, provided that the licensee has not violated the terms of the license. We believe that our existing production licenses will be extended at or prior to their scheduled expiration and we are currently in the process of requesting extensions for our most significant fields, including Romashkinskoye, our largest field. 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 extend the license upon the expiration of its current period. See “Item 4—Information on the Company—Exploration and Production.”

 

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The Federal Service for the Supervision of the Use of Natural Resources, or its regional division, oversees compliance with the terms of licenses. A licensee can be fined for failing to comply with a subsoil production license and a subsoil production license can be revoked, suspended or limited in certain circumstances, including:

 

    breach or violation by the licensee of material terms and conditions of the license;

 

    repeated violation by the licensee of the subsoil regulations;

 

    failure by the licensee to commence operations within a required period of time or to produce required volumes, both as specified in the license;

 

    the occurrence of an emergency situation;

 

    the emergence of a direct threat to the life or health of people working or residing in the area affected by the operations under the license;

 

    liquidation of the licensee; and

 

    non-submission of reporting data in accordance with the legislation.

 

In the case of expiration of the term of a license or early termination of subsoil use, all oil and natural gas facilities in the relevant licensing area, including underground facilities, must be removed or properly abandoned. In accordance with removal and abandonment regulations, all mining facilities, including oil and natural gas wells, must be maintained at a level that is safe for the population, the environment, buildings and other facilities. Abandonment procedures must also secure the conservation of the relevant oil and natural gas field, mining facilities and wells. Our estimates of future abandonment costs consider present regulatory or license requirements and are based upon our management’s experience of the costs and requirements of such activities. Most of these costs are not expected to be incurred until several years, or decades, in the future and will be funded from our general resources at the time of removal. For a further discussion of our treatment of our asset removal obligations see Note 22 to our audited consolidated financial statements included in this annual report.

 

Certain activities relating to the oil and gas industry require specific licenses. These include the construction, operation, repair, manufacture and installation of oil and natural gas producing equipment and refining facilities, the storage of oil and natural gas and their respective products, the processing and transportation of hydrocarbons and hydrocarbon products and the construction and manufacturing of buildings and other structures connected with oil and natural gas activities. The Ministry of Industry and Energy and the Federal Service for Environmental, Technology and Nuclear Supervision, the designated government agency, are authorized to issue these specific licenses.

 

Land Use Permits

 

In addition to a subsoil production license, permission to use surface land within the specified licensed area is necessary. A majority of land plots in the Russian Federation are owned by federal, regional or municipal authorities which, through public auctions or tenders or through private negotiations, can sell, lease or grant other use rights to the land to third parties.

 

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.

 

System of Payments for the Use of Subsoil

 

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:

 

    one-time payments in cases specified in the license;

 

    regular payments for subsoil use, such as rent payments for the right to conduct prospecting/appraising and exploration work;

 

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    payments to the state for geological subsoil information;

 

    fees for the right to participate in tenders and auctions; and

 

    fees for the issuance of licenses.

 

The rates at which payments are to be levied are usually established in a license by federal authorities within a range of minimum and maximum rates established by the Subsoil Law.

 

Production Sharing Agreements

 

Petroleum operations carried out under production sharing agreements, or PSAs, are governed by separate laws. A PSA is a contract between the Russian government or its authorized body, acting on behalf of the Russian Federation, 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 are not to 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.

 

We do not participate in any PSA arrangements.

 

Oil and Petroleum Products Transportation Regime

 

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.

 

Over 90% of the oil produced in Russia is transported through Transneft, the state-owned monopoly owner and operator of Russia’s trunk crude oil and export pipelines. 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 Tariff Service is authorized to periodically review and set 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 the Czech Republic, Germany, Hungary, Poland 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 Ministry of Industry and Energy, 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 (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 content) crude compensate the shippers of higher-quality crude oil for deterioration in crude quality due to blending. Although the introduction of a blending compensation system, often referred to as a “quality bank,” is currently under discussion between Transneft and the Russian government, these proposals are generally met with aggressive resistance by 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.

 

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Imports and Exports

 

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, the predecessor of the Ministry of Industry and Energy, 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 existing crude oil prices.

 

Environmental Protection

 

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 other federal, and regional authorities. Fees are assessed both for pollution within the limits agreed of emissions and effluents and for pollution in excess of these limits. There are additional fines for certain other breaches of environmental regulations. The Environmental Protection Law does not stipulate precise requirements for the clean-up of pollution, although it does contain an obligation to provide full compensation for all environmental losses caused by pollution. The “pay-to-pollute” regime is also governed by Government Decree No. 344, On Rates of Payments for Pollutant Emissions into the Air by Stationary and Mobile Sources, Pollutant disposals into Surface and Underground Waters, Disposal of Production and Consumption Waste, dated June 12, 2003.

 

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. Furthermore, the implementation of the Kyoto Protocol may impose new and/or additional rules or more stringent environmental norms. Such requirements may require additional capital expenditures or modifications in operating practices. The impact on us will depend on, among other factors, the base level against which permissible levels of emissions are to be measured and the allocation of quotas for such emissions, which is currently uncertain.

 

Current System of Oil-Related Taxes and Payments

 

In general, the Russian oil industry is subject to the same burdensome tax regime as other industries. In addition, the oil companies are subject to industry-specific taxes. As noted above under “—Regulation of the Russian Oil Industry—Oil and Petroleum Products Transportation Regime,” 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.

 

The Unified Natural Resources Production Tax

 

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 the unified natural resources production tax, a tax on the extraction of commercial minerals.

 

For the year ended December 31, 2004, the base tax rate for the unified natural resources production tax was set at RR347 per ton of crude oil produced, and was increased to RR419 per ton of crude oil produced effective from January 1, 2005, and is adjusted monthly 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 U.S.$9.00 per barrel (U.S.$8.00 per barrel prior to January 1, 2005). For the year ended December 31, 2003, the average effective rate for the unified natural resources production tax, based on the Urals blend market price and ruble exchange rates, was RR801 per ton of crude oil produced. At December 31, 2003, the effective rate for the unified natural resources production tax was RR808 per ton. From January 1, 2007, the unified natural resources production tax rate is set by law at 16.5% of the value of extracted crude oil, calculated either by reference to actual sale prices of natural resources or the deemed value of natural resources net of VAT less export duties, transportation expenses and certain other distribution expenses.

 

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Recent articles in the press have indicated that the Russian government is considering introducing a differentiated rate for the unified natural resources production tax, with the effect that oil companies with more mature fields would pay a lower rate than those with better quality reserve deposits. The introduction of a differentiated unified natural resources production tax may benefit us because the majority of our fields are considered mature. However, we have no information regarding the details of such a differentiated tax, or indeed if any such differentiation will actually be introduced. Consequently, at this stage we cannot speculate as to the impact that a differentiated tax rate would have on our operations.

 

Oil-related Export Duties

 

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 out in the amended Law on Customs Tariffs are as follows:

 

Average Price for Urals Crude Oil Blend(1)


  

Export customs duties


Up to U.S.$109.50 per ton (U.S.$15.37 per barrel)    0%

U.S.$109.50 to U.S.$146 per ton

(U.S.$15.37 to U.S.$20.50 per barrel).

   35% of the difference between the actual price (per ton) and U.S.$109.50

U.S.$146 to U.S.$182.50 per ton

(U.S.$20.50 to U.S.$25.62 per barrel)

   U.S.$12.78 plus 45%(2) of the difference between the actual price (per ton) and U.S.$146

Greater than U.S.$182.50 per ton

(U.S.$25.62 per barrel).

   U.S.$29.2 plus 65%(3) of the difference between the actual price (per ton) and U.S.$182.50

(1) The Urals crude oil blend price is calculated as the price for Urals blend on world markets (Mediterranean and Rotterdam) for the two months immediately preceding the current two-month period.
(2) This rate was 35% prior to June 2004.
(3) This rate was 40% prior to June 2004.

 

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 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) per square kilometer; and (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) per 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.

 

Current Excise Tax on Oil Products

 

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. Effective January 1, 2001, this Fuel Sales Tax has been abolished, and excise tax became applicable to all of the above products. The current excise tax rates on oil products are as follows:

 

Oil Product


   Rate per ton
(RR)


Gasoline with octane numbers not exceeding “80”

   2,460

Gasoline with octane numbers exceeding “80”

   3,360

Diesel fuel

   1,000

Motor oil

   2,732

 

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EXPLORATION AND PRODUCTION

 

Reserves and Fields

 

The following tables present our net proved reserves at January 1, 2005, 2004, 2003 and 2002. Net reserves are defined as the allocated portion of the gross reserves to a particular economic interest in a property. Unless otherwise noted, all presentations of reserves in the following section are with respect to net reserves.

 

Our oil and gas fields are located principally in Tatarstan. We obtain licenses from the governmental authorities to explore and produce oil and gas from these fields. Most of our existing production licenses expire from 2013 to 2019, and the license for our largest field, Romashkinskoye, expires in 2013. The economic lives of our licensed fields extend significantly beyond the license expiration dates. Under Russian law, we are entitled to renew our licenses to the end of the economic lives of the fields, provided certain conditions are met. Article 10 of the Subsoil Law provides that a license to use a field “shall be” extended at its scheduled termination at the initiative of the subsoil user if necessary to finish production in the field, provided that there are no violations of the conditions of the license. The legislative history of Article 10 indicates that the term “shall” replaced the term “may” in August 2004, clarifying that the subsoil user has an absolute right to extend the license term so long as it has not violated the conditions of the license. We have received a letter, dated April 7, 2005, from the Federal Agency for Subsoil Use under the Ministry of Natural Resources of the Russian Federation confirming that, to date, it has not identified any violations of the terms of our licenses that could prevent their extension and that, based on approved development plans and in accordance with the Subsoil Law, our licenses will be extended at our request. Our right to extend our licenses is, however, dependent on our continuing to comply with the terms of our licenses, and we have the ability and intent to do so. We plan to request the extension of our licenses and are currently in the process of requesting extensions for our most significant fields, including Romashkinksoye. Our current production plans are based on the assumption, which we consider to be reasonably certain, that we will be able to extend all of our existing licenses. These plans have been designed on the basis that we will be producing crude oil through the economic lives of our fields and not with a view to exploiting our reserves to maximum effect only through the license expiration dates.

 

Miller & Lents, our independent oil and gas consultants, have confirmed our view that it is “reasonably certain” that we will be allowed to produce oil from our reserves after the expiration of our existing production licenses and until the end of the economic lives of the fields. “Reasonable certainty” is the applicable standard for defining proved reserves under the SEC’s Regulation S-X, Rule 4-10. Accordingly, we have included in proved reserves in this annual report on Form 20-F all reserves that otherwise meet the standards for being characterized as “proved” and that we estimate we can produce through the economic lives of our licensed fields.

 

The SEC staff have indicated that proved reserves generally should be limited to those that can be produced through the license expiration date unless there is a long and clear track record which supports the conclusion that the extension of the license will be granted as a matter of course. We believe that the extension of our licenses is a matter of course as fully described above. To assist the reader in understanding the proved oil reserves that will be produced during the existing license periods and those that will be produced during the period of the expected license extension, we have presented reserves information in this annual report on Form 20-F for each of these two periods.

 

For a discussion of the accounting treatment of depletion, depreciation and amortization of our oil producing assets, see “Item 5—Operating and Financial Review and Prospects—Critical Accounting Policies and Estimates” and Note 3 and Note 11 to our audited consolidated financial statements included in this annual report.

 

Proved Reserves Through the Economic Lives of Our Licensed Fields

 

     As of January 1,(1)

     2005

   2004

   2003

   2002

Reserve Category


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Proved Developed Reserves

   798.4    5,687.1    783.7    5,582.4    774.8    5,518.6    706.8    5,034.8

Proved Undeveloped Reserves

   38.7    275.5    52.8    376.6    63.6    453.4    58.9    419.9
    
  
  
  
  
  
  
  

Total Proved Reserves

   837.1    5,962.6    836.6    5,959.0    838.4    5,972.0    765.7    5,454.7
    
  
  
  
  
  
  
  

 

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Proved Reserves Through Current License Expirations

 

     As of January 1,(1)

     2005

   2004

   2003

   2002

Reserve Category


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Proved Developed Reserves

   202.6    1,442.9    277.8    1,978.6    308.0    2,194.1    328.3    2,338.8

Proved Undeveloped Reserves

   7.9    56.2    19.2    137.0    23.5    167.5    24.3    173.1
    
  
  
  
  
  
  
  

Total Proved Reserves

   210.5    1,499.1    297.0    2,115.6    331.5    2,361.6    352.6    2,511.9
    
  
  
  
  
  
  
  

 

The following tables present, by major field, our net proved reserves through the economic lives of our licensed fields, at January 1, 2005, 2004, 2003 and 2002.

 

     Proved Reserves Through the Economic Lives of our Licensed Fields(1)(2)

     2005

   2004

   2003

   2002

Field


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Romashkinskoye

   457.2    3,256.5    471.0    3,354.9    455.4    3,243.6    432.1    3,078.6

Novo-Yelkhovskoye

   81.6    581.4    72.3    514.8    69.5    494.7    67.3    479.1

Bavlinskoye

   48.9    348.4    52.5    374.1    51.5    366.6    44.9    319.9

Sabanchinskoye

   15.7    111.5    15.2    108.9    15.6    110.8    15.4    109.8

Others

   233.7    1,664.7    225.5    1,606.3    246.6    1,756.2    206.0    1,467.3
    
  
  
  
  
  
  
  

Total

   837.1    5,962.5    836.6    5,959.0    838.4    5,972.0    765.7    5,454.7
    
  
  
  
  
  
  
  
     Proved Developed Reserves Through the Economic Lives of our Licensed
Fields(1)(2)


     2005

   2004

   2003

   2002

Field


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Romashkinskoye

   452.1    3,220.5    465.1    3,312.7    446.2    3,178.4    426.7    3,039.3

Novo-Yelkhovskoye

   80.9    576.2    71.7    510.6    68.8    490.3    66.6    474.1

Bavlinskoye

   40.7    290.1    39.1    278.2    35.1    250.1    28.5    202.8

Sabanchinskoye

   14.8    105.7    14.3    102.1    14.6    104.0    14.2    101.0

Others

   209.8    1,494.5    193.6    1,378.9    210.0    1,495.8    171.0    1217.6
    
  
  
  
  
  
  
  

Total

   798.4    5,687.1    783.7    5,582.4    774.8    5,518.6    707.0    5,034.8
    
  
  
  
  
  
  
  
     Proved Undeveloped Reserves Through the Economic Lives of our Licensed
Fields(1)(2)


     2005

   2004

   2003

   2002

Field


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Romashkinskoye

   5.1    36.0    5.9    42.2    9.2    65.2    5.5    39.3

Novo-Yelkhovskoye

   0.7    5.1    0.6    4.2    0.6    4.4    0.7    5.0

Bavlinskoye

   8.2    58.3    13.5    95.9    16.4    116.5    16.4    117.1

Sabanchinskoye

   0.8    5.9    0.95    6.8    1.0    6.8    1.2    8.8

Others

   23.9    170.2    31.9    227.4    36.6    260.4    35.1    249.7
    
  
  
  
  
  
  
  

Total

   38.8    275.5    52.9    376.6    63.6    453.4    58.9    419.9
    
  
  
  
  
  
  
  

 

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The following tables present, by major field, our net proved reserves for the periods through the current license expiration dates, at January 1, 2005, 2004, 2003 and 2002.

 

     Proved Reserves Through the Current License Expirations(1)(2)

     2005

   2004

   2003

   2002

Field


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Romashkinskoye

   117.3    835.4    161.3    1,149.1    169.3    1,205.7    183.1    1,304.0

Novo-Yelkhovskoye

   18.1    128.6    27.6    196.6    30.5    217.0    34.8    248.2

Bavlinskoye

   8.4    59.9    18.3    130.4    18.6    132.7    19.4    138.5

Sabanchinskoye

   5.2    36.8    5.8    41.6    6.4    45.8    7.0    49.7

Others

   61.5    438.3    83.9    597.7    106.8    760.4    108.3    771.4
    
  
  
  
  
  
  
  

Total

   210.5    1,499.1    297.0    2,115.6    331.5    2,361.6    352.6    2,511.9
    
  
  
  
  
  
  
  
     Proved Developed Reserves Through the Current License Expirations(1)(2)

     2005

   2004

   2003

   2002

Field


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Romashkinskoye

   115.7    824.4    158.8    1,131.2    165.4    1,178.3    180.3    1,284.6

Novo-Yelkhovskoye

   17.8    126.7    27.2    193.9    30.0    213.8    34.3    244.3

Bavlinskoye

   6.6    46.8    13.7    97.6    13.0    92.4    13.1    93.0

Sabanchinskoye

   4.9    35.1    5.4    38.5    6.1    43.1    6.4    45.8

Others

   57.5    409.8    72.6    517.3    93.6    666.5    94.2    671.0
    
  
  
  
  
  
  
  

Total

   202.6    1,442.9    277.8    1,978.6    308.0    2,194.1    328.3    2,338.8
    
  
  
  
  
  
  
  
     Proved Undeveloped Reserves Through the Current License Expirations(1)(2)

     2005

   2004

   2003

   2002

Field


   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

   Tons

   Bbls

     (millions of units)

Romashkinskoye

   1.5    11.0    2.5    17.9    3.8    27.4    2.7    19.4

Novo-Yelkhovskoye

   0.3    1.9    0.4    2.7    0.4    3.2    0.5    3.9

Bavlinskoye

   1.8    13.1    4.6    32.8    5.7    40.3    6.4    45.5

Sabanchinskoye

   0.2    1.7    0.4    3.1    0.4    2.7    0.5    3.9

Others

   4.0    28.5    11.3    80.4    13.2    93.9    14.1    100.4
    
  
  
  
  
  
  
  

Total

   7.9    56.2    19.2    137.0    23.5    167.5    24.3    173.1
    
  
  
  
  
  
  
  

(1) Columns may not total due to rounding.
(2) For convenience, throughout this annual report 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. Translations in the these tables may differ, however, as the crude oil reserves in the reservoirs within specific fields may have a different weighted density than that of our total average crude oil reserves.

 

In the discussion that follows we focus on our proved reserves that we estimate we can produce through the economic lives of our licensed fields. According to appraisals of our reserves performed by the engineering firm Miller and Lents, as of January 1, 2004 and 2005, our reserves base had decreased by 0.1% in 2003 and increased by 0.06% in 2004, bringing the total volume of proved developed and undeveloped reserves to 836.6 million tons (5,959.0 mmbbl) and 837.1 million tons (5,962.5 mmbbl) as of January 1, 2004 and 2005, respectively. We had 783.7 million tons (5,582.4 mmbbl) and 798.4 million tons (5,687.1 mmbbl) of Proved Developed Reserves at January 1, 2004 and 2005, respectively, of which Proved Developed Producing Reserves accounted for approximately 493.5 million tons (3,515.3 mmbbl) or 59% of the total proved reserves and 505.1 million tons (3,597.8 mmbbl) or 60% of the total proved reserves. The slight decline in our reserves during 2003 is primarily attributable to fluctuations in price and cost levels that impact the economic viability of recovering oil from certain of our fields. Our reserves remained relatively stable in 2004 as compared to 2003. 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 2003 and 2004, approximately 42.5% and 47.5%, respectively, 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 83% when produced, meaning that 83% 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.

 

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We are expanding our reserves outside Tatarstan into other regions of Russia, including Kalmykia, the Samara Region and the Orenburg Region. In May 2000, in conjunction with the regional oil company Kalmneft, we established Kalmtatneft, of which we owned 50% until 2005. Tatneft or one of our subsidiaries currently hold licenses for exploration in the Ulyanovsk region, the Chuvash Republic, the Samara Region and the Nenetsk Autonomous District and a joint exploration and production license for the Matrosovskoye oil field, located in both Tatarstan and the Orenburg region. In December 2002, the area of the initial subsoil license for the Matrosovkoye oil field was expanded due to the inclusion of a deposit in the Orenburg Region, which was previously explored under a separate subsoil license. See “Item 5—Operating and Financial Review—Licenses.”

 

We also have plans to acquire exploration, development or production rights in Iran, Iraq and Syria. 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 included 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 do not currently engage in any significant activities in Iraq.

 

We have opened a representative office in Iran and in February 2005 the government of Tatarstan and the government of Iran concluded an agreement pursuant to which we are expecting to register a joint venture with an Iranian entity in order to participate in various projects in Iran, including tenders for the development of oil fields. The terms of our participation in this venture have not yet been finalized. In November 2003, the Syrian government selected us to explore and develop a production block in eastern Syria, and in March 2005 we concluded an agreement with the government of Syria and the Syrian Oil Company according to which we are to explore for oil in this area and to produce oil on the basis of a 25-year production sharing agreement. We are also planning to participate in future tenders for the development of oil fields in Syria. We believe that our operations in Iran and Syria have been conducted in full compliance with applicable Russian, U.S. and international law.

 

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. The decision to remit any funds to us and the amount of any funds so remitted was at the discretion of the Tatarstan government. In 2001, we received back approximately RR563.5 million, or 9.6% of our 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. Moreover, we do not expect to receive any additional funds in connection with our contributions to the Restoration Fund made in prior periods.

 

High Sulfur Content Crude Oil

 

High sulfur content crude oil, defined as crude oil containing more than 1.8% of 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, 42.5% in 2003 and 43.1% in 2004 as a result of renewed shipments to Kremenchug starting in 1995, the establishment of new arrangements with refineries in 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.

 

Production

 

Overview

 

In the years ended December 31, 2004 and 2003, we produced approximately 25.4 million tons (180.9 mmbbl) and 24.9 million tons (177.3 mmbbl) of crude oil, respectively, not including our share of production by TATEX, a joint venture that is accounted for on an equity basis. This represented approximately 5.5% and 5.9% of the total crude oil production in Russia in 2004 and 2003, making Tatneft the sixth largest crude oil producer in Russia.

 

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Crude Oil Production

(in millions)

 

Year Ended December 31,


2004(1)(2)


  

2003(1)(2)


  

2002(1)(2)


  

2001(1)


Tons


  

Barrels


  

Tons


  

Barrels


  

Tons


  

Barrels


  

Tons


  

Barrels


25.4

   181.6    24.9    177.3    24.9    177.3    24.9    177.3

(1) Includes production attributable to our joint venture Tatoilgas, which is consolidated with our results, of approximately 257,198 tons (1.8 mmbbl), 265,301 tons (1.89 mmbbl), 291,000 tons (2.07 mmbbl) and 243,190 tons (1.73 mmbbl) in the years ended December 31, 2004, 2003, 2002 and 2001, respectively.
(2) Includes approximately 173,495 tons (1.2 mmbbl), 169,193 tons (1.2 mmbbl) and 172,000 tons (1.2 mmbbl) in the years ended December 31, 2004, 2003 and 2002 respectively, produced at the third-block of the Pavlovskoye area of the Romashkinskoye oil field operated by Ritek-Vnedreniye under a joint operations agreement with us.

 

Our largest oil field is the Romashkinskoye field, from which we produced approximately 14.5 million tons (103.5 mmbbl) of crude oil in 2003 and 14.8 million tons (105.4 mmbbl) in 2004. We produced approximately the same quantities of crude oil from the field in prior years, 14.4 million tons (102.6 mmbbl) in 2002 and 14.6 million tons (103.2 mmbbl) in 2001. The field was discovered in 1948 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 oil in 2003 and 2.4 million tons (17.1 mmbbl) in 2004. We produced approximately 2.4 million tons (17.1 mmbbl) of crude oil from the field in each of 2002 and 2001. 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. The field reached peak production levels in 1957. Production from the field was approximately 809,764 tons (5.8 mmbbl) of crude oil in 2003 and approximately 861,100 tons (6.1 mmbbl) of crude oil in 2004. We produced approximately 779,600 tons (5.7 mmbbl) in 2002 and approximately 773,000 tons (5.5 mmbbl) in 2001 from the field. 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 to 25 million tons per year. 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:

 

    a more favorable Tatarstan tax regime through the end of 2000, providing increased economic incentives to bring a number of non-operational wells into production;

 

    the impact of our well rehabilitation program; and

 

    employment of secondary and tertiary recovery techniques to increase well productivity.

 

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:

 

    a return of certain amounts of that portion of the royalties for the use of the subsoil that was payable to Tatarstan; and

 

    an exemption from property taxes on related wells and fixed assets, including, from January 1, 1998, amounts that had previously been payable to local authorities.

 

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

 

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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. In 2002, the Tatarstan government set for us the minimum rates permitted by Russian legislation for payments for the right to explore and appraise oil fields and prospect for natural resources. However, effective from January 1, 2003, the Tatarstan government raised the rates to the maximum level permitted by the legislation. In 2004 and 2003, the rates for the right to explore and appraise oil fields in Tatarstan, Ulyanovsk and Orenburg were 360 rubles/sq. km (compared to 120 rubles/sq. km in 2002) and 20,000 ruble/sq. km for the right to prospect natural resources (compared to 5,000 rubles/sq 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 from royalties for the use of subsoil owed to the federal government with respect to oil produced from rehabilitated and previously 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. At December 31, 2004 and 2003, approximately 23% and 20% of production wells were non-operational, respectively, compared to approximately 17% as of December 31, 2002 and 18.2% as of December 31, 2001.

 

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. We plan to continue our well stimulation program, subject to providing necessary financing. We produced approximately 11.2 million tons (79.6 mmbbl), or 45.3% of our total crude oil produced, in 2003 using these secondary and tertiary recovery techniques (of which approximately 41.5% was from the use of the tertiary recovery techniques), and approximately 11.3 million tons (80.5 mmbbl) or 45.1% of our total crude oil produced in 2004, using these 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. 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 2003 our direct operating costs, or “lifting costs” per barrel (costs directly associated with the extraction of crude oil) remained virtually unchanged (U.S.$2.46 compared to U.S.$2.47 in 2002), with the positive effects from our cost reduction program offset by the real appreciation of the ruble against the U.S. dollar. Direct operating costs do not include accretion of liability in accordance with SFAS 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). At the same time, the growth in transportation expenses, increase in taxes other than income taxes and higher depreciation, depletion and amortization expenses resulted in an overall 25% increase in per barrel production costs from U.S.$9.51 in 2002 to U.S.$11.93 in 2003. In 2004, crude oil production costs increased by 10.8% due to the increase in taxes; however, at the same time our operating costs decreased by 3.2%.

 

The table below illustrates the dynamics of our production costs and average production costs per ton over the periods indicated:

 

     Year ended December 31,

     2003

   2002

   2001

Revenue (RR millions)

   93,155    84,394    91,528

Production costs (RR millions)

   26,562    24,521    26,821

Production (millions of tons)

   24,935    24,890    24,855

Average sales price (RR/ton)

   3,736    3,391    3,682

Average production cost (RR/ton)

   1,065    985    1,079

 

Wells

 

As of December 31, 2003, Tatneft possessed a total of 42,322 wells. Of these, 19,209 were active production wells and 8,431 were active injection wells. As of December 31, 2004, we possessed a total of 42,635 wells, of which 18,659 were active production wells and 8,504 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.

 

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The table below sets forth information on our wells as at December 31, 2004, 2003, 2002 and 2001.

 

     At December 31,

     2004

   2003

   2002

   2001

Production wells

   24,154    24,095    23,887    24,246

in operation

   18,659    19,209    19,832    19,831

not in operation(1)

   5,495    4,886    4,055    4,415

Injection wells

   9,220    9,017    8,831    8,578

in operation

   8,504    8,431    8,259    7,960

not in operation(2)

   716    586    572    618

Total production and injection wells

   33,374    33,112    32,718    32,824

Others(3)

   9,261    9,210    9,205    8,634
    
  
  
  

Total

   42,635    42,322    41,923    41,458
    
  
  
  

(1) Includes wells that are temporarily inactive, wells due to be rehabilitated or stimulated and wells that are used for testing purposes only.
(2) Includes wells due to be rehabilitated.
(3) Examples of other wells include irreparable wells that have been abandoned or dismantled and special purpose wells.

 

The table below sets out the drilling activity of Tatneft and our joint ventures in the years ended December 31, 2004, 2003, 2002 and 2001.

 

Drilling Activity

 

     Year Ended December 31,

Type of Drilling


   2004

   2003

   2002

   2001

     (Thousand meters)

Operation

   521.9    646.0    699.1    925.1

Exploration

   50.1    51.4    57.7    51.0

 

Tatneft drilled 350 new production wells in 2004, 414 new production wells in 2003, 417 new production wells in 2002 and 580 new production wells in 2001. Our joint ventures drilled 33, 40, 42 and 62 new production wells in 2004, 2003, 2002 and 2001, respectively. We generally drill more wells in the second half of the year than in the first half of the 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, 2004, 2003, 2002 and 2001 took place in the southern and eastern parts of Tatarstan. In addition, our oil services subsidiaries drilled 160.5 thousand meters, 176.7 thousand meters and 24.8 thousand meters for third parties, primarily small independent oil companies operating in Tatarstan in 2003, 2002 and 2001, respectively.

 

In the years ended December 31, 2004 and 2003, approximately 598 and 816 production wells were taken out of operation (representing approximately 2.8% and 3.4% of the total production wells), respectively. We rehabilitated 3,545 production wells in 2004 and 2,570 production wells in 2003, accounting for 18.9% and 13.4% of the active producing wells as of December 31, 2004 and 2003, respectively. In the year ended December 31, 2002, approximately 531 wells were taken out of operation. We rehabilitated 2,745 wells in 2002, accounting for approximately 13.6% of the active producing wells as of December 31, 2002. In the year ending December 31, 2001, approximately 392 wells were taken out of operation. We rehabilitated 2,491 wells in 2001, accounting for approximately 12.6% of the active producing wells as of December 31, 2001.

 

In 2003, we improved production at 1,250 production wells, accounting for approximately 6.5% of the active production wells as of December 31, 2003, respectively. In the year ended December 31, 2002, we improved production at 1,497 production wells, accounting for approximately 7.5% of 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.

 

TRANSPORTATION

 

We transport most of our crude oil through the pipeline system operated by Transneft, Russia’s monopoly pipeline operator. The Ministry of Industry and Energy allocates usage of the pipeline network for export deliveries to oil producers on a quarterly basis.

 

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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. Failure to pay taxes to the Russian government could result in the termination or temporary suspension of our access to the export pipelines. We do not believe that our share of pipeline export capacity will be materially adjusted in the near future. 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 Tariffs Service, a successor to the Federal Energy Commission, which also regulates the activities of natural monopolies in 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 May 6, 2005 and exclusive of VAT) for us to transport crude oil to Butinge is approximately U.S.$12.67 per ton; to Moscow approximately U.S.$5.37 per ton; to the Kremenchug refinery approximately U.S.$8.21 per ton; to Primorsk approximately U.S.$13.60 per ton; to Novorossisk approximately U.S.$11.30 per ton; and to Germany approximately U.S.$9.37 per ton. In addition, Transneft charges a premium of U.S.$2.5 per ton (exclusive of VAT) 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 addition to transportation of crude oil via Transneft, we transport a portion of our refined products through the Transnefteprodukt pipeline. Transnefteprodukt is also a state-controlled entity, specializing in the transportation of refined products. The Transnefteprodukt system is less extensive than the Transneft system. The Federal Tariffs Service also has responsibility for setting the tariff rates for Transnefteprodukt.

 

In 2002, we started shipping crude oil and refined products by railroad from the Nizhnekamsk Oil Refinery’s oil-loading platform and in 2003 from Tikhoretskaya oil-loading platform. Our total rail shipments in 2004 were 4.28 million tons (30.4 mmbbl) of refined products and 1.32 million tons (9.4 mmbbl) of crude oil compared to 3.2 million tons (22.8 mmbbl) of refined products and 2.3 million tons (16.4 mmbbl) of crude oil in 2003 and approximately 4.57 million tons (32.6 mmbbl) of refined products and 48,400 tons (0.3 mmbbl) of crude oil in 2002.

 

Since November 2002, we have accumulated a fleet of railroad cars capable of carrying oil and oil products and formed a subsidiary, OOO Tatneft-Trans, to operate these and leased rail cars and to coordinate transportation of our products via rail-road. As of December 31, 2004, we operated 1,162 rail cars, including 950 rail cars that we owned, and as of December 31, 2003 we operated 1,166 rail cars, including 950 rail cars that we owned.

 

RE FINING AND MARKETING

 

Crude Oil

 

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 processing arrangements and receive in return refined products for sale into the market. Starting from 2001, we shifted our emphasis from using intermediaries to processing arrangements. See “—Refined Products” 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, 2003, 2002 and 2001.

 

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Crude Oil Sales and Transfer Volumes

 

     Year Ended December 31,

     2003

   2002

   2001

     Tons

   Barrels

   %

   Tons

   Barrels

   %

   Tons

   Barrels

   %

     (in thousands of units, except percentages)
Crude oil sales and transfers     

Domestic

   6,153    43,828    20.3    5,402    38,478    18.7    10,664    77,101    37.0

CIS

   2,637    18,783    8.7    4,077    29,040    14.1    1,716    12,406    5.9

Non-CIS

   13,124    93,482    43.2    10,861    77,363    37.6    10,065    72,770    34.9

Transfers(1)

   8,428    60,032    27.8    8,528    60,745    29.6    6,408    46,330    22.2
    
  
  
  
  
  
  
  
  

Total

   30,342    216,125    100.0    28,868    205,626    100.0    28,853    208,607    100.0
    
  
  
  
  
  
  
  
  

(1) Transfers represent oil transferred for refining using intermediaries or under processing arrangements with third parties.

 

Our export volumes in 2003 increased in comparison to those in 2002 primarily due to a significant increase in non-CIS exports. Export sales are generally made at a higher price than are domestic sales, 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 58.0% of total sales revenues in 2003, compared to 55.6% in 2002.

 

Non-CIS Crude Oil Export Sales

 

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 2003 and 2004, we supplied approximately 26.6% and 14.0%, respectively, of our non-CIS deliveries to customers located in Germany, Poland, the Czech Republic and Slovakia via the Druzhba pipeline. We exported the remainder via the ports of Novorossisk, Primorsk, Butinge, Odessa and Yuzhnyi primarily to customers located in Turkey, France and Germany, or via the Transneft pipeline system to the Baltic states. We have also been increasing our exports of oil by rail.

 

We sell most of the oil that we export to international oil traders. Approximately 30%, or 0.3 million tons per month, of our export sales are made pursuant to long-term contracts securing our long-term loan agreements, and the remaining export volumes are sold on the basis of spot contracts. 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 2003, our non-CIS crude oil prices per ton decreased slightly, to RR5,296 compared to an average in 2002 of RR5,330.

 

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. During 2003 and 2004, approximately 30% of our approximately 1.1 million tons per month of non-CIS crude oil exports have been pledged as security for existing borrowings. 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 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 Crude Oil Export Sales

 

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 have historically been higher than domestic prices. In 2003, we delivered approximately 2.56 million tons (18.5 mmbbl) of crude oil to the Kremenchug refinery, representing approximately 97% of our CIS crude oil sales. In 2004, we delivered approximately 3.09 million tons (22.0 mmbbl) of crude oil to the Kremenchug refinery, representing approximately

 

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100% of our CIS 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 increased to RR3,591 in 2003 from RR2,823 in 2002, a 27% increase, due to the increase in market prices in the CIS.

 

Domestic Crude Oil Sales and Deliveries

 

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 2003, our domestic prices per ton averaged RR1,844, compared to average price of RR2,203 per ton in 2002, representing a 16% decrease. In 2004 our domestic prices trended significantly upwards as compared to 2003.

 

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 processing 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 processing arrangements is ultimately delivered to the Nizhnekamsk Oil Refinery, the Moscow oil refinery and Yaroslavl oil refinery. In 2004 and 2003, approximately 83% and 67%, respectively, of our total domestic crude oil shipment volumes were ultimately delivered to these three refineries, including approximately 63% and 50%, respectively, to the Nizhnekamsk oil refinery. Deliveries were also made to other refineries located throughout European Russia, including in Ufa, Ryazan and Nizhny Novgorod. In total, approximately 9.2 million tons and 8.3 million tons were delivered to domestic refineries, representing approximately 38% and 34% of all our deliveries (excluding purchased oil) in 2004 and 2003.

 

We also engage in swap transactions with other Russian oil companies whereby we undertake to deliver our oil to certain refineries in Russia or the CIS in exchange for delivery of oil of equivalent value to refineries in or adjacent to regions of Russia where we have retail operations. Such swap arrangements are beneficial to us and our counterparties insofar as they result in reduction of transportation costs and improved marketing efficiencies. The total volume of such swap transactions amounted to 0.4 million tons, 2.1 million tons, 2.7 million tons and 2.5 million tons in 2004, 2003, 2002 and 2001, respectively.

 

High Sulfur Content Crude Oil Sales

 

High sulfur content crude oil has a lower market value than crude oil with low sulfur content. The national pipeline operator, Transneft, charges a premium of U.S.$2.5 per ton (exclusive of VAT) 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 official ruble/U.S. dollar exchange rate as reported by the Central Bank in effect on the first day of each month. Because the blended crude oil sells for a uniform price and the U.S.$2.5 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. We blended and shipped virtually all of our high sulfur content crude oil production.

 

Government-Directed Deliveries

 

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 operations.”

 

Refined Products

 

Tatneft did not receive any refining capacity in connection with the privatization of the Russian oil and natural gas sector. However, we have increasingly been developing our refining capabilities and reducing our reliance on purchases of refined products produced from our crude oil from third parties.

 

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Refined Product Sales

 

     Year Ended December 31,

     2003

   2002

   2001

     Tons

   %

   Tons

   %

   Tons

   %

     (thousands of tons, except percentages)

Refined product sales(1)

                             

Domestic

   7,271    61.3    7,403    58.6    6,591    49.0

CIS

   63    0.5    7    0.1    121    0.9

Non-CIS

   4,523    38.2    5,216    41.3    6,737    50.1
    
  
  
  
  
  

Total

   11,857    100.0    12,626    100.0    13,449    100.0
    
  
  
  
  
  

(1) Includes purchases of 4,086, 4,490 and 6,171 thousand tons in the years ended December 31, 2003, 2002 and 2001, respectively.

 

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. To 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 to expand, upgrade and operate the Nizhnekamsk refinery. Our total investment in the refinery amounted to approximately RR8,438.4 million as of January 1, 2005 and we are currently planning capital expenditures of approximately RR252.2 million for 2005. Currently we own 63% of OAO Nizhnekamsk Oil Refinery. However, our and our partners’ interests in the joint venture are still under negotiation 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.

 

Completion of the Nizhnekamsk oil refinery facilities will decrease our dependence on refineries outside of Tatarstan and will enable us to produce more environmentally-friendly oil products from high sulfur content crude oil, including diesel fuel that adheres to European environmental standards. 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 directly the facilities whose construction we financed, separately from our interest in OAO Nizhnekamsk Oil Refinery. However, the primary refining unit belongs to TAIF, which has received a court judgment terminating the lease of that unit to OAO Nizhnekamsk Oil Refinery. Following the judgment, TAIF has not taken any steps to immediately evict Nizhnekamsk Oil Refinery, which currently continues to operate and make payments for the use of the unit. See “Item 3—Risk Factors—Risks Relating to the Company—A dispute with one of our business partners over the lease of a refining unit at the Nizhnekamsk oil refinery may have a material adverse affect on the value of the refining units owned by us and on our ability to process crude oil in Tatarstan.” We have also formed a joint venture with OAO Nizhnekamskneftekhim, OAO Svyazinvestneftekhim and LG International Corp. to carry out a feasibility study for an oil refining and petrochemicals complex in Tatarstan. See “—History and Development” under this Item.

 

We own a small oil refinery in Kichuyi, Tatarstan, that began operating in 1995. This refinery is one of the most technologically modern oil refineries in Russia. It has an annual refining capacity of 400,000 tons (approximately 2.85 mmbbl) and produces gasoline and diesel fuel to serve primarily our fuel needs and those of local residents of the Almetyevsk region.

 

We also own the Minnibaevsk Gas Refinery in Tatarstan. Deliveries from the Minnibaevsk Gas Refinery totaled 0.9 million tons of gas products in each of 2003 and 2004, of which approximately 56% were delivered to Nizhnekamskneftekhim, 1% exported, and the balance sold to various 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. 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.

 

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. Further development of our retail network has resulted in increased sales of refined products in domestic markets. 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 2003, we purchased refined products totaling approximately 2.4 million tons, of which we exported 2 million tons. We sold refined products totaling 9.9 million tons, 12.6 million tons and 13.4 million tons, and earned revenue of RR43,831, RR44,876 and

 

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RR43,859 million from these sales for the years ended December 31, 2003, 2002 and 2001, 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.

 

Processing arrangements accounted for a significant portion of our crude oil product sales in 2003. Under such arrangements, a refinery processes crude oil for us in exchange for either a portion of crude oil, 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 January 1, 2005, there were 547 Tatneft-branded service stations throughout Russia and Ukraine, including 140 in Tatarstan, 124 in Moscow and the Moscow region, 56 in the Chuvash Republic and 145 in Ukraine.

 

PETROCHEMICALS

 

We did not receive any petrochemicals companies or operations in connection with the privatization of the Russian oil and gas sector. However, in an attempt to create a vertically integrated company, since 2000 we have been increasing our petrochemicals capabilities. In 2000, we purchased an approximately 34.6% stake in Nizhnekamskshina from the Tatarstan government, subsequently increasing our stake to 76.01% through additional purchases and participation in a new share issuance. Nizhnekamskshina has been consolidated in our consolidated financial statements from September 30, 2001.

 

Nizhnekamskshina is one of the largest tire manufacturers in Russia, accounting for approximately 29% and 27.7% of all tires produced in Russia in 2004 and 2003, respectively, and supplying its products to both domestic and foreign markets. Nizhnekamskshina consists of two divisions, a mass tire plant that produces tires for light-weight vehicles and a truck tires plant. Approximately 27.0% and 26.0% of the tires produced by Nizhnekamskshina in 2004 and 2003, respectively, were supplied to car manufacturers (25.9% in 2002), 53.0% and 53.6% were sold on the secondary market (60.3% in 2002) and 20.0% and 20.3% were exported (13.7% in 2002), including approximately 15.0% and 15.4% (10.3% in 2002) to customers in the CIS. We are in the process of renovating the manufacturing facilities at Nizhnekamskshina, and intend 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, and in July 2004 we started producing radial tires for light passenger vehicles using this technology in the production of up to two million tires annually. From July to December 2004, we shipped 102,700 radial tires. In 2005, we plan to produce and ship 1,400,000 radial tires.

 

We also acquired approximately 77.06% 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 and own 51% of ZAO Yarpolymermash-Tatneft, which is based on the assets of the Yaroslavl Polymer Machine Plant, in order to manufacture equipment for processing materials for tire production. In 2003, we commenced production at OOO Tatneft-Nizhnekamskneftekhimoil, a polialphaolefin-based synthetic lubricants plant that is the only such enterprise in Russia. In the first half of 2004 the production of polialphaolefin-based synthetic lubricants was conducted on a transitional basis. In December 2004, programs were approved to update the oils to international standards and on the production of new products. These programs require an investment of approximately RR79.9 million. Polialphaolefin-based synthetic lubricants are also used at the plant for the production of high-quality greasing substances, such as engine, transmission, refrigerator and synthetic oils. The American Oil Institute has issued a license on the conformity of our engine oil “Tatneft-Profy” with the API standards.

 

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, Tatneft-Nizhnekamskneftekhimoil, Trading House “Kama,” OAO Plant Elastic and other petrochemicals companies.

 

BANKING OPERATIONS

 

We own shares in a number of banking and financial entities, but following the sale of our controlling share in our most significant banking subsidiary in April 2005, have recently decreased our activities in these market sectors. The banks in which we hold significant stakes are:

 

    OAO Bank Zenit. In April 2005 we owned 52.7% of Bank Zenit, a Russian commercial bank founded in December 1994 and based in Moscow, having increased our holdings from 50% plus one share in 2004. Bank Zenit has branches, in Rostov-on-Don, Nizhny Novgorod, Almetyevsk, Gorno-Altaisk, St. Petersburg, Kemerovo and Kursk, a representative office in Kazan and additional offices in Kazan and Nizhnekamsk. In April 2005, our wholly-owned subsidiary, Tatneft Oil AG, sold its 26.75% stake in Bank Zenit to three companies acting for the benefit of beneficiaries of Urals Energy NV. This transaction had the effect of reducing our ownership interest in Bank Zenit to 25.95%.

 

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    Bank Devon-Credit. We own approximately 95.3% of Bank Devon-Credit, a Russian commercial and retail bank. Bank Devon-Credit serves Tatneft and much of the local population in Almetyevsk and the southeast of Tatarstan through a network of 13 branch offices.

 

    Bank Ak Bars. As of December 31, 2003 we owned approximately 21.77% of Bank Ak Bars, the largest private bank located in the Republic of Tatarstan in terms of assets and number of retail customers. In 2004 and 2005 we increased our shareholding and currently hold 29.98% of Bank Ak Bars. Bank Ak Bars has held approximately 1% of Tatneft’s Ordinary Shares since 2000.

 

We conduct our banking operations through, and consolidate the results of, Bank Zenit and Bank Devon-Credit. However, due to the sale of 26.75% of our stake in Bank Zenit from the fiscal year ending December 31, 2005, we will no longer consolidate the results of Bank Zenit, but rather account for our investment in Bank Zenit under the equity method. Pursuant to the sale of a portion of a stake in Bank Zenit, we no longer consider our banking activities to be significant to our operations. For more comprehensive information about our sale of Bank Zenit shares see Note 22 to our audited consolidated financial statements included in this annual report. For a more detailed discussion of our banking subsidiaries in general see “Appendix A—Tatneft’s Banking Operations.”

 

COMPETITION

 

Oil and Refined Products

 

We currently hold most of the licenses for oil exploration and production within Tatarstan. We consider all other major Russian oil companies, including Rosneft (particularly following its acquisition of the former Yukos subsidiary Yuganskneftegaz in January 2005), LUKOIL, Surgutneftegaz and TNK-BP, 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, 2003 and 2004 the Russian oil industry experienced substantial consolidation, including the privatization sale of Slavneft, a large vertically-integrated oil company, to the shareholders of TNK and Sibneft, at the time Russia’s third and fifth largest oil companies, respectively; the formation of TNK-BP, a joint venture between TNK and BP that combined the assets of TNK, Sidanko and Onako oil companies and TNK’s share in Slavneft with the Russian assets of BP (excluding investments in Sakhalin); and the merger between YUKOS and Sibneft that resulted in the creation of the largest Russian and one of the largest international oil companies by annual production. Following the criminal prosecution of key YUKOS shareholders, YUKOS and Sibneft have unwound their merger, and Yuganskneftegaz – the largest production subsidiary of YUKOS – was sold at auction by the Russian government in partial settlement of tax claims against YUKOS and acquired by Rosneft, a state-owned oil company. In addition, in September 2004, the Russian government sold its remaining 7.6% stake in LUKOIL in a privatization auction to ConocoPhillips. These competitors may have better access to financial and other resources and greater political influence than we do.

 

Petrochemicals

 

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, Volzhsky, Barnaul, NIIShP, Ural and Petroshina tire companies, as well as Ukrainian tire plant Rosava. The Omsk, Yaroslavl, Volzhsky and Ural tire companies, accounting for approximately 46.4% of tires produced in Russia, are controlled by Sibur, a petrochemicals subsidiary of Gazprom, Russia’s largest company and natural gas transportation monopoly and the world’s largest producer of natural gas. The Kirov, Krasnoyarsk and Voronezh tire companies, accounting for approximately 18.3% of tires produced in Russia in 2003, as well as Rosava, are controlled by AMTEL, a Russian petrochemicals holding. Several of our competitors have entered into joint ventures with major

 

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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. For example, Nokian Tires has announced its decision to build a new plant in Vsevolzhsk and within three years to produce 3.5 million tires per year (with a maximum production capacity of 8-9 million tires per year). In addition, in 2004, Michelin opened a plant that produces extra class radial tires and sport tires in Davidivo (in the Moscow Region) and has announced plans to reach a production capacity of 2.1 million tires per year in 2005.

 

Banking

 

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, 1,304 banks and other non-bank credit organizations were licensed to conduct banking transactions in Russia as of December 1, 2004. Due to the large number of banks in Russia and the varying focuses of many of those banks, 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. For a more detailed discussion of our banking subsidiaries in general see “Appendix A—Tatneft’s Banking Operations.”

 

ENVIRONMENTAL MATTERS

 

We are currently subject to environmental legislation enacted by both Russia and Tatarstan. The Russian legislation provides grounds for requiring polluters to clean up environmental pollution. Environmental authorities may impose fines for breaches of environmental and sanitation standards as a payment for remediation of the damage caused to the environment. We actively pursue policies, however, that are designed to reduce pollution and its effects, particularly with respect to water, soil and air. Furthermore, the implementation of the Kyoto Protocol may impose new and/or additional rules or more stringent environmental norms. Such requirements may require additional capital expenditures or modifications in operating practices. The impact on us will depend on, among other factors, the base level against which permissible levels of emissions are to be measured and the allocation of quotas for such emissions, which is currently uncertain.

 

All four of the main rivers located in the territory of our operations previously tested positive in excess of safe levels for chlorides (chemicals derived from the oil production process) and oil products, which characterizes the impact of oil producing industry on these rivers. Levels of chloride contamination in local rivers peaked in 1986, have recently dropped below the maximum allowable concentrations established by law and continue to decrease. We use the system of circulating and repeated water supply in oil production where water is used in maintaining the seam pressure after the oil treatment.

 

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). Almost all of our waste water carrying pipelines have now been replaced with such polyethylene-coated pipes and we continue to replace our oil-gathering networks. Where the use of polyethylene-coated pipes is technically impossible, we use pipes with an internal polymer coating. Along with other corrosion control methods, we have successfully used corrosion inhibitors and electro-chemical protection of oil producing equipment. We develop and implement measures for diagnostics of the technical state of oil-producing pipes on an annual basis. We also organized a permanent monitoring of corrosion of oil-producing equipment for assessment of maintaining resources for safe use and prevention of environmental risks.

 

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 well constructions and hydroisolation of storage pits during well drilling and repair work.

 

We have developed a complex of measures to ensure ecologically safe construction and repair of the wells and other oil producing facilities. We have organized a supervising service which monitors compliance of the production technology with legal requirements.

 

We have an opportunity to conduct purification and recovery of contaminated soil as the need arises, as well as recovery of the oil sludge earlier collected in ponds.

 

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Through our joint venture TATEX we have been installing vapor recovery equipment on our oil storage tanks. In 2003, two additional vapor recovery systems became operational. In 2004, two more vapor recovery systems became operational and we completed construction on an additional three vapor recovery systems. Currently there are 40 vapor recovery systems in operation, equipping all of our storage tanks. This program has helped to reduce substantially emissions of hydrocarbons from our facilities into the atmosphere. We have reduced sulfur dioxide emissions by installing facilities for sulfur cleaning.

 

After making an economic assessment we created facilities and introduced technologies for processing used tires, luminescent lamps, oil sludge, used motor oils and wires and other production waste because environmental regulations changed and became more strict in respect to handling of waste.

 

We maintain special laboratories to monitor the surface and ground waters and control the atmospheric air in the territory where we conduct our activities.

 

CORPORATE REORGANIZATION

 

Following the dissolution of the Soviet Union and due to the subsequent disruption of relations with 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 that was initially approved by our Board of Directors in 1996. The key tasks of the reorganization program are:

 

    enhancing oil and natural gas production potential;

 

    transferring to subsidiaries functions that are unrelated to our core activities;

 

    reducing extraction and auxiliary production expenses by: (i) reducing the number of divisions and (ii) optimizing utilization of production facilities;

 

    improving efficiencies in utilization of personnel; and

 

    reducing social benefit costs.

 

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 are currently in 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, and in enterprises that sell crude oil and oil products or provide oil services, such as Tatneft Europe.

 

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, consolidated management of Tatneft-branded gas stations in OOO Tatneft-Centernefteproduct and continued with our internal restructuring in order to optimize costs and corporate governance. As part of our internal restructuring, we took additional steps 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 2003, we divested our stakes in 21 agricultural companies and formed a subsidiary, OOO Tatneft-Aktiv, to optimize leasing of various assets not necessary for our ongoing operations to third parties.

 

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Further Reorganization Plans

 

We have recently approved a corporate reorganization program for 2005 to 2007, which is aimed at further transferring support services, currently provided within each NGDU, to newly formed subsidiaries. In accordance with this program we plan to transfer the following functions unrelated to our core activities to subsidiaries:

 

    public transport;

 

    construction and installation works;

 

    repair and maintenance of our conventional pumping units;

 

    downhole logging works;

 

    chemical analytical works; and

 

    security of industrial facilities.

 

We do not plan any significant employee reductions over the course of this reorganization.

 

In an effort to reduce our costs, we intend to separate out some of our small service units into economically independent operations. 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, though in the first several years following their creation we expect to remain the primary customer of such 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 and maintenance 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.

 

Divestiture of Social Assets

 

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, 2003, 2002 and 2001, we held social assets with a net book value of RR4,870 million, RR5,833 million and RR5,831 million, respectively. We transferred social assets with a combined net book value of RR2,162 million (including medical equipment with a net book value of RR1,917 million), RR1,293 million and RR593 million in the years ended December 31, 2003, 2002 and 2001, respectively, to public ownership. We also incurred social infrastructure expenses of RR279 million, RR199 million and RR419 million for the years ended December 31, 2003, 2002 and 2001, respectively, for maintenance primarily relating to housing, schools and cultural buildings.

 

We have also developed a long-term home construction program, which is aimed at reducing housing shortages in the regions in which we operate and that extends 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 2003 and 2004, we issued RR58.63 million and RR50 million, respectively, in housing loans, enabling more than 5% of our employees who qualified as in need of improved housing to acquire new housing. We also financed the construction of 33,443.7 square meters of housing for our employees in 2003 and 33,195 square meters in 2004.

 

RELATIONSHIP WITH TATARSTAN

 

As of May 12, 2005, OAO Svyazinvestneftekhim, a company wholly-owned by the government of Tatarstan, held approximately 33.59% of our capital stock and 35.87% of our Ordinary Shares. The Tatarstan government also holds the Golden Share, which gives it the power to appoint a representative to our Board of Directors and Revision Committee and veto certain corporate decisions. The Golden Share currently has an indefinite term. For a description of the Golden Share rights see “Item 7—Major Shareholders and Related Party Transactions—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.”

 

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Through its indirect 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, directly or indirectly, 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:

 

    OAO Tatenergo: Our companies receive most of their electricity from Tatenergo, the primary provider of electric power in Tatarstan.

 

    OAO Nizhnekamskneftekhim: Through domestic sales agents we deliver some of our crude oil products to Nizhnekamskneftekhim, the largest petrochemicals company in Tatarstan. Nizhnekamskneftekhim is also a shareholder in OAO Nizhnekamsk Oil Refinery and TKNK.

 

    OAO TAIF: TAIF, which is affiliated with Tatarstan, owns a refining unit at the Nizhnekamsk Oil Refinery. However, TAIF has won a court judgment terminating the lease of its refining unit to Nizhnekamsk Oil Refinery. TAIF has not currently taken any steps to immediately evict Nizhenekamsk Oil Refinery, which currently continues to operate and make payments for use of the unit. See “Item 3—Risk Factors—Risks Relating to the Company—A dispute with one of our business partners over the lease of a refining unit at the Nizhnekamsk oil refinery may have a material adverse effect on the value of the refining units owned by us and on our ability to process crude oil in Tatarstan.” TAIF is also a shareholder in OAO Nizhnekamsk Oil Refinery and one of our largest shareholders. See “—Refined Products” under this Item and “Item 7—Major Shareholders and Related Party Transactions—Major Shareholders.”

 

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 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 (we repaid all amounts due 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 the transfer to us 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 U.S.$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 U.S.$19 million to Société Générale. This obligation was restructured under the terms of the Restructuring Agreement.

 

Through 2000, Tatarstan had a special tax regime in relation to our operations. This tax regime provided significant tax savings for us. We have not enjoyed any significant tax benefits from Tatarstan since 2000.

 

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 “—Strategy” under this Item.

 

In 2003, we provided an interest-free loan in the amount of RR1,197 million to the Republican State Unitary Company “Nedoimka,” which is wholly owned by the government of Tatarstan, in exchange for long-term notes receivable due in 2022. The government of Tatarstan used the proceeds of this transaction to finance social expenditures. We believe that these long-term notes receivable are not recoverable. Consequently, we wrote off the long-term notes receivable in fiscal year 2003, resulting in a charge to operations of RR1,197 million. See Note 10 to our audited consolidated financial statements.

 

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In September 2004, we entered into a RR 2,000 million loan agreement with Svyazinvestneftekhim. The amount outstanding as of December 31, 2004 was RR 2,000 million. The loan interest rate is 0.01% per annum, and the loan matures in March 2014.

 

In January 2004, we purchased interest-free promissory notes redeemable in 2024 in the amount of RR960 million from “Tatgospostavki,” which is wholly owned by the government of Tatarstan. The government of Tatarstan used the proceeds of this transaction to finance social expenditures.

 

PROPERTY, PLANT AND EQUIPMENT

 

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, are located in Tatarstan. For a description of our reserves, sources of crude oil, refining facilities, gas station operations and other facilities see “—History and Development,” “—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, Nizhny Novgorod and Arkhangelsk, as well as in Ukraine. In 2002, in a series of transactions we purchased 16,767 hectares of land underneath most of our production properties located in Tatarstan from the Tatarstan government for RR330 million.

 

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ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

 

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, 2003 and 2002 and for each of the years in the three-year period ended December 31, 2003. 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.

 

Russia’s economy was considered hyperinflationary for purposes of our consolidated financial statements for the year ended December 31, 2002 and prior periods, and such consolidated financial statements were prepared in accordance with Accounting Principles Board Statement 3, Financial Statements Restated for General Price Level Changes. All ruble amounts for periods prior to January 1, 2003 are thus expressed in constant rubles as of December 31, 2002 purchasing power, except as indicated otherwise. At a meeting of the AICPA International Practices Task Force on November 25, 2002, the Task Force concluded that Russia would no longer be considered highly inflationary effective from January 1, 2003.

 

As discussed herein, this discussion of our financial condition and results of operations gives effect to the restatements of our consolidated financial statements for the years ended December 31, 2002 and 2001 described below in “Restatements of Previously Issued Financial Statements” and in Note 4 to our consolidated financial statements included in this annual report.

 

Restatements of Previously Issued Financial Statements

 

Our consolidated financial statements for the year ended December 31, 2002 have been restated to reflect a change in calculation of deferred taxes. In addition, the consolidated financial statements for the years ended December 31, 2002 and 2001, have been restated to reflect the effects of a change in calculation of depreciation, depletion and amortization, as described below. The net effect of these changes was to reduce our net income by RR2,323 million and RR206 million for the years ended December 31, 2002 and 2001, respectively.

 

Deferred taxes

 

For the year ended December 31, 2002, as permitted by the legislation of the Russian Federation, we recorded a statutory revaluation of our property, plant and equipment tax base amounting to RR11,893 million, and inappropriately recorded a decrease in deferred tax liability of RR2,854 million calculated on the entire amount of this statutory revaluation. Only a portion of this statutory revaluation, however, could be deductible in the future for tax purposes and as such the tax base of property, plant and equipment was overstated resulting in an understatement of deferred tax liabilities as of December 31, 2002, amounting to RR2,158 million. Deferred tax liabilities as of December 31, 2002 and 2001 and corresponding deferred tax expenses and benefits for the years then ended were also restated as a result of a restatement of property, plant and equipment, net of accumulated depreciation, depletion and amortization, as of December 31, 2002 and 2001 as discussed below. As a result of these restatements, our deferred income tax expense changed from a benefit of RR1,488 million to an expense of RR620 million for the year ended December 31, 2002 and increased from RR8,205 million to RR8,316 million for the year ended 2001.

 

Depreciation, depletion and amortization

 

We historically have been depleting oil and natural gas properties on a units-of-production basis over total proved reserves, and not proved developed reserves, as required by U.S. GAAP. We originally believed that the difference between the two classes of reserves was not material for us and that the impact on the calculation of depreciation, depletion and amortization would also not be material. As a result of a recalculation of depreciation, depletion and amortization using proved developed reserves on a cumulative basis, we no longer believe that assumption to be appropriate. The cumulative effect of the subsequent adjustment to retained earnings as of December 31, 2000 was a decrease of RR697 million. As a result of this restatement, our depreciation, depletion and amortization for the year ended December 31, 2002 increased from RR7,325 million to RR7,541 million and for the year ended December 31, 2001 increased from RR5,822 million to RR6,139 million.

 

Developments during 2004 and 2005

 

At the annual general meeting of shareholders on June 25, 2004, final dividends of RR0.30 per ordinary share and RR 1.00 per preferred share, to be paid in cash, were approved for 2003. At an extraordinary general meeting of shareholders held on November 6, 2004, interim dividends for the first nine months of 2004 of RR0.67 per ordinary share and RR1.00 per preferred share, to be paid in cash between November 15, 2004 and March 1, 2005, were approved. The interim dividends were paid out as of January 1, 2005. At the annual general meeting of shareholders on June 30, 2005, final dividends of RR0.90 per ordinary share and RR1.0 per preferred shares, to be paid in cash, were approved for 2004.

 

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In addition, in April 2005 we received a claim for back taxes from the federal tax authorities, based on their review of our tax filings for the years 2001, 2002 and 2003, in the amount of RR1,380 million. This amount includes both alleged non-payment and under-payment of taxes as well as fines and penalties. While we could challenge this claim, given other Russian companies’ recent experiences in this area, we have decided not to do so and paid all sums due in May 2005. Moreover, we recognize that this claim is significantly smaller than similar claims recently received by other Russian companies.

 

OVERVIEW

 

Our financial results have been affected significantly by several factors attributable to the special characteristics of the Russian economy and our primary product markets. These factors include crude oil and refined product prices; constraints on the export sale of crude oil and refined products; transportation costs; and inflation and foreign currency exchange rate fluctuations. Each of these factors is discussed in more detail below.

 

Crude oil and refined product prices

 

Our operations are significantly affected by changes in crude oil and refined product prices, both in export markets and in Russia. These prices are affected by external factors over which we have no control, such as global economic conditions, demand growth, inventory levels, weather, competing fuel prices and global and domestic supply. Export and domestic prices for crude oil and refined products have been highly volatile, depending on the balance between supply and demand and on OPEC production levels.

 

Historically, crude oil prices in the Russian market have been substantially below prices in the international market. Moreover, there is no independent or uniform market price for crude oil in Russia primarily because a significant portion of crude oil destined for sale in Russia is produced by vertically integrated Russian oil companies and is refined by the same vertically integrated companies. Crude oil that is not exported from Russia, refined by the producer or otherwise sold is offered for sale in the domestic market at prices determined on a transaction-by-transaction basis.

 

Most of the crude oil that we sell in export markets is transported through the Transneft pipeline system. Transneft is a state-controlled company. Our crude oil is blended in the Transneft pipeline system with other crude oil of varying qualities to produce an export blend commonly referred to as Urals. We benefit from this blending, as the quality of our crude oil is generally lower than that produced by other oil companies due to the relatively high sulfur content of the crude oil that we produce. There is currently no equalization scheme, often referred to as a “quality bank,” for differences in crude oil quality supplied to the Transneft pipeline system, and the implementation of any such scheme is not determinable at present. However, if this practice were to change, our business could be materially and adversely affected. See “Item 3—Key Information—Risk Factors—Risks Relating to the Company—A significant proportion of our crude oil production and reserves consists of high sulfur crude oil, for which we receive a lower price and which has lower marketability than lower-sulfur content crude oil.”

 

Constraints on the export sale of crude oil and refined products

 

We transport substantially all of the crude oil that we sell in export markets through trunk pipelines in Russia that are controlled by Transneft. The Russian government is expected to retain control over Transneft for the foreseeable future. Although pipeline capacity in Russia has increased in recent years, this capacity has not kept up with increases in production experienced by Russian oil and gas companies, and therefore the capacity of the pipeline network acts as a constraint on exports and indirectly on oil production in Russia.

 

Tatneft also uses the Russian rail network to transport the crude oil and refined products that it sells in export markets. However, the Russian rail network has limited capacity and the Russian government may allocate use of the Russian railway system on a preferential basis to domestic deliveries. Moreover, the system is subject to disruption as a result of its physical condition, a shortage of railcars, the limited capacity of border stations and spills and leakages.

 

A significant proportion of our crude oil and refined products is transported by pipeline and rail and delivered to marine terminals for onward transportation. There are significant constraints present in Russia’s oil shipment terminals due to geographic location, weather conditions and port capacity limitations.

 

In addition, our ability to sell crude oil in export markets may be constrained by the Russian government and its agencies, which seek to ensure the availability of sufficient supplies of crude oil and refined products on the domestic market and may also seek to limit exports of crude oil for other reasons. For example, though Russia is not a member of OPEC, the Russian government agreed with OPEC to reduce exports of crude oil through the Transneft pipeline by 150,000 barrels per day through most of the first half of 2002 as compared to the fourth quarter of 2001. This voluntary reduction of crude oil exported through the Transneft pipeline was not extended.

 

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We believe that physical and governmental constraints on export sales of crude oil and refined products may continue in the future.

 

Transportation costs

 

We incur transportation costs for the delivery of crude oil to refineries and for the delivery of crude oil and refined products to export markets. Transneft collects, on a prepayment basis, a ruble tariff on domestic crude oil shipments and a combined ruble and hard currency tariff on exports. A significant proportion of our refined products are transported using the Transnefteprodukt pipeline system. Transnefteprodukt is a state-controlled company, which specializes in transportation of refined products. However, the Transnefteprodukt system is not as extensive as the Transneft system for transporting crude oil.

 

Prior to March 2004, the Russian Federal Energy Commission periodically reviewed and set the tariff rates for each segment of the Transneft and Transnefteprodukt pipelines. In March 2004, the Federal Energy Commission was reorganized into the Federal Tariffs Service, which has now assumed this role.

 

We are also subject to tariffs for crude oil and refined products that we transport by railway.

 

Inflation and foreign currency exchange rate fluctuations

 

A significant part of our revenues are derived from export sales of crude oil and refined products, which are denominated in U.S. dollars. Our operating costs are primarily denominated in rubles.

 

Accordingly, the relative movements of ruble inflation and ruble/U.S. dollar exchange rates can significantly affect our results of operations. 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 costs to increase relative to revenues. We have not historically used financial instruments to hedge against foreign currency exchange rate fluctuations.

 

As measured by Russia’s CPI, annual inflation in Russia was 11.7%, 12%, 15.1%, 18.8%, 20.1% and 37.0% in 2004, 2003, 2002, 2001, 2000 and 1999 respectively. Given Russia’s past inflation history, Russia’s economy was considered hyperinflationary for purposes of our consolidated financial statements for the year ended December 31, 2002 and prior periods, and such consolidated financial statements were prepared in accordance with Accounting Principles Board Statement 3, Financial Statements Restated for General Price-Level Changes. These figures were thus expressed in millions of constant rubles as of December 31, 2002 purchasing power. At a meeting of the AICPA International Practices Task Force on November 25, 2002, the Task Force concluded that Russia would no longer be considered highly inflationary effective from January 1, 2003.

 

The following table shows the period-end and average ruble/U.S. dollar exchange rates, 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 indicated.

 

     Year ended
December 31,
2003


    Year ended
December 31,
2002


    Year ended
December 31,
2001


 

U.S.$ period-end exchange rate

   29.45     31.78     30.14  

Average U.S.$ exchange rate

   30.69     31.35     29.17  

Nominal appreciation (devaluation) of the ruble

   7.3 %   (5.4 )%   (7.0 )%

Real ruble appreciation

   20.9 %   9.2 %   11.0 %

Sources: Goskomstat and Central Bank of Russia

 

At present, the ruble is not a convertible currency outside the Commonwealth of Independent States. Exchange restrictions and controls exist with respect to the conversion of rubles into other currencies. For instance, between March 1999 and the first half of August 2001, we were required to sell 75% of our hard currency export proceeds to authorized banks in exchange for rubles. From the second half of August 2001, this rate was decreased to 50%. In July 2003 the Central Bank was given the authority to set this rate between 0% and 30%, and established a rate of 25%. In December 2004, the Central Bank further reduced the rate to 10%.

 

In December 2003, the Exchange Control Law was signed by President Putin. Most provisions of the Exchange Control Law came into effect on June 18, 2004. The Exchange Control Law significantly liberalizes the exchange control regime in Russia and

 

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expands the ability of Russian individuals and legal entities to engage in banking and financial transactions outside of Russia. Effective from January 1, 2007, the Exchange Control Law will remove certain restrictions previously imposed by the Russian government and the Central Bank on transactions between Russian individuals and companies and non-Russian residents. However, from June 18, 2004, the Russian government and the Central Bank are also able to impose mandatory reserve requirements and require the use of special accounts for certain transactions of Russian residents with non-residents.

 

Taxation

 

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.

 

The Russian Tax Code was amended in August 2001, effective from January 1, 2002. As a result of this amendment, 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 9% 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% were abolished. Under the second chapter, a unified natural resources production tax on the extraction of commercial minerals was introduced. This unified natural resources production tax replaced the mineral restoration tax, royalty tax and excise tax on crude oil. In addition, Road Users Tax was abolished effective January 1, 2003.

 

In addition to income taxes, we are also subject to:

 

    unified natural resources production tax;

 

    export duties;

 

    excise taxes on refined products;

 

    value added tax;

 

    property taxes; and

 

    other local taxes and levies.

 

These taxes have had a significant effect on our results of operations, and represented 28%, 22% and 21% of total sales and other operating revenues in the years ended December 31, 2003, 2002 and 2001, respectively. These taxes also represented 31% of total costs and other deductions in the year ended December 31, 2003 and 25% in each of the years ended December 31, 2002 and 2001.

 

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

 

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The table below presents a summary of statutory tax rates fixed by monthly calculations issued by the taxation authorities to which we and most of our subsidiaries were subject during the years ended December 31, 2004, 2003, 2002 and 2001 and as of April 1, 2005:

 

   

April 1,

2005


    Year Ended December 31,

   

Taxable base


Tax


    2004

    2003

    2002

    2001

   

Income tax – maximum rate

    24 %     24 %     24 %     24 %     35 %   Taxable income

VAT

    18 %     18 %     20 %     20 %     20 %   Added value

Unified natural resources production tax

  RR 1,723     RR 1,053     RR 801     RR 668       —       Metric ton produced (crude oil)

Mineral restoration tax(1)

    —         —         —         —         10 %   Sales revenues(2)

Royalty tax(1)

    —         —         —         —         6-16 %   Sales revenues(2)

Crude oil excise tax(1)

    —         —         —         —       RR 66     Metric ton produced and sold (crude oil)

Refined products excise tax:

                                           

High octane gasoline

  RR 3,629     RR 3,360     RR 3,000     RR 2,072     RR 1,850     Metric ton produced and sold domestically(3)

Low octane gasoline

  RR 2,657     RR 2,460     RR 2,190     RR 1,512     RR 1,350    

Diesel fuel

  RR 1,080     RR 1,000     RR 890     RR 616     RR 550    

Motor fuel

  RR 2,951     RR 2,732     RR 2,440     RR 1,680     RR 1,500    

Crude oil export duty, average(4)

  U.S.$ 102.6     U.S.$ 55.9     U.S.$ 30.4     U.S.$ 18.6     EUR 29.1     Metric ton exported

Refined products export duty, average:

                                           

Light distilled products (gasoline products)(5)

  U.S.$ 68.2     U.S.$ 38.0     U.S.$ 27.4     EUR 30.0     EUR 38.7     Metric ton exported

Mid distilled products (diesel fuel) (5)

  U.S.$ 68.2     U.S.$ 38.0     U.S.$ 27.4     EUR 30.0     EUR 38.7    

Fuel oil(5)

  U.S.$ 36.7     U.S.$ 36.7     U.S.$ 27.4     EUR 15.1     EUR 24.4    

Road users tax(6)

    —         —         —         1 %     1 %   Net revenues

Property tax – maximum rate

    2.2 %     2.2 %     2 %     2 %     2 %   Taxable property

(1) The crude oil excise tax, mineral restoration tax and royalty tax were replaced on January 1, 2002 by the unified natural resources production tax. The range from 6 to 16% represents the minimum and maximum rates applicable.
(2) Sales revenues net of VAT and excise tax for domestic sales; sales revenues net of export duties, excise tax and transportation costs for export sales.
(3) Excise taxes are paid on refined products produced and sold domestically. Prior to January 1, 2003, excise tax was paid by the producers of refined products. From January 1, 2003, excise taxes are paid by the sellers of refined products to end customers, and producers and intermediary re-sellers accrue excise tax and subsequently recover it subject to certain conditions.
(4) From February 1, 2002, crude oil export duties have been denominated in U.S. dollars. Prior to February 1, 2002, crude oil export duties were denominated in euro.
(5) From January 1, 2003, refined products export duties have been denominated in U.S. dollars. Prior to January 1, 2003, refined products export duties were denominated in euro.
(6) Abolished from January 1, 2003.

 

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 natural gas revenues recognized under Russian accounting regulations by production subsidiaries and excise taxes on crude oil production of approximately U.S.$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 a unified natural resources production tax. Through December 31, 2004, the base tax rate for the unified natural resources production tax was set at RR347 per ton of crude oil produced, increasing to RR419 per ton of crude oil produced effective from January 1, 2005. The rate is adjusted monthly depending on the market price of Urals blend and the ruble exchange rate, and becomes zero if the Urals blend price falls to or below U.S.$8.00 per barrel (U.S.$9.00 from January 1, 2005). For the year ended December 31, 2003, the average effective rate for the unified production tax, based on the Urals blend market price and ruble exchange rates, was RR801 per ton of crude oil produced. At December 31, 2003, the effective rate for the unified natural resources production tax was RR808 per ton. From January 1, 2007, the unified natural resources production tax rate is set by law at 16.5% of the value of extracted crude oil, calculated either by reference to actual sale prices of natural resources or the deemed value of natural resources net of VAT less export duties, transportation expenses and certain other distribution expenses.

 

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Maximum rates of export duties for crude oil were established by Russian Federal Law No. 126-FZ dated August 8, 2001, as amended. The maximum rates depend on a lagged average of Urals blend prices. Effective from February 1, 2002, the export duty rates start at zero when the lagged Urals blend price is at or below U.S.$109.5 per metric ton. The export duty rates increase by U.S.$0.35 per ton for each U.S.$1.00 increase in the lagged Urals blend price when the lagged Urals blend price is between U.S.$109.5 and U.S.$182.5 per ton, and by U.S.$0.40 per ton for each U.S.$1.00 increase in the lagged Urals blend price when the lagged Urals blend price is above U.S.$182.5 per ton.

 

Effective from June 13, 2004, the export duty rates start at zero when the lagged Urals blend price is at or below U.S.$109.5 per metric ton. The export duty rates then increase by U.S.$0.35 per ton for each U.S.$1.00 increase in the lagged Urals blend price when the lagged Urals blend price is between U.S.$109.5 and U.S.$146.0 per ton, by U.S.$0.45 per ton for each U.S.$1.00 increase in the lagged Urals blend price when the lagged Urals blend price is between U.S.$146.0 and U.S.$182.5 per ton, and by U.S.$0.65 per ton for each U.S.$1.00 increase in the lagged Urals blend price when the lagged Urals blend price is above U.S.$182.5 per ton.

 

Between January 1, 2003 and December 31, 2003, export duties on refined products were limited to 90% of the export duties on crude oil. This limitation was lifted effective from January 1, 2004.

 

From January 1, 2004, refined products excise tax rates increased to RR3,360 per metric ton of high octane gasoline, RR2,460 per metric ton of low octane gasoline, RR1,000 per metric ton of diesel fuel and RR2,732 per metric ton of motor fuel, and from January 1, 2005 the excise tax rates are RR3,629 per metric ton for high octane gasoline, RR2,657 per metric ton for low octane gasoline, RR1,080 per metric ton for diesel fuel and RR2,951 per metric ton for motor fuel.

 

From January 1, 2004, the maximum property tax rate was increased from 2% to 2.2%. However, local authorities set the actual tax rates. The property tax rate in Tatarstan is 2.2% for 2005 and was 2.2% in 2004.

 

In 2003, we were subject to value added tax, or VAT, of 20% on most purchases. VAT paid is recoverable against VAT received on domestic sales. Export sales 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. The VAT rate was reduced to 18% starting from January 1, 2004.

 

Current income taxes have also had a significant effect on our financial results, representing 41%, 24% and 28% of income before income taxes and minority interest in the years ended December 31, 2003, 2002 and 2001, respectively.

 

In the context of the significant regulatory changes related to Russia’s transition from a centrally planned to a market economy since the early 1990s 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 “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.”

 

RESULTS OF OPERATIONS

 

The following table shows certain key business and financial indicators:

 

     Year Ended December 31,

     2003

   % Change
on prior
year


   

2002

(as restated)


   % Change
on prior
year


   

2001

(as restated)


Crude oil production (millions of tons)

   24.9    0.1 %   24.9    0.2 %   24.9

Crude oil production (millions of barrels)

   177.3    0.1 %   177.0    0.2 %   177.0

Refining and processing throughput (millions of tons)

   8.4    (1.2 )%   8.5    16.2 %   7.3

Refining and processing throughput (millions of barrels)

   60    (1.6 )%   61    16.2 %   52

Cash flow from operating activities (in RR millions)

   16,421    61.7 %   10,153    (33.5 )%   15,259

Basic net income per share (RR)

   —      —       —      —       —  

Common

   6.93    11.1 %   6.24    (43.0 )%   10.94

Preferred

   7.82    9.8 %   7.12    (35.6 )%   11.05

Diluted net income per share (RR)

   —      —       —      —       —  

Common

   6.90    10.8 %   6.23    (42.9 )%   10.92

Preferred

   7.80    9.7 %   7.11    (35.5 )%   11.02

 

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Year Ended December 31, 2003 vs. Year Ended December 31, 2002.

 

Sales and other operating revenues

 

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

 

    

Year Ended

December 31,


     2003

  

2002

(as restated)


     (in RR millions)

Crude oil

   90,327    81,297

Refined products

   43,831    44,376

Petrochemicals

   11,583    9,920

Other sales

   9,076    9,890

Net banking interest income

   1,001    845
    
  

Total sales and other operating revenues

   155,818    146,328
    
  

 

Sales and other operating revenues totaled RR155,818 million for the year ended December 31, 2003, an increase of 6% compared to RR146,328 million for the year ended December 31, 2002. The increase is mainly attributable to an increase in crude oil sales and petrochemical sales, partially offset by a decrease in sales of refined products and other sales.

 

The table below provides an analysis of the changes in sales of crude oil:

 

    

Year Ended

December 31,


     2003

  

2002

(as restated)


Domestic sales of crude oil          

Revenues (in RR millions)

   11,346    11,901

Volume (thousand tons).

   6,153    5,402

Price (RR per ton)

   1,844    2,203
CIS export sales of crude oil          

Sales (in RR millions)

   9,470    11,510

Volume (thousand tons)

   2,637    4,077

Price (RR per ton)

   3,591    2,823
Non-CIS export sales of crude oil          

Sales (in RR millions)

   69,511    57,886

Volume (thousand tons)

   13,124    10,861

Price (RR per ton)

   5,296    5,330

 

Sales of crude oil increased by 11% to RR90,327 million for the year ended December 31, 2003 compared to RR81,297 million for the year ended December 31, 2002. This increase is attributable to a RR11,625 million increase in non-CIS export sales, partially offset by a RR555 million decrease in domestic sales and a RR2,040 million decrease in CIS export sales.

 

Domestic sales of crude oil decreased by 5% to RR11,346 million in 2003 from RR11,901 million in 2002, notwithstanding a 14% increase in volumes sold. Domestic prices were exceptionally low in the first half of 2003 and increased only at year-end. Domestic crude oil sales decreased to 7% of total sales and other operating revenues for the year ended December 31, 2003, as compared to 8% for the year ended December 31, 2002.

 

CIS export sales of crude oil decreased by 18% to RR9,470 million in 2003 from RR11,510 million in 2002. This decline was due to a 35% decrease in volumes sold, partially offset by a 27% increase in average selling prices to RR3,591 million for the year

 

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ended December 31, 2003 compared to RR2,823 million for the year ended December 31, 2002. CIS export sales decreased to 6% of total sales and other operating revenues for the year ended December 31, 2003, as compared to 8% for the year ended December 31, 2002.

 

Revenues from non-CIS export sales of crude oil increased by 20% to RR69,511 million in 2003 from RR57,886 million in 2002. The price per ton of non-CIS exports decreased because we increased volumes of crude oil shipped by rail in 2003. Rail shipments are more costly than transportation via Transneft because of the increased transportation costs borne by us. The 21% increase in volumes sold is attributable to the use of railway deliveries for crude oil in 2003. Prior to 2003, we did not engage in railway deliveries on a commercial basis. Non-CIS average crude oil prices remained relatively unchanged in 2003 as compared to 2002. Non-CIS export sales increased to 45% of total sales and other operating revenues for the year ended December 31, 2003, as compared to 40% for the year ended December 31, 2002.

 

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

 

     Year Ended December
31,


     2003

  

2002

(as restated)


Domestic sales of refined products          

Revenues (in RR millions)

   23,545    24,378

Volume (thousand tons)

   7,271    7,403

Price (RR per ton)

   3,238    3,293
CIS export sales of refined products          

Revenues (in RR millions)

   336    30

Volume (thousand tons)

   63    7

Price (RR per ton)

   5,333    4,305
Non-CIS export sales of refined products          

Revenues (in RR millions)

   19,950    19,968

Volume (thousand tons)

   4,523    5,216

Price (RR per ton)

   4,411    3,829

 

Sales of refined products amounted to RR43,831 million for the year ended December 31, 2003 compared to RR44,376 million for the year ended December 31, 2002, a 1% decrease. This slight decrease was primarily due to a decrease in the volume of refined products sold domestically, partially offset by an increase in both the price and volume of CIS export sales. Refined products that we sell are primarily gasoline, fuel oil, diesel fuel and naphtha. Sales of refined products decreased to 28% of total sales and other operating revenues in 2003, from 31% in 2002.

 

Domestic sales of refined products decreased by 3%, to RR23,545 million, in 2003 from RR24,378 million in 2002 due to the combined effects of a 2% decrease in sales volumes and a 2% decrease in prices. Average selling prices decreased due to a shift in the mix of products to heavier, generally less expensive refined products than in 2002. The share of light refined products, especially gasoline, decreased due to a 50% decline in processing throughput at the Moscow refinery of our products, from 2,968 thousand tons in 2002 to 1,494 thousand tons in 2003. This decrease was partially offset by a 22% increase in refining throughput at the Nizhnekamsk refinery, from 4,992 thousand tons in 2002 to 6,081 thousand tons in 2003. Domestic sales of refined products decreased to 15% of our total sales and other operating revenues in 2003, as compared to 17% in 2002.

 

CIS export sales of refined products increased 1,020%, to RR336 million, in 2003 from RR30 million in 2002 primarily due to sales to new customers in Belarus and Kazakhstan.

 

Non-CIS export sales of refined products decreased slightly, to RR19,950 million in 2003, from RR19,968 million in 2002, due to a 13% decline in volumes sold, which was largely offset by a 15% increase in average selling price per ton. The decline in volumes sold was due to decreased processing throughput at the Moscow refinery. Non-CIS export sales of refined products decreased slightly as a percentage of our total sales and other operating revenues, to 13% in 2003, as compared to 14% in 2002.

 

Sales of petrochemical products increased by 17% to RR11,583 million in 2003, from RR9,920 million in 2002. The increase was primarily attributable to a 17% increase in tire sales, to RR10,302 million in 2003, from RR8,768 million in 2002. This revenue was attributable to both increased prices and higher volumes of tires sold. We increased production of tires by 9% to 10.7 million tires in 2003 from 9.8 million tires in 2002. The average selling price increased due to an increase in CIS and non-CIS export sales of tires, where average tire prices are higher than in Russia. Sales of petrochemicals constituted 7% of our total sales and other operating revenue in 2003, unchanged from 2002.

 

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Other sales decreased by 8%, to RR9,076 million, in 2003 from RR9,890 million in 2002. This decrease is attributable to our ongoing strategy to reduce the number and level of our non-core activities. Other sales primarily comprise sales of materials and equipment and various field services provided by our production subsidiaries to third parties (such as drilling, lifting, construction, repairs and geophysical works). Other sales constituted 6% of our total sales and other operating revenue in 2003, down from 7% in 2002.

 

Net banking interest income increased by 18%, to RR1,001 million, in 2003 from RR845 million in 2002, largely as a result of an increase in the volume of our banking activities. Interest income increased 28%, to RR2,859 million, in 2003 from RR2,236 million in 2002 due to an increase in banking loans and advances to customers from RR11,352 million as of December 31, 2002 to RR20,146 million as of December 31, 2003, partially offset by a decrease in weighted average interest rates. Interest expense increased by 34%, to RR1,858 million, in 2003 from RR1,391 million in 2002 due to the issuance of Eurobonds with a face value of $125 million by Bank Zenit and an increase in term and demand banking customer deposits.

 

Costs and other deductions

 

A breakdown of costs and other deductions is provided in the following table.

 

     Year Ended December 31,

 
     2003

   

2002

(as restated)


 
     (in RR millions)  

Operating

   31,799     36,389  

Purchased oil and refined products

   28,997     28,372  

Exploration

   812     463  

Transportation

   7,635     5,683  

Selling, general and administrative

   15,499     16,031  

Bad debt charges and credits, net

   (262 )   (261 )

Depreciation, depletion and amortization

   8,850     7,541  

Loss on disposals of property, plant and equipment and impairment of investments

   2,325     851  

Taxes other than income taxes

   43,378     31,988  

Maintenance of social infrastructure

   279     199  

Transfer of social assets

   2,162     1,293  
    

 

Total costs and other deductions

   141,474     128,549  
    

 

 

Operating expenses decreased by 13%, to RR31,799 million, in 2003 from RR36,389 million in 2002. Operating expenses include the following main categories: lifting expenses connected with extraction of crude oil; refining and processing expenses; cost of petrochemical products; cost of materials other than oil and gas refined products purchased for re-sale; and other direct costs. Lifting expenses connected with the extraction of crude oil decreased by approximately RR1,200 million due to cost-saving programs implemented by management. Refining expenses decreased due to changes in excise tax legislation. Prior to January 1, 2003, producers of refined products were responsible for paying excise tax, with the effect that excise tax of RR1,318 million was invoiced to us by external refineries in 2002. We included this cost in operating expenses. From January 1, 2003, excise tax is paid by sellers of refined products, as a result of which we now include excise tax within taxes other than income tax. Processing fees paid to external refineries decreased by approximately RR270 million in 2003, primarily due to decreased processing at the Moscow refinery. In addition, cost of other sales decreased as we continue to reduce our non-core activities, such as utilities and communication services, and sales of materials. Operating expenses decreased to 20% of total sales and other operating revenues in the year ended December 31, 2003 as compared to 25% in the year ended December 31, 2002.

 

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A summary of purchases of oil and refined products for 2003 and 2002 is as follows:

 

     Year Ended December
31,


     2003

  

2002

(as restated)


Purchases of refined products (in RR millions)

   14,158    14,337

Volume (thousand tons)

   4,086    4,490

Average price per ton (RR)

   3,465    3,193

Purchases of crude oil (in RR millions)

   14,839    14,035

Volume (thousand tons)

   5,310    4,679

Average price per ton (RR)

   2,795    2,999
    
  

Total purchased oil and refined products (in RR millions)

   28,997    28,372
    
  

 

Expenses related to the purchase of oil and refined products totaled RR28,997 million for the year ended December 31, 2003, an increase of 2%, compared to RR28,372 million for the year ended December 31, 2002. Purchases of refined products decreased by 1%, to RR14,158 million, in 2003 from RR14,337 million in 2002, due to a 9% decrease in the volume of refined products purchased, partially offset by a 9% increase in the average price per ton. Purchases of crude oil increased by 6%, to RR14,839 million, in 2003 from RR14,035 million in 2002, as a result of a 13% increase in volumes purchased partially offset by a 7% decrease in purchase price. Purchases of crude oil and refined products represented 19% of our total sales and other operating revenues in 2003, unchanged from 2002. These purchases are related to swap transactions with other Russian oil companies whereby we undertake to deliver our oil to certain refineries in Russia or the CIS in exchange for delivery of oil of equivalent value to refineries in or adjacent to regions of Russia where we have retail operations. The total volume of such swap transactions amounted to 0.4 million tons, 2.1 million tons, 2.7 million tons and 2.5 million tons in 2004, 2003, 2002 and 2001, respectively.

 

Exploration expenses increased by 75% to RR812 million in 2003 from RR463 million in 2002. This increase is due to increased exploration activities in Kalmykia, the Nenetsk Autonomous District, the Orenburg Region and the Samara Region. Exploration expenses represented less than 1% of our total sales and other operating revenues in both 2003 and 2002.

 

Transportation expenses increased by 34%, to RR7,635 million, in 2003 from RR5,683 million in 2002. This increase was primarily due to an increase in Transneft’s transportation tariffs as well as increased export sales of crude oil. Additionally, in 2003 we significantly increased export crude oil sales by railway in order to overcome restrictions on crude oil exports through the Transneft pipeline system. Transportation expenses are incurred in the delivery of crude oil and refined products to final customers and to refineries for processing. Transportation expenses constituted 5% of our total sales and other operating revenues in 2003, as compared to 4% in 2002.

 

Selling, general and administrative expenses decreased by 3%, to RR15,499 million, in 2003 from RR16,031 million in 2002. Certain selling, general and administrative expenses are by nature fixed costs and are not directly attributable to production, such as general business costs, insurance, advertising, management expenses, legal fees, consulting, audit services and others. Selling, general and administrative expenses constituted 10% of our total sales and other operating revenues in 2003, a decrease from 11% in 2002.

 

Bad debt charges and credits, net remained virtually unchanged, resulting in a benefit of RR262 million in 2003, compared with a benefit of RR261 million in 2002.

 

Depreciation, depletion and amortization increased by 17%, to RR8,850 million, in 2003 from RR7,541 million in 2002. The increase is attributable to continued investments in property, plant and equipment, including oil and natural gas properties, retail gas stations and tank cars. Additional charges were incurred as a result of our adoption of SFAS 143, effective January 1, 2003, which requires us to record future costs that are associated with future asset retirement obligations, and the use of capital leases in 2003. See “—Critical Accounting Policies and Estimates.” Depreciation, depletion and amortization constituted 6% of our total sales and other operating revenues in 2003, as compared to 5% in 2002.

 

Loss on disposals of property, plant and equipment and impairment of investments increased by 173%, to RR2,325 million, in 2003 from RR851 million in 2002. This increase is partially due to a RR1,197 million write off of long-term notes receivable, issued by the Republican State Unitary Company “Nedoimka,” which we do not consider to be recoverable. See “Item 7—Major Shareholders and Related Party Transactions—Related Party Transactions” and Note 10 to our audited consolidated financial statements. Losses on disposals and impairment in 2003 was also partially due to losses on disposals of subsidiaries not considered to be part of our core operations. Loss on disposals and impairments represented less than 1% of our total sales and other operating revenues in 2003 and 2002.

 

Taxes other than income taxes increased by 36%, to RR43,378 million, in 2003 from RR31,988 million in 2002. Export duties increased by 53%, to RR18,174 million, from RR11,890 million, and unified production tax increased by 17%, to RR19,818

 

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million from RR16,940 million. The rates of export duties and the unified natural resources production tax are linked to crude oil market prices, which increased in 2003 compared with 2002. Excise tax increased to RR2,031 million from RR104 million as a result of a change in tax legislation. As of January 1, 2003, payments of excise tax were shifted from the producers of refined products to sellers of refined products to end customers. Excise tax is accrued on each intermediary re-sale of refined products and subsequently recovered subject to certain conditions set by legislation. Road users tax was abolished effective January 1, 2003. In 2002, our road users tax burden amounted to RR1,079 million. Taxes other than income tax increased to 28% of total sales and other operating revenues in the year ended December 31, 2003 compared to 22% in the year ended December 31, 2002. Tax penalties and interest increased by 535%, to RR686 million, in 2003, from RR108 million in 2002, partially resulting from our recognition of restructured tax interest on VAT related to prior years (RR501 million) and partially from a claim for back taxes from the federal tax authorities, received in April 2005. See “—Developments in 2004 and 2005” under this Item. This restructured tax interest may be written-off if we are able to repay the restructured VAT payable. We expect to repay all the restructured VAT payable in accordance with the schedule agreed. See “Item 3—Key Information—Risk Factors—Risks Relating to the Russian Legal System and Russian Legislation.”

 

Maintenance of social infrastructure expenses increased by 40%, to RR279 million, in 2003 from RR199 million in 2002. This increase was mainly due to celebrations of the fiftieth anniversary of Almetyevsk and the sixtieth anniversary of discovery of crude oil in Tatarstan. Maintenance of social infrastructure remained well below 1% of total sales and other operating revenues in both 2003 and 2002.

 

Expenses arising from the transfer of social assets increased by 67%, to RR2,162 million, in 2003 from RR1,293 million in 2002. This increase reflects our continued divestiture of social assets. The timing of these transfers is dependent on discussions with the government of Tatarstan. Expenses related to the transfer of social assets constituted 1% of total sales and other operating revenues in 2003 and 2002.

 

Production costs per barrel

 

Below is an analysis of our production costs per barrel:

 

     Year Ended December 31,

    
     2003

   2002

   Change

Production costs (U.S.$ per barrel)(1)               

Lifting expenses

   2.46    2.47    0%

General and administrative expenses

   1.12    1.11    1%

Transportation expenses

   1.01    0.56    80%

Total taxes other than income tax

   6.05    4.39    38%

Depreciation, depletion and amortization

   1.28    1.02    25%
    
  
  
Total production costs per barrel    11.92    9.55    25%
    
  
  

(1) The conversion factors are 1 ton = 7.123 barrels; U.S.$1 = RR30.69 in 2003; and U.S.$1 = RR31.35 in 2002.

 

Lifting and general and administrative expenses are expenses related to oil and natural gas production and incurred by our oil and natural gas producing divisions and subsidiaries. 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 natural gas reserves.

 

Our direct operating costs for crude oil extraction, or lifting expenses, averaged U.S.$2.46 per barrel in 2003 compared to U.S.$2.47 per barrel in 2002. Lifting expenses decreased slightly due to a cost-saving program implemented by our management, partially offset by the real appreciation of the Russian ruble against the U.S. dollar. Lifting expenses exclude liabilities accrued in accordance with SFAS 143.

 

General and administrative expenses include expenses incurred by our production divisions relating to crude oil production. The 1% increase in general and administrative expenses per barrel of produced oil was primarily the result of increased overhead of our production divisions.

 

The 80% increase in transportation expenses per barrel of produced oil was primarily due to the combined effect of increases in Transneft’s tariffs and in non-CIS export sales of crude oil, including railway deliveries.

 

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The increase in total taxes other than income tax per barrel of produced oil was primarily the result of increases in export duty and the unified natural resources production tax, which are linked to market crude oil prices. The effective unified natural resources production tax increased by 27% to U.S.$3.64 per barrel in 2003 from U.S.$2.86 per barrel in 2002, while the export duty rate per barrel increased by 72% to U.S.$2.38 per barrel in 2003 from U.S.$1.38 per barrel in 2002.

 

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 and the adoption of SFAS 143 effective January 1, 2003.

 

Other income and expenses

 

Other income (expenses) totaled RR313 million for the year ended December 31, 2003, a decrease of 79% compared to RR1,525 million for the year ended December 31, 2002. As a percentage of total sales and other operating revenues, other income accounted for less than 1% during 2003 and 2% during 2002.

 

Earnings from equity investments decreased by 32% to RR101 million in 2003 from RR148 million in 2002 due to lower income received from our equity affiliates and joint ventures in 2003.

 

The foreign exchange loss decreased by 78% to RR225 million in 2003 from RR1,042 million in 2002. This was due to the appreciation of the ruble against the U.S. dollar.

 

There was no monetary gain or loss in 2003 because Russia’s economy ceased to be considered hyperinflationary from January 1, 2003. Monetary loss amounted to RR871 million in 2002.

 

Interest expense decreased by 3% to RR827 million in 2003 from RR855 million in 2002, which is explained by a decrease in interest expense, partially offset by a decrease in interest income to RR303 million in 2003 from RR804 million in 2002. The decrease in net interest expense is due to debt repayment and appreciation of the ruble in 2003.

 

Other income decreased 46% to RR1,961 million in 2003 from RR3,599 million in 2002. Other income includes other net banking expense, which increased by 102% to RR1,362 million in 2003 from RR673 million in 2002. Other net banking expense primarily consists of other income and expenses connected with Bank Zenit and Bank Devon-Credit: income from commissions (RR607 million), gains from sales and purchase of securities net of provisions (RR118 million), net gains from dealing in foreign currencies (RR287 million), operating expenses related to banking activities (RR1,881 million), and other items. Other net banking expense increased primarily due to increased salary costs. In 2003, we recorded a gain of RR2,251 million as a result of offsetting our income tax, VAT and unified natural resources production tax liability against the benefit to us of the favorable outcome of legal proceedings we filed against the Tax Ministry of Tatarstan in December 2002. Other income in 2002 primarily resulted from the redemption of Tatneft Finance Eurobonds, which resulted in a net realized holding gain of RR3,408 million.

 

Income Taxes

 

Total income tax expense decreased by 15% to RR4,582 million for the year ended December 31, 2003 from RR5,363 million for the year ended December 31, 2002. Current income taxes increased by 28% to RR6,070 million in 2003 from RR4,743 million in 2002 partially because we recognized a higher statutory profit in 2003 and partially due to a claim for back taxes from the federal tax authorities, received in April 2005, but which was partially booked in 2003. See “—Developments in 2004 and 2005” under this Item. Deferred taxes totaled a benefit of RR1,488 million in 2003 compared to a RR620 million expense in 2002 resulting from the restatement of our deferred tax benefit in 2002. See “—Restatement of Previously Issued Financial Statement” under this Item.

 

Minority interest

 

Benefits attributable attributable to minority interest amounted to RR63 million in 2003 compared to an expense of RR471 million in 2002, reflecting losses incurred by our subsidiaries which are not wholly-owned by us, and disposal of certain of our subsidiaries in 2003, including OAO Tatincom-T. See “Item 4—Information on the Company—History and Development.”

 

Year Ended December 31, 2002 vs. Year Ended December 31, 2001

 

Sales and other operating revenues

 

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

 

     Year Ended December 31,

    

2002

(as restated)


  

2001

(as restated)


     (in RR millions)

Crude oil

   81,297    95,223

Refined products

   44,376    43,859

Petrochemicals

   9,920    4,133

Other sales

   9,890    12,296

Net banking interest income

   845    1,350
    
  
Total sales and other operating revenues    146,328    156,861
    
  

 

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Sales and other operating revenues totaled RR146,328 million for the year ended December 31, 2002, a decrease of 7% compared to RR156,861 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:

 

     Year Ended December 31,

    

2002

(as restated)


  

2001

(as restated)


Domestic sales of crude oil

         

Revenues (in RR millions)

   11,901    32,371

Volume (thousand tons).

   5,402    10,664

Price (RR per ton)

   2,203    3,036

CIS export sales of crude oil

         

Sales (in RR millions)

   11,510    6,997

Volume (thousand tons)

   4,077    1,716

Price (RR per ton)

   2,823    4,078

Non-CIS export sales of crude oil

         

Sales (in RR millions)

   57,886    55,855

Volume (thousand tons)

   10,861    10,065

Price (RR per ton)

   5,330    5,549

 

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