Edgar Filing: O A O TATNEFT

OAO TATNEFT

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

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

¨	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


			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

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

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.

iii

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

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;

•

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.

PART I

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

This Item is not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

This Item is not applicable.

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.


	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


	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.”

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 1/100^th 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.

CAPITALIZATION AND INDEBTEDNESS

This Item is not applicable.

REASONS FOR THE OFFER AND USE OF PROCEEDS

This Item is not applicable.

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.

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

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.

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:

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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.

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:

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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.

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;

•

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.

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.

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

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:

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limiting our access to additional financing;

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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

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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

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.

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.

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.

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:

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unexpected drilling conditions;

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pressure or irregularities in formations;

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equipment failures or accidents;

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

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

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pipe or cement failures;

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casing collapse; and

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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.

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.

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

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:

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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.

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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.

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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.

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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

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:

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

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market uncertainty;

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weather conditions;

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domestic and foreign governmental regulations;

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prices and availability of alternative fuels;

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prices and availability of new technologies;

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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;

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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;

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

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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:

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

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interpretation of geological and geophysical data;

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the assumed effects of regulations adopted by governmental agencies;

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assumptions concerning future percentages of international sales;

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assumptions concerning future oil and natural gas prices;

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capital expenditures; and

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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:

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

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the production and operating costs incurred;

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the amount and timing of future development expenditures; and

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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:

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modify operations;

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install pollution control equipment;

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perform site clean-ups;

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curtail or cease certain operations; or

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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.

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.

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

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.

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.

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

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%.

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:

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exploration and production;

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refining and marketing;

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petrochemicals; and

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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

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:

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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.

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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.

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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.

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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.

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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.”

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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.”

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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.

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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.”

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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%.

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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.

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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.

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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.

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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.”

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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.

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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

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.”

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.

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

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.

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.”

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;

•

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.

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.

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

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

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

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.

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.

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

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.

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.

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.

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

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.

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

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%.

•

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

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.

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:

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enhancing oil and natural gas production potential;

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

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

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improving efficiencies in utilization of personnel; and

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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.

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:

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public transport;

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construction and installation works;

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repair and maintenance of our conventional pumping units;

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downhole logging works;

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chemical analytical works; and

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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.”

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:

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

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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.

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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.

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.

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.

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.

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

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.

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	April 1, 2005			2004			2003			2002			2001			Taxable base
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.

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

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

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.

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.

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

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.

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

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

Substantially all of our CIS sales of crude oil in the periods under review were to the Kremenchug oil refinery in Ukraine. CIS export sales of crude oil increased by 64%, to RR11,510 million, in 2002 from RR6,997 million in 2001. This increase was attributable to an increase in supplies to the Kremenchug refinery. CIS average crude oil prices per ton decreased to RR2,823 for the year ended December 31, 2002, or by 31%, compared to RR4,078 for the year ended December 31, 2001, due to a decline in CIS market prices. As a percentage of total sales and other operating revenues, CIS export sales increased to 8% in 2002 from 4% in 2001.

Non-CIS export sales of crude oil totaled RR57,886 million for the year ended December 31, 2002, an increase of 4%, compared to RR55,855 million for the year ended December 31, 2001. Sales volumes increased to 10,861 thousand tons in 2002 compared to 10,065 thousand tons in 2001, or by 8%. Non-CIS average crude oil prices per ton decreased to RR5,330 in 2002 from RR5,549 per ton in 2001, or by 4%, as a result of a general change in world crude oil prices in 2002. As a percentage of total sales and other operating revenues, non-CIS export sales increased to 40% in 2002 from 36% in 2001.

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


	Year Ended December 31,
	2002 (as restated)	2001 (as restated)
Domestic sales of refined products
Revenues (in RR millions)	24,378	18,971
Volume (thousand tons)	7,403	6,591
Price (RR per ton)	3,293	2,878
CIS export sales of refined products
Revenues (in RR millions)	30	705
Volume (thousand tons)	7	121
Price (RR per ton)	4,305	5,823
Non-CIS export sales of refined products
Revenues (in RR millions)	19,968	24,183
Volume (thousand tons)	5,216	6,737
Price (RR per ton)	3,829	3,590

Sales of refined products amounted to RR44,376 million for the year ended December 31, 2002 compared to RR43,859 million for the year ended December 31, 2001, a 1% increase. This slight increase in refined product sales was due primarily to two offsetting factors: a 14% increase in domestic prices and a decrease in sales to Europe. Refined products that we sell are primarily gasoline, fuel oil, diesel fuel and naphtha. As a percentage of total sales and other operating revenues, sales of refined products increased to 30% in 2002 from 28% in 2001. Production of our own refined products represents a new business direction for us, which we intend to expand further in the future.

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

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

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

Other sales decreased by 20% to RR9,890 million in 2002 from RR12,296 million in 2001. Other sales include revenues from sales of materials and equipment, various field services provided by our production subsidiaries to third parties (such as drilling, lifting, construction, repairs and geophysical works) and revenues from some of our specialized subsidiaries for communication services and insurance fees. The decrease of other sales is due to our strategy to reduce the number and level of our non-core activities. Other sales constituted 7% of our total sales and other operating revenue in 2002, down from 8% in 2001.

Net banking interest income decreased by 37%, to RR845 in 2002 million from RR1,350 million in 2001. Net banking interest consists of interest income of RR2,236 million and interest expense of RR1,391 million, primarily related to the operations of Bank Zenit. Interest expense increased by RR 801 million as a result of an increase in debt securities issued and customer deposit accounts, partially offset by an increase of RR296 million in interest income.

Costs and other deductions

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


	Year Ended December 31,
	2002 (as restated)		2001 (as restated)
	(in RR millions)
Operating	36,389		31,297
Purchased oil and refined products	28,372		34,104
Exploration	463		839
Transportation	5,683		5,183
Selling, general and administrative	16,031		17,282
Bad debt charges and credits, net	(261	)	1,027
Depreciation, depletion and amortization	7,541		6,139
Loss on disposals of property, plant and equipment and impairment	851		2,502
Taxes other than income taxes	31,988		33,373
Maintenance of social infrastructure	199		491
Transfer of social assets	1,293		593

Total costs and other deductions	128,549		132,830

Operating expenses increased by 16% to RR36,389 million in 2002 from RR31,297 million in 2001. Operating expenses include the following main categories: lifting expenses connected with extraction of crude oil, refining expenses, cost of petrochemical products, cost of materials other than oil and natural gas, refined products purchased for resale and other direct costs. The increase in operating expenses is primarily attributable to the full-year consolidation of Nizhnekamskshina, whose operating expenses increased by approximately RR5,600 million to RR8,184 million. Refining expenses also increased by RR1,031 million due to the increase in refining volumes. These increases were partially offset by a reduction in crude oil lifting costs in the amount of RR2,854 million. Operating expenses as a percentage of total sales and other operating revenues increased to 25% in 2002 from 20% in 2001.

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


	Year Ended December 31,
	2002	2001
Purchases of refined products (in RR millions)	14,337	13,091
Volume (thousand tons)	4,490	6,171
Average price per ton (RR)	3,193	2,121
Purchases of crude oil (in RR millions)	14,035	21,013
Volume (thousand tons)	4,679	6,361
Average price per ton (RR)	2,999	3,303

Total purchased oil and refined products (in RR millions)	28,372	34,104

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

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

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

Selling, general and administrative expenses decreased by 7% to RR16,031 million in 2002 from RR17,282 million in 2001. Certain selling, general and administrative expenses are by nature fixed costs, which are not directly attributable to production, such as general business costs, insurance, advertising, management expenses, legal fees, consulting and audit services. The decrease was largely due to a RR1,716 million decrease in charity and sponsorship expenses, largely offset by an increase in insurance costs to RR3,351 million in 2002 from RR2,088 million in 2001, resulting from the combined effect of increased tariff rates and scope of insurance coverage. These expenses constituted 11% of our total sales and other operating revenues in 2002.

Bad debt charges and credits, net changed to a RR261 million release in 2002 from a RR1,027 million expense in 2001, primarily resulting from a recovery of certain bad debts during 2002.

Depreciation, depletion and amortization totaled RR7,541 million for the year ended December 31, 2002, an increase of 23% compared to RR6,139 million for the year ended December 31, 2001. The increase was attributable to the combined effect of the full-year consolidation of Nizhnekamskshina, which became our subsidiary effective from September 30, 2001, and continued investments into property, plant and equipment, especially our retail network of service stations. These expenses constituted 5% of our total sales and other operating revenues in 2002, compared to 4% in 2001.

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

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

Maintenance of social infrastructure expenses totaled RR199 million for the year ended December 31, 2002, a decrease of 59% from RR491 million for the year ended December 31, 2001. Social infrastructure expenses include mainly agricultural support costs and are subject to variations depending on social needs. The decrease was primarily attributable to reduction in agriculture support and city reconstruction costs. As a percentage of total sales and other operating revenues, maintenance of social infrastructure expense remained below 1% in both 2002 and 2001.

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

Production costs per barrel

Below is an analysis of our production costs per barrel:


	Year Ended December 31,
	2002	2001	Change
Production costs (U.S.$ per barrel)⁽¹⁾
Lifting expenses	2.47	2.74	(9.9)%
General and administrative expenses	1.11	1.01	9.9 %
Transportation expenses	0.56	0.45	24.4 %
Total taxes other than income tax	4.39	3.18	38.1 %
Depreciation, depletion and amortization	1.02	0.87	17.2 %

Total production costs per barrel	9.55	8.25	15.8%

(1)	The conversion factors are 1 ton = 7.123 barrels; U.S.$1 = RR31.35 in 2002, and U.S.$1 = RR29.17 in 2001.

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

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

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

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

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

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

Other income and expenses

Other income (expenses) totaled RR1,525 million for the year ended December 31, 2002, an increase of 169% compared to RR567 million for the year ended December 31, 2001. Other income accounted for 1% and less than 1% of total sales and other operating revenues during 2002 and 2001, respectively.

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

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

Interest expense net of interest income decreased by 70% to RR855 million in 2002 from RR2,875 million in 2001, primarily due to a decrease of interest income to RR804 million in 2002 from RR1,517 million in 2001. This decrease in interest income was due to reduced holdings of short-term investments.

Other income increased by 604% to RR3,599 million in 2002 from RR511 million in 2001. The increase was primarily driven by the redemption of Tatneft Finance Eurobonds, resulting in a net realized holding gain of RR3,408 million. In 2001, these gains were partially recognized in comprehensive income as unrealized holding gains on available-for-sale securities. Other income includes other net banking expense, which increased by 28% to RR673 million in 2003 from RR525 million in 2001. Other net banking expense primarily consists of other income and expenses connected with Bank Zenit and Bank Devon-Credit: income from commissions (RR163 million), gains from sales and purchase of securities net of provisions (RR203 million), loan loss provision (RR69 million), net gains from dealing in foreign currencies (RR281 million), operating expenses related to banking activities (RR1,359 million), and other items. Other net banking expense increased primarily due to an increase in operating expenses related to banking activities by 35% to RR1,359 million in 2002 from RR1,005 million in 2001, primarily attributable to increased staff costs.

Income taxes

Total income tax (benefit) expense totaled RR5,363 million for the year ended December 31, 2002, compared to a (RR1,244) million benefit for the year ended December 31, 2001. Current income taxes totaled RR4,743 million for the year ended December 31, 2002, a decrease of RR2,329 million, or 33%, compared to RR7,072 million for the year ended December 31, 2001. The decrease was attributable to lower statutory profit recognized by the Company in 2002 and lower tax rates. Deferred taxes totaled RR620 million for the year ended December 31, 2002 compared to a benefit of (RR8,316) million for the year ended December 31, 2001. The primary reason for the decrease in deferred income taxes was the change in the Russian income tax rate from 35% to 24% effective from January 1, 2002.

Minority interest

Expense attributable to minority interest decreased 72% from RR1,698 million in 2001 to RR471 million in 2002, reflecting decreased income earned by our subsidiaries that are not wholly-owned. A significant portion of the decrease is attributable to our increased ownership in Bank Devon-Credit (up to 92%) and decreased net income of our banks in 2002, compared to 2001. In 2002, we also reduced operations with certain subsidiaries with significant minority interest, which contributed to the decline of minority interest.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our Consolidated Statements of Cash Flows for periods ending prior to January 1, 2003 reflect the effects of operating in a hyperinflationary environment, in which financial statements are adjusted for price level changes, and the effects of currency fluctuations on our results. The amounts in the Consolidated Statements of Cash Flows for periods prior to January 1, 2003 show actual nominal cash flows restated to the December 31, 2002 purchasing power of the ruble. The working capital movements for periods ending prior to January 1, 2003 represent the actual nominal increases or decreases in working capital balances at the date they actually occurred, restated to the December 31, 2002 purchasing power of the ruble. Accordingly, this presentation removes the effects of inflation and foreign exchange on us, and presents this information on inflation and foreign exchange separately in the cash flow statement. Amounts for periods starting from January 1, 2003 are presented in nominal terms.

The following table shows certain key financial indicators:


	Year ended December 31,
	2003	2002 (as restated)
	(RR millions, except current ratio)
Total assets	262,717	226,288
Total liabilities	108,436	86,067
Current ratio	1.36	1.35
Total bank loans payable	26,009	31,240
Shareholders’ equity	149,180	135,152

At December 31, 2003, our cash holdings consisted of cash, cash equivalents, and restricted cash, including U.S. dollar-denominated amounts of RR2,888 million (U.S.$98 million), of which holdings of RR300 million (U.S.$10 million) were restricted.

As of December 31, 2003, our working capital amounted to RR19,267 million, compared to RR16,763 million as of December 31, 2002. As of December 31, 2003, our current ratio increased by 1% compared to December 31, 2002. Our current ratio is calculated as current assets divided by current liabilities. The increase in our working capital is primarily attributable to an increase in amounts due from related parties and loans receivable partially offset by an increase in banking customer deposits and notes payable.

We believe that our working capital is sufficient for our present requirements.

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


	Year Ended December 31,
	2003		2002 (as restated)		2001 (as restated)
	(in RR millions)
Net cash provided by operating activities	16,421		10,153		15,259
Barter settlements provided by operating activities	1,126		2,425		4,227

Net cash and barter settlements provided by operating activities	17,547		12,578		19,486


	Year Ended December 31,
	2003		2002		2001
	(in RR millions)
Net cash used for investing activities	(10,614	)	(8,002	)	(17,512	)
Barter settlements of property, plant and equipment	(1,126	)	(2,425	)	(4,227	)

Net cash and barter settlements used for investing activities	(11,740	)	(10,427	)	(21,739	)


	Year Ended December 31,
	2003		2002		2001
	(in RR millions)
Net cash provided by (used for) financing activities	(4,424	)	325		4,024

In 2003 and 2002, the major sources of our liquidity were cash flows from operating activities and funds borrowed under credit facilities described under “—Debt” below.

Net cash and barter settlements provided by operating activities

Net cash and barter settlements provided by operating activities increased by 40%, to RR17,547 million, in 2003 from RR12,578 million in 2002. Despite the lower income before cumulative effect of change in accounting principles in 2003, changes in working capital exercised a positive effect on net cash provided by operating activities.

Our net cash and barter settlements provided by operating activities decreased by 35% from RR19,486 million at December 31, 2001 to RR12,578 million at December 31, 2002. This decrease occurred primarily due to a decrease in sales and other operating revenues.

Net cash and barter settlements used for investing activities

Net cash and barter settlements used for investing activities increased by 13% to RR11,740 million in 2003 from RR10,427 million in 2002, primarily due to the fact that our proceeds from disposal of investments decreased by 69% in 2003 as compared to 2002.

Net cash and barter settlements used for investing activities were RR10,427 million for the year ended December 31, 2002, compared to RR21,739 million for the year ended December 31, 2001, a decrease of 52%. The main reason for this decrease was the decrease in cash used for investing activities primarily as a result of lower capital expenditures on property, plant and equipment. Capital expenditures on property, plant and equipment declined to RR13,100 million in 2002 from RR20,583 million in 2001.

Net cash (used for) provided by financing activities

Net cash (used for) provided by financing activities totaled RR(4,424) million in 2003, a decrease from net cash provided by financing activities of RR325 million in 2002. The decrease was due to net repayment of short-term and long-term debt of RR3,320 million and repayment of capital lease obligations of RR1,221 million in 2003 compared to RR1,142 million in net proceeds from debt in 2002.

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

Capital Expenditures

We make some of our capital expenditures using consideration other than cash. In the years ended December 31, 2003 and 2002, our operating cash flows exceeded our cash capital expenditures and were above our combined cash and non-cash capital expenditures. In the year ended December, 31, 2001 our operating cash flows exceeded our cash capital expenditure, but were not sufficient to cover our combined cash and non-cash capital expenditures.

Following is a table of our cash and non-cash capital expenditures:


	Year Ended December 31,
	2003	2002	2001
	(in RR millions)
Cash capital expenditures	12,679	13,100	20,583
Effect of adoption of SFAS 143	9,912	—	—
Capitalization of leases	2,223	—	—
Mutual cancellations and barter settlements	1,126	2,425	4,227

Total capital expenditures	25,940	15,525	24,810

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

Following is a table of our capital expenditures by segment:


	Year Ended December 31,
	2003	2002	2001
	(in RR millions)
Exploration and production	21,320	10,519	18,824
Refining and marketing	2,766	3,576	5,027
Petrochemicals	1,768	818	939
Banking	86	612	20

Total capital expenditures	25,940	15,525	24,810

We had capital expenditures for 2004 of approximately RR10,800 million. Future capital expenditures are expected to be made principally on production development, drilling development and other equipment in order to maintain current crude oil production. In addition, we plan to continue to make investments in the Nizhnekamsk refinery, our single most significant current capital commitment, development of our retail gas station network and development of our petrochemicals operations, including upgrading production at Nizhnekamskshina. Our capital expenditures will be dependent on the sufficiency of cash flows. See “Item 4—Information on the Company.” Capital expenditures on social assets will continue to be substantial, although we believe they will be lower than in the past as a result of the implementation of our cost restructuring plans. See “Item 4—Information on the Company—Corporate Reorganization—Divestiture of Social Assets.”

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

We operate a central treasury function, initially through allocation of our budget, which is reviewed each month by our budget committee and the Board. Payments are the either classed as centralized, paid by Tatneft, or decentralized, paid directly by the relevant organizational department. Centralized payment requests are reviewed by the Chief Accountant and the Head of the Financial Department. Payments made by the organizational departments are overseen by the head of the relevant unit. Over 99% of all of our expenses are paid via centralized payments.

Debt

Our borrowings of short-term debt and long-term debt net of repayments of short-term debt and long-term debt were RR(3,320) million and RR(1,142) million for the periods ended December 31, 2003 and December 31, 2002, respectively. In 2003, we also repaid RR1,221 million in capital lease obligations. We had no capital lease obligation repayments in 2002.

The overall decline in our borrowings as reported in our financial statements resulted from improved financial results and cash flows during 2003.

The following table shows our borrowings at December 31, 2003 and 2002:


	At December 31,
	2003		2002
	(in RR millions, except for percentages)
Short-term debt
Fixed interest rate debt	7,561		8,559
Weighted average interest rates for fixed rate debt	7.51	%	9.7	%
Variable interest rate debt	884		1,947
Weighted average interest rates for variable rate debt	5.72	%	5.4	%

Total short-term borrowings	8,445		10,506

Foreign currency-denominated short-term debt	4,335		5,565
Ruble-denominated short-term debt	4,110		4,941

Total short-term borrowings	8,445		10,506

Plus: Current portion of long-term debt	4,768		6,112

Total short-term debt obligations	13,213		16,618

Long-term debt
Fixed interest rate debt	4,577		626
Weighted average interest rates for fixed rate debt	9.71	%	5.97	%
Variable interest rate debt	12,987		20,108
Weighted average interest rates for variable rate debt	5.3	%	5.3	%

Total long-term borrowings	17,564		20,734

Foreign currency denominated long-term debt	15,902		20,162
Ruble-denominated long-term debt	1,662		572

Total long-term borrowings	17,564		20,734

Less: current portion of long-term debt	(4,768	)	(6,112	)

Total long-term debt obligations	12,796		14,622

Total debt	26,009		31,240

At December 31, 2003 and 2002, our long-term debt, including current maturities, amounted to RR17,564 million and RR20,734 million, and our short-term debt less the current portion of long-term debt amounted to RR8,445 million and RR10,506 million, respectively. In the following paragraphs we provide a summary of our outstanding debt. For a more comprehensive information about our debt see Note 12 to our audited consolidated financial statements included in this annual report.

Short-term foreign currency-denominated debt. At December 31, 2003, our short-term foreign currency-denominated debt amounted to RR4,335 million and included loans from Winter Bank, Credit Suisse Zurich and interbank loans.

In July 2001, we entered into a RR1,042 million (U.S.$30 million) loan agreement with Winter Bank. This unsecured loan bears an interest rate of 6 month LIBOR plus 4.5% per annum. The loan must be repaid in full every six months and may be renewed immediately for an additional six months during the three year term of the commitment. The loan was fully repaid in 2004. The amount of the loan outstanding as of December 31, 2003 was RR884 million.

In November 2003, we entered into a RR3 million (U.S.$0.1 million) loan agreement with Alesworth Ltd. The loan bears interest at 16% per annum and was repaid in November 2004. The amount of the loan outstanding as of December 31, 2003 was RR3 million.

In December 2003, we entered into a RR1,034 million (U.S.$35 million) one month revolving overdraft facility with Credit Suisse Zurich. The monthly revolving loan bears interest at 2.85% per annum and is collateralized by crude oil sales. The amount of the loan outstanding as of December 31, 2003 was RR725 million (U.S.$25 million).

Interbank loans from foreign banks of RR2,723 million and RR2,522 million as of December 31, 2003 and 2002, respectively had effective average year end interest rates of 6% and 7% per annum, respectively.

Long-term foreign currency-denominated debt. At December 31, 2003, our long-term foreign currency-denominated debt amounted to RR15,902 million. Our largest long-term foreign currency-denominated loans include a loan from BNP Paribas and a loan from Credit Suisse First Boston.

In November 2001 we entered into a loan agreement with BNP Paribas for U.S.$100 million. The loan bore interest at LIBOR plus 3.5% per annum, was collateralized by crude oil export contracts of 50 thousand tons per month and matured in February 2004. The amount of the loan outstanding as of December 31, 2003 was RR614 million and was repaid in 2004.

In March 2002 we entered into a U.S.$200 million loan agreement with Credit Suisse First Boston. The loan bears interest at LIBOR plus 3.78% per annum, is collateralized by the crude oil export contracts of 80 thousand tons per month and matures in March 2007. The amount of the loan outstanding as of December 31, 2003 was RR4,220 million (U.S.$143 million). Although we failed to provide Credit Suisse First Boston with our audited consolidated U.S. GAAP financial statements for the year ended December 31, 2003 and interim consolidated financial information for the six months ended June 30, 2004 as required by our loan agreement, Credit Suisse First Boston has not notified us that it considers an event of default to have occurred under that agreement. We have provided Credit Suisse First Boston with our U.S. GAAP audited consolidated financial statements for the year ended December 31, 2003. However, due to possible delays in completion, we may be unable to provide Credit Suisse First Boston with our U.S. GAAP audited consolidated financial statements for the year ended December 31, 2004 by the date provided for in our loan agreement. As a result Credit Suisse First Boston may notify us that it considers an event of default to have occurred under the terms of this loan agreement in respect of the 2004 audited consolidated financial statements.

In October 2002, we entered into a further loan agreement with BNP Paribas for U.S.$300 million. The proceeds are payable in two tranches, U.S.$125 million bearing interest at LIBOR plus 4.25% per annum and U.S.$175 bearing interest at LIBOR plus 3.75% per annum. The loan is collateralized by crude oil export contracts of 120 thousand tons per month, and matures in October 2007. The amount outstanding under this loan as of December 31, 2003 was RR8,120 million. The loan agreements require compliance with certain financial covenants including, but not limited to, minimum levels of consolidated tangible net worth and maximum debt and interest coverage ratios. In April 2005, BNP Paribas notified us that it considered an event of default to have occurred under the terms of this loan agreement as a result of our failure to provide our audited consolidated U.S. GAAP financial statements for the year ended December 31, 2003 and interim consolidated financial information for the six months ended June 30, 2004, and reserved its rights to accelerate amounts outstanding under the loan agreement and to enforce the related security. However, to date BNP Paribas has taken no action in this respect. We have provided BNP Paribas with our U.S. GAAP audited consolidated financial statements for the year ended December 31, 2003. We believe that this cures this event of default. However, due to possible delays in completion, we may be unable to provide BNP Paribas with our U.S. GAAP audited consolidated financial statements for the year ended December 31, 2004 by the date provided for in our loan agreement. As a result BNP Paribas may notify us that it considers an event of default to have occurred under the terms of this loan agreement in respect of the 2004 audited consolidated financial statements.

During 2002 we entered into a RR278 million (U.S.$9 million) loan agreement with West Deutsche Landesbank Vostok. The loan bears interest at LIBOR plus 4.5% per annum and is collateralized by crude oil export contracts of approximately 7.5 thousand tons per month and was repaid in February 2004. The amount outstanding under this loan as of December 31, 2003 was RR33 million.

We pay interest on our secured loans at a floating rate calculated as LIBOR plus a certain margin, ranging from 3.5% to 4.5%. These loans are currently collateralized by aggregate oil exports of 257,500 tons per month (subject to increases depending on crude oil prices).

In June 2003, Bank Zenit entered into a credit facility agreement with WestLB AG in the amount of U.S.$125 million, bearing interest rate at 9.25% payable semi-annually in arrears. Simultaneously, WestLB AG issued U.S.$125 million of eurobonds due in June 2006, the proceeds of which were loaned to Bank Zenit under the credit facility agreement. The entire amount of eurobonds outstanding at December 31, 2003 was RR2,915 million. The financing agreement includes a covenant that requires Bank Zenit to maintain a specified minimum capital adequacy ratio.

Ruble-denominated debt. At December 31, 2003 and 2002, we had short-term ruble-denominated loans of RR4,110 million with contractual interest rates of 10% to 20% per annum and RR4,941 million with contractual interest rates of 10% to 25% per annum, respectively. These loans are collateralized by our assets. We also had short-term notes payable in the amount of RR6,948 million and RR3,482 million at December 31, 2003 and 2002, respectively, with contractual interest rates of 1% to 7%for the year ended December 31, 2003. Long-term ruble-denominated debt includes debentures and other loans. In 2003 we issued RR1,500 million in debentures with contractual interest rates from 9% to 19%. Debentures outstanding as of December 31, 2003 amounted to RR1,391 million. Other loans include non-banking loans of RR271 million with counter parties. The loans mature between 2004 and 2015.

The following table shows our schedule of repayments for long-term borrowings (excluding long-term promissory notes, deposit certificates and term banking customer deposits) at December 31, 2003 and December 31, 2002, expressed in constant ruble terms.

Schedule of repayment for long-term borrowings


	At December 31,
	2003	2002
	(in RR millions)
Within one year	4,768	6,112
Between one and two years	3,996	5,381
Between two and five years	8,699	7,194
After five years	101	2,047

	17,564	20,734

Financing Activity in 2004 and 2005

Short-term foreign currency denominated debt. In April 2004, we entered into a RR5,422 million (U.S.$187.5 million) bridge loan agreement with BNP Paribas. This loan bears an annual interest rate LIBOR plus 3%. The loan was collateralized by oil exports of 50,000 tons per month and was repaid in October 2004.

In April 2004, we entered into a RR5,422 million (U.S.$187.5 million) bridge loan agreement with Credit Suisse First Boston International. This loan bore an annual interest rate LIBOR plus 3%. The loan was collateralized by oil exports of 80,000 tons per month and was repaid in October 2004.

In February 2005, we entered into a U.S.$35.69 million loan agreement with Bank Ak Bars, which matured in February 2005.

Ruble-denominated debt. In March 2004, our subsidiary Bank Zenit issued RR1,000 million principal amount of unsecured bonds. These bonds bear interest at 8.69% for the first and the second payments due in September 2004 and March 2005, respectively, with subsequent coupon yields determined by the Chairman of the Board of Bank Zenit. These bonds mature in March 2007 and are listed on the MICEX.

CONTRACTUAL OBLIGATIONS

The schedule below sets out our total contractual obligations as of December 31, 2003.


	Payment due by period
Contractual Obligations	Total	Less than 1 year	1-3 years	3-5 years	More than 5 years
Long-Term Debt Obligations	17,564	4,768	11,115	1,580	101
Capital (Finance) Lease Obligations	1,166	643	518	5	—
Operating Lease Obligations	—	—	—	—	—
Purchase Obligations	—	—	—	—	—
Other Long-Term Liabilities	—	—	—	—	—

Total	18,730	5,411	11,633	1,585	101

OFF-BALANCE SHEET ARRANGEMENTS

Banking commitments and contingent liabilities comprise Bank Zenit’s loan commitments and guarantees of RR1,809 million and RR2,062 million at December 31, 2003 and 2002, respectively. The contractual amount of these commitments represents the value at risk if the bank’s clients default and all existing collateral becomes worthless.

Bank Zenit managed trust and fiduciary assets with a nominal value of RR10,857 million and RR4,148 million at December 31, 2003 and 2002, respectively. These assets are recorded off balance sheet as they are not assets of Bank Zenit. No insurance coverage is maintained with respect to these assets.

The above arrangements have been entered into in the ordinary course of business.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. For a full description of our significant accounting policies, please refer to Note 3 to our audited consolidated financial statements included in this annual report. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used, and actual amounts may differ from these estimates. The following critical accounting policies require significant judgments, assumptions and estimates and you should read them in conjunction with our consolidated financial statements.

Oil exploration and production activities

We follow the successful efforts method of accounting for our oil and gas properties, whereby costs of acquiring unproved and proved oil and gas property as well as costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. Exploration expenses, including geological and geophysical expenses and the costs of carrying and retaining undeveloped properties, are expensed as incurred. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. If proved reserves are not found, exploratory well costs are expensed as a dry hole. In an area requiring a major capital expenditure before production can begin, an exploration well is carried as an asset if sufficient reserves are discovered to justify its completion as a production well, and additional exploration drilling is underway or firmly planned. We do not capitalize the cost of other exploratory wells for more than one year unless proved reserves are found.

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

The determination of estimated proved reserves is a significant element in arriving at the results of operations of exploration and production activities. We use independent reservoir engineers to estimate all of our oil and gas reserves. The estimates of proved reserves impact well capitalizations, undeveloped lease impairments and the depreciation rates of proved properties, wells and equipment. Reduction in reserve estimates may result in the need for impairments of proved properties and related assets.

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.

We calculate depreciation, depletion and amortization using the unit of production method over proved or proved developed oil and gas reserves depending on the nature of the costs involved. See Note 3 and Note 11 to our audited consolidated financial statements to this annual report. The proved or proved developed reserves used in the unit of production method assume the extension of our production licenses beyond their current expiration dates until the end of the economic lives of the fields, as discussed, above.

We accrue estimated costs of dismantling oil and natural gas production facilities, including abandonment and site restoration costs, using the unit-of-production method and include these costs as a component of depreciation, depletion and amortization. These estimates are based on currently available technology and current environmental regulations and their interpretation. If these technologies or regulations or their interpretation change in the future, our actual results could differ from the estimates. Effective January 1, 2003, we adopted SFAS 143. This new statement applies to legal obligations associated with the retirement and removal of tangible long-lived assets. Following the requirements of SFAS 143, we recognize a liability for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement obligations are incurred (typically when the asset is installed at the production location). We capitalize the associated asset retirement costs as part of the carrying amount of the long-lived assets in accordance with SFAS 143. Legal obligations, if any, to retire refining and marketing, distribution and banking assets are generally not recognized because of the indeterminable settlement date of these obligations. Through December 31, 2002, in accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” the estimated undiscounted costs of dismantling and removing major oil and gas production and transportation facilities, including necessary site restoration, were accrued using the unit-of-production method. The change in accounting of asset retirement obligations was accounted for as a change in accounting principle.

Most of these removal obligations are many years in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria will have to be met when the removal event actually occurs. Asset removal technologies and costs are constantly changing as are political, environmental and safety considerations. See also “Environmental remediation” below.

Environmental remediation

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated.

Income tax accounting

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

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

We believe that our estimates and assumptions are reasonably accurate and we do not believe that they are reasonably likely to change materially in the future.

Recent accounting pronouncements

Consolidation of Variable Interest Entities. In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities”, (“FIN 46”) to expand existing accounting guidance and to establish standards for determining under what circumstances a variable interest (“VIE”) should be consolidated with its primary beneficiary. FIN 46 also requires disclosure about VIEs that are not required to be consolidated but in which the reporting entity has a significant variable interest or about any potential VIEs when a reporting entity is unable to obtain the information necessary to confirm if this entity is a VIE or determine if a reporting entity is the primary beneficiary. In December 2003, the FASB revised certain implementation provision of FIN 46. The revised interpretation (“FIN 46R”) substantially retained the requirements of immediate application of FIN 46 to VIEs created after January 31, 2003 or created before that date but which had significant modifications in terms of contracts or nature of transactions with a reporting entity subsequent to that date. With respect of older VIEs, the consolidation requirements under FIN 46R apply not later than for the first financial year or interim period ending after December 15, 2003, if such a VIE is a special-purpose entity (“SPE”), and no later than for the first financial year or interim period ending after March 15, 2004, if such a VIE is not an SPE.

In general, a VIE is a corporation, partnership, trust, or any other legal structure used for business purposes that either (a) does not have equity investors with voting rights or (b) has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN 46 requires a VIE to be consolidated by reporting entity if that entity is subject to a majority of the risk of loss from the VIE’s activities, is entitled to receive a majority of the VIE’s residual returns, or both (the entity required to consolidate VIE’s is called the primary beneficiary). It also requires deconsolidation of a VIE if an entity is not the primary beneficiary of the VIE.

We have completed our analysis of compliance with the provisions of FIN 46 as revised by FIN 46R in respect of the existence of VIEs created after January 31, 2003 or VIEs created before that date but which had significant modifications in terms of contracts or nature of transactions with us subsequent to that date or VIEs which are SPEs. This analysis did not identify any significant impact of FIN 46 as revised by FIN 46R on our audited consolidated financial statements as of and for the year ended December 31, 2003. We are still assessing the impact that FIN 46 as revised by FIN 46R may have on its consolidated financial statements for the periods commencing January 1, 2004.

Postretirement Benefits. In December 2003, the FASB revised and reissued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88, and 106,” which revises and requires additional disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by previous Financial Accounting Board Standards. We adopted the provisions of this standard. Certain provisions of this standard regarding disclosure of information about foreign plans and disclosure of estimated future benefit payments are not required until 2004. The adoption of the provisions applicable to 2003 did not have a material impact on our results of operations, financial position or cash flow, nor will the adoption of the additional provisions in 2004 have a material impact on the Group’s results of operations, financial position or cash flow.

Amendment to SFAS No. 133 on Derivative Instruments and Hedging Activities. In April 2003, the FASB issued SFAS No. 149, “Amendment to Statement 133 on Derivative Instruments and Hedging Activities” (“SFAS 149”). This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”. It is

effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. All provisions of the statement should be applied prospectively, except as stated further. Provisions related to SFAS 133 implementation issues that have been effective for fiscal quarters beginning prior to June 15, 2003, should continue to be applied in accordance with their respective dates. Rules related to forward purchases or sales of when-issued securities or other similar securities, should be also applied to existing contracts. The adoption of the provisions of SFAS 149 did not have a material impact on our results of operations, financial position or cash flow.

Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“SFAS 150”). This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. On November 7, 2003, the FASB issued FASB Staff Position No. FAS 150-3, which deferred certain provisions of SFAS 150. The adoption of the provisions of SFAS 150 and deferral of certain provisions did not have a material impact on our results of operations, financial position or cash flow.

Stock-based compensation. On December 16, 2004, FASB issued SFAS No. 123 (revised 2004), “Share Based Payment” (“SFAS 123R”), which is a revision of SFAS 123. SFAS 123R supersedes APB 25 and amends Statement No. 95, “Statement of Cash Flows”. SFAS 123R prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans; pro forma disclosure is no longer permitted. The cost of the equity instruments is to be measured based on fair value of the instruments on the date they are granted (with certain exceptions) and is required to be recognized over the period during which the employees are required to provide services in exchange for the equity instruments. SFAS 123R is effective in the first interim or annual reporting period beginning after June 15, 2005.

SFAS 123R provides two alternatives for adoption: (1) a “modified prospective” method in which compensation cost is recognized for all awards granted subsequent to the effective date of this statement as well as for the unvested portion of awards outstanding as of the effective date and (2) a “modified retrospective” method which follows the approach in the “modified prospective” method, but also permits entities to restate prior periods to reflect compensation cost calculated under SFAS 123 for pro forma amounts disclosure. We plan to adopt SFAS 123R using the modified prospective method. The adoption of SFAS 123R is expected to have an impact on our results of operations. On March 30, 2005, the SEC released Staff Accounting Bulletin No. 107, “Share-Based Payment,” (“SAB 107”), which expresses the views of the SEC staff regarding the application of SFAS 123R. The impact of adopting SFAS 123R and SAB 107 cannot be accurately estimated at this time, as it will depend on the amount of share based awards granted in future periods. However, had we adopted SFAS 123R and SAB 107 in a prior period, the impact would approximate the impact of SFAS 123 as described in the disclosure of pro forma net income and income per share in this Note to the consolidated financial statements.

Inventory costs. In November 2004, the FASB issued SFAS No. 151, “Inventory Costs an amendment of ARB No. 43, Chapter 4” (“SFAS 151”). SFAS 151 requires that items, such as idle facility expense, excessive spoilage, double freight, and re-handling costs, be recognized as a current-period charge. The provisions of SFAS 151 are effective for financial statements for fiscal years beginning after June 15, 2005. We are analyzing the provisions of this statement to determine the effects, if any, on our results of operations, financial position or cash flow.

Nonmonetary exchanges of similar assets. In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets” (“SFAS 153”). SFAS 153 addresses the measurement of exchanges of nonmonetary assets. The guidance in APB 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29, however, included certain exceptions to that principle. SFAS 153 amends APB 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of SFAS 153 are effective for financial statements for fiscal years beginning after June 15, 2005. The adoption of the provisions of SFAS 153 is not expected to have a material impact on our results of operations, financial position or cash flow.

Accounting changes and error corrections. In May 2005, the FASB issued SFAS No. 154, “Accounting changes and error corrections” (“SFAS 154”). SFAS 154 replaces APB Opinion No. 20, “Accounting Changes” (“APB 20”), and SFAS No. 3, “Reporting Changes in Interim Financial Statements,” and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior period’s financial statements of all changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change, if a pronouncement, which requires the change in accounting principle, does not include specific transition provisions. SFAS 154 carries forward without change the guidance contained in APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of the provisions of SFAS 154 is not expected to have a material impact on our results of operations, financial position or cash flow.

Income per share calculation. In March 2004, the Emergency Issue Task Force (“EITF”) reached a consensus on Issue 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128, Earnings per Share,” that explained how to determine whether a security should be considered a “participating security” and how income should be allocated to a participating security when using the two-class method for computing basic income per share. The adoption of this standard which is effective for financial statements for fiscal periods beginning after March 31, 2004 is not expected to have a material impact on our income per share calculation.

Discontinued operations. In November 2004, the EITF issued EITF No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (“EITF 03-13”). EITF 03-13 assists in the development of a model for evaluating (a) which cash flows are to be considered in determining whether cash flows have been or will be eliminated and (b) what types of continuing involvement constitute significant continuing involvement when determining whether the disposal or sale of a component of a business is to be accounted for as discontinued operations. We are analyzing the provisions of EITF 03-13 to determine the effects, if any, on our results of operations, financial position or cash flow.

Conditional asset retirement obligations. In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). This interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event if the liability’s fair value can be reasonably estimated. We are analyzing the provisions of this interpretation to determine the effects, if any, on our results of operations, financial position or cash flow.

Suspended well costs. In April 2005, the FASB issued FASB Staff Position FAS No. 19-1, “Accounting for suspended well costs” (“FSP FAS 19-1”). FSP FAS 19-1 amends SFAS 19 and applies to companies that follow the successful efforts method of accounting. FSP FAS 19-1 concludes that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and an entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. In addition FSP 19-1 requires certain disclosures to provide financial statement users information about management’s evaluation of capitalized exploratory well costs. The provisions of FSP FAS 19-1 are effective for the first reporting period beginning after April 4, 2005 and should be applied prospectively to existing and newly capitalized exploratory well costs. The adoption of the provisions of FSP FAS 19-1 is not expected to have a material impact on our results of operations, financial position or cash flow.

Implicit variable interest. In March 2005, the FASB issued FASB Staff Position FIN 46(R)-5, “Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities” (“FSP FIN 46(R)-5”). FSP FIN 46(R)-5 is applicable to both nonpublic and public reporting enterprises and addresses an issue that commonly arises in leasing arrangements among related parties, and in other types of arrangements involving related parties and unrelated parties. We are analyzing the provisions of this interpretation to determine the effects, if any, on our results of operations, financial position or cash flow.

RESEARCH AND DEVELOPMENT

In the years ending December 31, 2003 and 2002, we spent approximately RR316 million and RR331 million on research and development, respectively.

The Tatar Research and Design Institute of the Oil Industry (“TatNIPIneft”), a research division of ours, has been in operation for approximately 50 years and is our main research and development unit. TatNIPIneft is one of the leading petroleum and petrochemicals research and development institutes in Russia and specializes in the prospecting and exploration of oil fields, well construction and rehabilitation, production methods, corrosion protection of oil equipment, and the assessment of reserves and development of oil fields.

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

We use a variety of patented technologies (and related processes) in our operations, as do our affiliates and related institutes, such as TatNIPIneft. These patented technologies and processes include several that have been licensed from third parties. We currently hold more than 600 Russian patents, of which we actively exploit approximately 60. In addition, we hold 22 patents outside Russia, including in Canada, China, Germany, France, Iran, Italy, Mexico, the United Kingdom, the United States and

Vietnam. Patented technology (and related processes) that are material to our operations consist primarily of patents relating to protecting pipelines against corrosion caused by water or foreign particles, patents for local well casing technology and patents relating to extracting and containing natural gas and light hydrocarbons escaping from crude oil held in storage. We developed some of these patents (such as those on the TATEX natural gas collection system) in joint ventures or in collaboration with third parties. We believe that licensing revenues are not material to us.

In 2003, our oil field development work included development of new designs and processes for the application of advanced oil bed stimulation methods and technologies, in order to ensure profitable oil field development. In the area of well construction, we have specifically focused on increasing penetration rates and well production capabilities. Moreover, we continue to improve the quality of techniques for drilling mud, technologies for implementing profile shut-offs and construction of small-diameter wells. In oil and natural gas treatment, we continued work on reconstruction of the collection system, improvement of accounting, as well as implementation of more strict requirements for the oil quality to meet demands of the world and domestic markets.

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

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

LICENSES

As of December 31, 2004, we held 66 production licenses giving us the exclusive rights to produce oil from 76 fields. Of our 66 licenses, 35 were solely production licenses and 31 were combined exploration and production licenses, 6 of which cover 19 oil fields. Two licenses were provided for the Tat-Kandyzskoe oil field located in the Republic of Tatarstan and the Orenburg region. Our joint ventures held production licenses for seven additional oil fields and two subsoil areas: three oil fields of Tatoilgas, two oil fields of TATEX and two oil fields and two subsoil areas of Kalmtatneft. Of the nine licenses held by the joint ventures, one license held by TATEX and two licenses held by Kalmtatneft were solely production licenses and six were combined exploration and production licenses.

Seven of the exploration and production licenses allow for exploration with the right to future development on newly discovered fields. Once exploration is completed, however, each field will require a separate development license with specific conditions relating to that field. Five of these licenses were issued in 1995 and cover nearly the entire oil-prospecting region of Tatarstan. These licenses exclude only fields for which specific licenses have already been granted, and are valid for 25 years. There are currently 19 known oil fields within these license areas, including 17 oilfields for which we have already acquired mining allotments and are in the process of undertaking initial testing exploitation. In addition, two of the exploration and production licenses were granted to our joint venture Kalmtatneft, which we sold in 2005, for exploration and production in Kalmykia in March 2002. In 2004, Kalmtatneft received a license for geological survey and evaluation of deposits of hydrocarbon materials in Kalmykia.

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 2004, we acquired 70% of OAO Ilekneft, which holds one production license and two combined exploration and production licenses. 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. In 2005 we also acquired Kalmtatneftegaz, which holds two licenses for geological survey in Kalmykia.

We also currently hold Russian Federation exploration licenses, valid for five years from the date of issuance: one for exploration in the Ulyanovsk region (issued in October 2000), one for exploration in the Chuvash Republic (issued in May 2001) and seven for exploration in the western part of Tatarstan (issued in 2003).

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

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

During the fourth quarter of 1997 and 1998, pursuant to a decree of the Tatarstan government encouraging the development of small new oil fields by newly established companies, we transferred several of our oil fields to such newly established companies. In each case, through this transfer we created new, smaller oil fields located in the territory that is covered by the five special Russian exploration licenses referred to above. As of December 31, 2003, as a result of this process, 21 newly formed oil companies held 59 licenses for 59 small oil fields, including 46 combined exploration and production licenses and 13 production licenses. Some of the newly established companies are majority owned by current and former employees of Tatneft. These companies are not affiliates of Tatneft. Such transfers may not have been made in full compliance with Russian law, which requires that the initial license-holder own not less than 50% in the legal entity that receives the license and that the new license-holder possesses the equipment necessary to explore the oil field or extract oil. Subsoil licenses are issued jointly by local and federal authorities. See “Item 4—Information on the Company—Exploration and Production.”

TRENDS INFORMATION

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

ITEM 6. DIRECTORS, SENIOR MANAGEMENT, AND EMPLOYEES

DIRECTORS AND SENIOR MANAGEMENT

The Joint-Stock Companies Law requires at least a seven-member Board of Directors for an open joint stock company with more than 1,000 holders of ordinary shares and at least a nine-member Board of Directors for an open joint stock company with more than 10,000 holders of ordinary shares. Our Board currently consists of 15 members. Directors are elected for one-year terms by our shareholders’ meeting and can be re-elected for an unlimited number of terms. If the Board is not elected at the time prescribed under current legislation, the powers of the existing Board terminate and a new shareholders’ meeting has to be convened to elect a new Board. All directors can be removed by a vote of the shareholders’ meeting. Apart from those members appointed by the Tatarstan government, through OAO Svyazinvestneftekhim in its capacity as a shareholder of Tatneft, the Tatarstan government holds the Golden Share in our company that gives it power to appoint a representative to our Board. See “Item 4—Information on the Company—Relationship with Tatarstan” and “Item 7—Major Shareholders and Related Party Transactions.”

As of the date of this annual report, the members of our Board of Directors are as follows:


Name	Titles	Year of Birth
Rustam Nurgalievich Minnikhanov*	Chairman of the Board, Prime Minister of the Republic of Tatarstan	1957

Shafagat Fahrazovich Takhautdinov	Director, General Director	1946

Rishat Fazlutdinovich Abubakirov	Director, Head of Almetyevsk Region and City Administration	1959

Radik Raufovich Gaizatullin	Director, Finance Minister of the Republic of Tatarstan	1964

Sushovan Ghosh	Director, Managing Director, SGI Enterprises Ltd.	1957

Nail Gabdulbarievich Ibragimov	Director, First Deputy General Director for Production, Chief Engineer	1955

Rais Salikhovich Khisamov	Director, Deputy General Director, Head Geologist	1950

Vladimir Pavlovich Lavushchenko	Director, Deputy General Director for Economics	1949

Nail Ulfatovich Maganov	Director, First Deputy General Director, Head of Oil and Refined Products Sales Department	1958

Renat Halliulovich Muslimov	Director, State Counsel to the President of the Republic of Tatarstan	1934

Veleriy Yurievich Sorokin	Director, General Director of OAO Svyazinvestneftekhim	1964

Mirgazian Zakievich Taziev	Director, Member of the Executive Board, Head of NGDU Almetievneft	1947

Valery Pavlovich Vasiliev	Director, Minister of Land and Property Relations of the Republic of Tatarstan	1947

Maria Leonidovna Voskresenskaya	Director, Director of Brentcross Ltd	1955

David William Waygood	Director, Director of Waygood Limited	1950

*	Appointed to the Board of Directors pursuant to the exercise of the Golden Share rights of the Tatarstan government.

As of the date of this annual report, members of the Executive Board of Tatneft who are not also directors are as follows:


Name	Title	Year of Birth
Viktor Isakovich Gorodny	Deputy General Director, Head of Property Management Department	1952

Iskandar Gatinovich Garifullin	Chief Accountant	1960

Valeriy Dmitrievitch Ershov	Head of Legal Department	1949

Semyon Afroimovich Feldman	Advisor to the General Director	1936

Khamid Zagirovich Kaveev	Deputy General Director and Head of Foreign Economics Department	1955

Rustam Nabiullovich Mukhamadeev	Deputy General Director for Personnel and Social Development	1952

Rafael Saitovich Nurmukhametov	Head of NGDU Leninogorskneft	1949

Rafkat Mazitovich Rakhmanov	Deputy General Director for Oil Well Repair and PNP	1948

Zagit Foatovich Sharafeev	Deputy General Director of Tatneft, Director of Tatneft-Neftekhim	1955

Fyodor Lazarevich Shyelkov	Deputy General Director on General Matters	1948

Mikhail Nikolaevich Studenskiy	Deputy General Director for Drilling	1945

Evgeny Aleksandrevich Tikhturov	Head of Finance Department	1960

Alexander Trofimovich Yukhimets	Secretary of the Board of Directors	1949

Vladimir Nikolaevich Zinoviev	Deputy General Director for Capital Construction	1951

Biographies of the directors and executive officers are set out below.

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

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

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

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

Sushovan Ghosh. Mr. Ghosh was born in 1957. He graduated from Queen Mary’s College of the University of London with a degree in Electrical and Electronics Engineering (with First Class Honors in 1979). He is also a Fellow of the Institute of Chartered Accountants, England and Wales. From 1998 to 2000 and since 2002 he has served as the Managing Director of SGI Group U.K., and from 2001 to 2002 he was Deputy Head of the International Investments and Trading Department and Director of Finance for Renaissance Capital in Russia.

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

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

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

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

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

Veleriy Yurievich Sorokin. Mr. Sorokin was born in 1964. He graduated from Kazan State University in 1986. From 1996 to 2002 he worked as director of the Agency for State Debt Management of the Republic of Tatarstan under the Ministry of Finance of the Republic of Tatarstan. Since 2003 he has been the General Director of OAO Svyazinvestneftekhim.

Mirgazian Zakievich Taziev. Mr. Taziev was born in 1947. He graduated from Oktyabrsk Oil Technical College with a specialization in mechanics. In 1972, he graduated from the Gubkin Petrochemical and Gas Industry Institute of Moscow with a degree in “Machine and Equipment of the Oil and Gas Industry.” In 1965, Mr. Taziev began working as a machinist-repairman in the oil-industrial section of Tyumazineft of Production Association “Bashneft.” From 1966 to 1978, he worked at NGDU Elkhovneft, as a mechanic, a specialist in oil production, and the head of exchange of the regional engineering-technological service. In 1978 he joined Tatneft, working as the head of the repair shop and assistant Head of Central Production Services for

the repair of electrical loading stations. In 1984 he became assistant Head of construction at Elkhovneft. In 1988, he accepted a position as Head of NGDU Irkenneft. From 2001 to 2005, Mr. Taziev served as Head of NGDU Djalilneft. In 2005, he was appointed Head of NGDU Almetievneft. Mr. Taziev is also a member of our Executive Board.

Valery Pavlovich Vasiliev. Mr. Vasiliev was born in 1947. He graduated from Kazan Agricultural Institute in 1970 with a specialization in mechanical engineering. He started work in 1970 as a mechanical engineer at the OKS of the Agricultural Department of the Executive Committee of Laishevsky District Council. He then worked in the Laishevsky District as Chief Engineer of Volzhsky state farm, Chairman of Put Ilyicha collective farm and Director of Rossiya state farm. His other positions have included: from 1977 to 1985 service as a full-time party officer, serving as the Second and First Secretary of the Laishevsky District Committee of the Communist Party and Head of the Agriculture and Food Industry Section of the Tatar Region Committee of the Communist Party. In 1986, he was appointed First Deputy Chairman of the Republic’s State Agricultural Committee and Minister of the Tatar Autonomous Soviet Socialist Republic. He was then appointed First Secretary of the Rybno-Slobodsky District Committee of the Communist Party. From 1989 to 1995, he worked with the government of the Republic as First Deputy Chairman of the Council of Ministers of the Tatar Autonomous Soviet Socialist Republic and First Deputy Prime Minister of the Republic of Tatarstan. He was then Head of the Control Department of the President of the Republic of Tatarstan. From 1996 to 1999, he headed the Ministry for Agriculture and Food of the Republic of Tatarstan. In May 1999, he was appointed Chairman of the State Property Management Committee of the Republic of Tatarstan. Since 2001, he has been Minister for Land and Property Relations of the Republic of Tatarstan.

Maria Leonidovna Voskresenskaya. Ms. Voskresenskaya was born in 1955. She graduated from the Moscow Financial Academy in 1977. She holds a certified public accountant designation and is a certified Russian accountant. Between 1994 and 2004, she worked at Ernst & Young. Since 2004, she has served as a director of Brentcross Ltd.

David William Waygood. Mr. Waygood was born in 1950. He is an Associate of the Institute of Bankers in the United Kingdom. From 1998 to 1999 Mr. Waygood served as Group Representative in the Moscow representative office of National Westminster Bank plc. In 2000 and 2001, he was a Director at LTP Trade plc, London, a trade finance company. Since August 2001, he has been Director of Waygood Limited, an international business consultancy.

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

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

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

Semyon Afroimovich Feldman. Mr. Feldman was born in 1936. In 1958, he graduated from the Leningrad Mining Institute and received the specialization of mining engineer for development of oil and natural gas fields. He worked first as an oil production operator, and then as a production foreman, manager of an oil production section and Deputy Head for Capital Construction at the Prikamneft NGDU. From 1985 until February 2004, he served as Deputy General Director for Capital Construction at Tatneft. From February 2004, Mr. Feldman has served as Advisor to the General Director of Tatneft.

Khamid Zagirovich Kaveev. Mr. Kaveev was born in 1955. He graduated from the Kazan Aviation Institute (KAI) in 1978, and received a Ph.D. in Economics from the Academy of National Economy in 1992. After working at KAI, he worked at the

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Minnibaevsk Oil Refinery from 1979 to 1984. He then worked as an instructor at the Almetyevsk City Committee of the Communist Party, from 1987, serving as Deputy Chairman of the City Council of People’s Deputies and from 1989 as Chairman of the Almetyevsk City Council of People’s Deputies. He has served as Deputy Manager of the joint ventures Tatoilpetro and TATEX since 1992, and was appointed General Director of TATEX in December 1996. Since June of 1999, he has served as Deputy General Director and Head of the Foreign Economic Department.

Rustam Nabiullovich Mukhamadeev. Mr. Mukhamadeev was born in 1952. In 1977, he graduated from the Gubkin Oil Processing and Gas Industry Institute of Moscow, with a degree in “Technological and Complex Mechanization for the Development of Oil and Gas Fields.” From 1970 to 1971, Mr. Mukhamadeev worked as a student operator for Elkhovneft. Following service in the army, he joined the evening department of the Tatarstan branch of the Gubkin Petrochemical and Gas Industry Institute of Moscow as a senior laboratory technician. In 1975, Mr. Mukhamadeev returned to Elkhovneft as an oil-pump research engineer, subsequently becoming a senior geologist at Tatneftegasrazvedka in 1978. His subsequent work includes serving as an instructor in the industrial-transport section of the Almetyevsk City Committee of the Communist Party (1981-1985); Secretary of the Communist Party committee, Assistant Director of Personnel, extra-curricular and social development, Assistant Director for Social Development and Assistant Director for General Operations of NGDU Elkhovneft (1985-1998); and head of the Almetyevsk repair and construction division of Tatneft (1998-2001). Mr. Mukhamadeev has served as our Deputy General Director for Personnel and Social Development since August 2001.

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

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

Zagit Foatovich Sharafeev. Mr. Sharafeev was born in 1956. In 1980 he graduated from the Kazan Chemical-Technological Institute and in 1991 he graduated from the All-Union Finance and Economics Institute. He is also a Candidate of Sciences in economics. From 1997 to 2000 he was the General Director of OAO Nizhknekamsktekhuglerod. From 2000 to 2002 Mr. Sharafeev was the First Deputy General Director of Nizhnekamskshina and from 2002 was the First Deputy Director of Tatneft-Neftekhim. In August 2004, Mr. Sharafeev became the Director of Tatneft-Neftekhim.

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

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

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

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

Vladimir Nikolaevich Zinoviev. Mr. Zinoviev was born in 1951. He graduated from the Kazan Construction Engineering Institute in 1980 with a specialization in industrial and civil construction. From 1971 to 1972, he worked in construction as a mason and carpenter. Following service in the armed forces (1972-74), he was a foreman at a construction company (1974-76), instructor of industrial-transportation department of the City Communist Party Committee (1976-1980), chief engineer of construction company No. 52 (1980-84), chief engineer and then director of industrial construction complex of the Yaukutgasstroy trust in Yaukutia (1984-91) and chief engineer of industrial construction trust No. 5 (1991-1992). From 1992 through February 2004, he served as deputy chief for capital construction of NGDU Yamashneft. From February 2004, he has served as Deputy General Director for Capital Construction at Tatneft.

COMPENSATION

Total salaries, bonuses and other awards paid by Tatneft and its subsidiaries to members of the Board as a group and to executive officers other than members of the Board as a group during 2003 were approximately RR77.7 million and during 2004 were approximately RR96.3 million.

In addition, in 2003, we issued and placed to members of our Board and senior management 9,300,000 options to acquire 9,300,000 Ordinary Shares, representing approximately 0.4% of our Ordinary Shares respectively. The options, represented by option certificates, are non-transferable and are exercisable in the period from 270 to 365 days from their placement. Each option entitles its holder to purchase one Ordinary Share at the price of RR9.50, the minimum price of the Ordinary Shares in the two-year period preceding the date the decision on issuance of the option certificates was adopted by our Board of Directors. The 2003 option certificates were placed at a subscription price of RR1.00 per certificate starting from July 10, 2003. We reserve the right to repurchase outstanding options at the maximum weighted average daily market price of our Ordinary Shares for the preceding three years on the MICEX less the exercise price of the option. In 2003, we repurchased the options granted in 2002 at RR27.00 per option and in 2004 we repurchased the options granted in 2003 at RR40.26 per option. We acquired Ordinary Shares underlying the options on the secondary market. Our subsidiary, IFK Solid, acted as the underwriter and placement agent for the issuance of the options, and OAO Aktsionerny Kapital (“Aktsionerny Kapital”), our registrar, acts as the registrar for the option certificates. See “Item 7—Major Shareholders and Related Party Transactions—Related Party Transactions.”

We provide termination benefits for the following members of our Board of Directors: Mr. Taukhautdinov, Mr. Khisamov, Mr. Lavushchenko, Mr. Maganov, and Mr. Taziev. Upon termination these directors receive a one-time cash payment, which is determined as a multiple (10 times) of the basic portion of their monthly salary and in the aggregate totaled RR6,465,870 as of May 19, 2005.

BOARD PRACTICES

Authority of the Board

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

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

•

determining our strategic priorities;

•

convening annual and extraordinary meetings of shareholders;

•

approving agendas for shareholders’ meetings;

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•

determining record dates for the right to participate in the shareholders’ meetings;

•

submitting certain matters to the shareholders’ meetings, as provided for by law; deciding on inclusion of shareholders’ proposals to the agendas for shareholders’ meetings and deciding on other matters related to the convening and holding of the shareholders’ meetings;

•

deciding on increases in our charter capital through issuance of additional shares within the amount of authorized shares;

•

placement of bonds and other securities;

•

determining the market value of property, where provided for by law;

•

acquiring stocks, bonds, and other securities we may issue, where provided for by law;

•

appointing and dismissing the General Director and the Executive Board;

•

making recommendations relating to the amount of remuneration and contributory compensation to be paid to members of the revision committee (the “Revision Committee”) and determining payments for the services of the independent auditors;

•

recommending the amount of the dividend on shares and the procedure for payment thereof;

•

using our reserves and other funds;

•

forming branches and opening representative offices;

•

concluding certain major transactions by the Company, where provided for by law;

•

concluding certain interested party transactions, where provided for by law;

•

approving our registrar and determining the terms and conditions of our agreement with the registrar and its termination;

•

amending our Charter following the placement of additional shares, including amendments relating to the increase in our charter capital, as provided by law;

•

determining the procedures for presenting all bills, statements and declarations and determining the system for calculation of profits and losses, including the rules relating to the amortization of property;

•

appointing the First Deputy General Director;

•

appointing and dismissing the Secretary of the Board and determining her/his duties;

•

approving other internal documents of the Company on the regulation of the matters related to the competence of the Board of Directors, excluding internal documents that are within the competence of the shareholders’ meeting and executive bodies where provided for in the Charter;

•

forming committees of the Board of Directors and approving related Regulations;

•

adopting the Corporate Governance Code and amending it;

•

approving the working standards of the Board of Directors and the Executive Board and determining their compensation; and

•

making other decisions that are not within the competence of the shareholders’ meeting, the General Director and the Executive Board.

Meetings of the Board

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

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

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

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

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

Committees of the Board of Directors

Audit Committee. As of the date of this annual report, the Audit Committee of our Board of Directors, appointed on June 30, 2005, is comprised of the following directors: Mr. Gaizatullin (Chairman), Mr. Waygood, Mr. Ghosh and Ms. Voskresenskaya. Under the terms of reference of the Audit Committee, its membership shall consist of at least three directors, including one director who is a specialist in accounting or financial management. Responsibilities of the Audit Committee are separate from the responsibilities of our Revision Committee that we are required to maintain as a matter of Russian law. See “—Revision Committee.” Our Audit Committee is responsible for submitting recommendations to the Board of Directors on an annual basis regarding the independent auditor, negotiating the terms of engagement of the independent auditor and evaluating its performance, overseeing completeness and correctness of our financial statements and evaluating reliability and effectiveness of our internal controls.

Remuneration Committee. As of the date of this annual report, our Remuneration Committee, appointed on June 30, 2005, is comprised of the following directors and members of senior management: Mr. Waygood (Chairman), Mr. Ibragimov, Mr. Lavushchenko, Mr. Gorodny, Mr. Garifullin and Mr. Mukhamadeev. The Remuneration Committee is responsible for appraising the work of the Board and management, development of recommendations with respect to remuneration of top managers, the terms of their employment contracts and personnel policies more generally.

Corporate Governance Committee. As of the date of this annual report, our Corporate Governance Committee, appointed on June 30, 2005, is comprised of the following directors and members of senior management: Mr. Gorodny (Chairman), Mr. R.S. Khisamov, Mr. Sorokin, Mr. Ershov, Mr. R.M. Khisamov and Mr. Rakhmatullin. The Corporate Governance Committee provides reports and recommendations to the Board of Directors regarding development and improvement of our corporate governance practices, including relationships between the shareholders, the Board of Directors and management and interaction with the subsidiaries and other affiliates.

Disclosure Committee. As of the date of this annual report, our Disclosure Committee, appointed on June 30, 2005, is comprised of the following directors and members of senior management: Mr. Lavushchenko (Chairman), Mr. Gorodny, Mr. Tikhturov, Mr. Ershov, Mr. Gaifutdinov, Mr. M. Demin, Mrs. T. Vilkova, Mr. R. Rafikov, Mr. Gariffulin, Mr. D. Volkov and Mr. Yukhimets. The Disclosure Committee is responsible for assisting the Board of Directors and the chief executive and financial officers in developing, carrying out and evaluating our internal controls and procedures in connection with information disclosure.

Approval of Major Transactions

The Joint-Stock Companies Law defines a “major transaction” as a transaction (including a loan, pledge or guarantee) or a series of interrelated transactions not in the ordinary course of business and not in connection with the placement of ordinary shares or securities convertible into ordinary shares, involving the acquisition or disposal of assets, the value of which constitutes 25% or more of the balance sheet value of the assets of a company calculated in accordance with RAR as of the most recent reporting date. Major transactions involving assets ranging from 25% to 50% of the balance sheet value of the assets of a company require the unanimous approval of all members of the Board or, in the absence of such approval, the affirmative vote of shareholders holding a majority of the voting shares present at a shareholders’ meeting. Major transactions involving assets in excess of 50% of the balance sheet value of our assets require a three-quarters affirmative vote of shareholders present at a shareholders’ meeting.

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Approval of Interested Party Transactions

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

•

is a party to, or beneficiary of, a transaction with us, whether directly or as a representative or intermediary;

•

owns, together or separately, at least 20% of the issued shares of a legal entity that is a party to, or beneficiary of, a transaction with us, whether directly or as a representative or intermediary; or

•

is a member of the Board or any management body of the company (or the managing company of such company) that is a party to, or a beneficiary of, a transaction with us, whether directly or as a representative or intermediary.

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

•

a majority of independent directors (1) who are not “interested parties” in the transaction and (2) who are not, and were not during the year preceding the date of approval, our affiliates (except for serving as directors) and who and whose close relatives are not, and were not during the year preceding the date of approval, the General Director or members of the Executive Board; or

•

a majority of all shareholders that are not “interested parties” in the transaction if (1) the value of such transaction is at least 2% of the value of our balance sheet assets calculated in accordance with RAR as of the most recent reporting date; (2) the transaction involves the issuance of shares or securities convertible into shares in an amount that equals at least 2% of the Ordinary Shares and ordinary shares into which the issued securities convertible into ordinary shares, if any, may be converted; or (3) all members of the Board are interested parties or are not independent directors.

In certain transactions, we failed to comply with this requirement of the Joint-Stock Companies Law. Due to the nature of these transactions and the Board’s ability to ratify actions taken previously, we do not believe that this failure will have a material impact on our financial condition or results of operations. See “Item 3—Key Information—Risk Factors—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.”

The General Director

The General Director is elected by the Board for a five-year term, and can be removed by a vote of 75% of the members of the Board. The current General Director, Mr. Shafagat F. Takhautdinov, was elected by the Board on June 21, 1999, and re-elected for an additional five years on May 24, 2004.

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

Pursuant to the Charter and the Provisions On the General Director approved by the shareholders on June 25, 2004, the authority of the General Director includes the following:

•

managing our assets in the manner prescribed by our Charter and the law;

•

nominating candidates for First Deputy General Director;

•

nominating candidates to the Executive Board;

•

organizing work of the Executive Board and delegating duties among members of the Executive Board;

•

making employment decisions;

•

concluding collective bargaining agreements;

•

appointing and dismissing heads of departments and representative offices; and

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•

approving internal documents of the Company, excluding internal documents that are within the competence of the shareholder’s meeting, Board of Director and Executive Board.

The General Director also chairs the meetings of our Executive Board.

The Executive Board

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

•

developing our programs of activities;

•

participating in commercial and non-commercial organizations;

•

fulfilling our financial and investment programs;

•

selling our shares and other securities;

•

determining procedures for access to the register of shareholders;

•

submitting proposals on profit and loss distribution to the Board;

•

determining our domestic and foreign pricing policies; and

•

approving other internal documents of the Company on the regulation of matters related to the competence of the Executive Board and other documents provided by the General Director.

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

Revision Committee

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

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

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

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

Members of the Revision Committee, appointed on June 30, 2005, as of the date of this annual report are:

•

Venera Gibadullovna Kuzmina, Head of the Revision Committee/shareholder of Tatneft;

•

Marat Mikhailovich Afanasiev, Head of Department at the Ministry of Finance of the Republic of Tatarstan;

•

Nikolai Kuzmich Lapin, Head of the Tatneft Control and Audit Department;

•

Marsel Masgutovich Muradymov, Chief Accountant of Almetyevsk UPNP and KRS;

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•

Peter Nikolaevich Paramonov, Chief Accountant of the Irkenneft NGDU;

•

Liliya Rafaelovna Rakhimzyanova, Head of the Oil Production Section with the Ministry of Economy and Industry of the Republic of Tatarstan;

•

Ildar Asylgaraevich Rakhmatullin, Head of the Internal Audit Section of the Corporate Management Department of Tatneft;

•

Rustam Ilgizarovich Sharapov, Deputy Head of the Almetyevskneft NGDU for Economics; and

•

Tamara Milchailovna Vilkova, Deputy Chief Accountant of Tatneft, Deputy Head of the Accounting Department of Tatneft.

EMPLOYEES

As of both December 31, 2004 and 2003, together with our principal subsidiaries we had approximately 100,400 and 98,000 employees, of which Tatneft had approximately 62,805 employees and 64,842 employees, respectively, including approximately 31,257 employees and 32,986, respectively, that worked in oil production and 6,491 employees and 6,481, respectively, that worked in drilling; Nizhnekamskshina had 13,513 and 14,125 employees, respectively; and our banking subsidiaries had 1,823 employees and 1,103 employees, respectively. Tatneft and our wholly-owned subsidiaries had approximately 68,555 and 74,226 employees at December 31, 2002 and 2001, respectively; Nizhnekamskshina had 14,325 and 14,520 employees at December 31, 2002 and 2001, respectively; and our banking subsidiaries had 1,273 and 974 at December 31, 2002 and 2001, respectively.

We do not expect a significant reduction in the workforce to result from our restructuring program.

We have adopted a collective labor agreement that applies to all employees of Tatneft, and sets a minimum level of compensation. This agreement is renegotiated annually and the most recent version became effective on January 25, 2005. Each NGDU, however, is entitled to provide additional benefits to its employees if it so chooses. Most employees are members of the Tatneft employees’ union, which acts for those employees in discussions with management. Nizhnekamskshina also has a collective labor agreement applicable to all of its employees. To date, we have not experienced any material labor disputes, strikes or legal actions, and we believe that our relations with our employees are good.

We maintain a pension plan pursuant to the collective labor agreement that entitles employees who have worked with Tatneft for more than ten years and retired before the establishment of our discretionary pension fund to receive on a quarterly basis 7.5% of the base sum in the amount of RR4,500, plus 0.75% for each year of employment over ten years provided, however, that the aggregate amount of payments thereunder may not exceed RR1,500 per quarter. In 1997, we established a new discretionary pension fund, in which employees, who have worked for us for more than ten years may participate. Tatneft pays a portion of the contributions for participants in this plan. At December 31, 2003, there were 53,262 employees participating in the discretionary pension fund. In addition to these pension plans, employees can obtain a number of formal and informal benefits, including bonuses for those who travel frequently, compensation for work-related injuries and losses, and one-time severance pay for workers who are laid off. The liabilities represented by these plans and benefits are not currently material to our financial condition or results of operations. However, the cost of such plans may become significant in the future.

We also have an incentive plan through which we allocate a certain portion of net profits to purchase Ordinary Shares on the secondary market for distribution under our stock option compensation program. In 2001 and 2002, we issued options to purchase 9,359,000 and 9,300,000 Ordinary Shares, respectively, to the members of the Board of Directors and the Executive Board. We repurchased the option certificates from holders at market value upon such option certificates becoming exercisable. In 2003, we issued further options to purchase 9,300,000 Ordinary Shares, respectively, to members of the Board of Directors and senior managers. In 2004, we repurchased these option certificates issued from holders at market value upon such option certificates becoming exercisable. See “Item 7—Major Shareholders and Related Party Transactions—Related Party Transactions” and“—Compensation” under this Item.

SHARE OWNERSHIP

No single Director or executive officer owned in excess of one percent of our outstanding capital stock as at May 12, 2005. Moreover, our directors and members of the Executive Board, as a group (27 persons) own less than one percent of our capital stock. The following table sets forth information concerning the direct ownership of our Ordinary Shares for all directors and members of the Executive Board as at May 12, 2005.

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Name	Number of Ordinary Shares	Ordinary Share Ownership Percentage
Rustam Nurgalievich Minnikhanov	None	None
Shafagat Fahrazovich Takhautdinov	2,699,700	0.1239
Rishat Fazlutdinovich Abubakirov	1,356,500	0.0622
Radik Raufovich Gaizatullin	None	None
Sushovan Ghosh	None	None
Nail Gabdulbarievich Ibragimov	450,400	0.0206
Rais Salikhovich Khisamov	430,200	0.0197
Vladimir Pavlovich Lavushchenko	1,050,000	0.0482
Nail Ulfatovich Maganov	None	None
Renat Halliulovich Muslimov	1,716,900	0.0788
Veleriy Yurievich Sorokin	None	None
Migrazian Zakievich Taziev	777,700	0.0357
Valery Pavlovich Vasiliev	None	None
Maria Leonidovna Voskresenskaya	None	None
David William Waygood	None	None
Viktor Isakovich Gorodny	800,00	0.0367
Iskandar Gatinovich Garifullin	326,500	0.0150
Valeriy Dmitrievitch Ershov	None	None
Semyon Afroimovich Feldman	2,380,900	0.1093
Khamid Zagirovich Kaveev	80,400	0.0037
Rustam Nabiullovich Mukhamadeev	92,900	0.0043
Rafael Saitovich Nurmukhametov	620,200	0.0285
Rafkat Mazitovich Rakhmanov	472,300	0.0217
Zagit Foatovich Sharafeev	None	None
Fyodor Lazarevich Shyelkov	686,800	0.0315
Mikhail Nikolaevich Studenskiy	19,200	0.0009
Evgeny Aleksandrevich Tikhturov	42,100	0.0009
Alexander Trofimovich Yukhimets	100,000	0.0046
Vladimir Nikolaevich Zinoviev	None	None

The following table sets forth information concerning the direct ownership by our directors and members of our Executive Board of our Preferred Shares as at May 12, 2005. Directors and members of our Executive Board not listed below do not own any of our Preferred Shares.


Name	Number of Preferred Shares	Preferred Share Ownership Percentage
Migrazian Zakievich Taziev	7,500	0.0051
Khamid Zagirovich Kaveev	345,400	0.2341
Rustam Nabiullovich Mukhamadeev	4,900	0.0033
Rafael Saitovich Nurmukhametov	7,800	0.0053
Mikhail Nikolaevich Studenskiy	7,400	0.0050
Evgeny Aleksandrevich Tikhturov	3,000	0.0020

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ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

MAJOR SHAREHOLDERS

At May 12, 2005, OAO Svyazinvestneftekhim, a joint-stock company wholly-owned by the Republic of Tatarstan, owned 781,404,369 Ordinary Shares, or 33.59% of our capital stock and 35.87% of our Ordinary Shares.

In addition to Svyazinvestneftekhim’s ownership of Ordinary Shares, the Tatarstan government holds the Golden Share. Under Federal law, the holder of the Golden Share has the power to veto major decisions at meetings of shareholders, including:

•

decisions relating to changes in the capital stock;

•

amendments to the Charter;

•

liquidation or reorganization of the company; and

•

entering into major or interested party transactions.

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

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

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

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

In addition to holding the Golden Share in Tatneft, the Tatarstan government holds the Golden Share in our subsidiary Nizhnekamskshina.

Shareholding Structure

Our shareholding structure evolved out of the mass privatization program in Russia that began in 1991. Although there have been some changes since 1991 in the authority of various agencies involved, the privatization process has been regulated and supervised by the Federal State Property Management Committee (the “GKI”) or in some regions, such as Tatarstan, by its regional counterparts (for Tatarstan, the Tatarstan Ministry of Property Management and its predecessors). The privatization program generally required that both management and workers agree on a privatization plan, and that it be approved by the GKI. A plan provided a charter for the new joint-stock company and for the distribution of its shares. Although there were several possible choices, plans generally called for shares to be: (i) given or sold at nominal value or less to management and workers; (ii) sold at tender or auction to third parties; and (iii) held by the state for some specified period of time, often three or five years (with little provision as to what would or could be done with the shares after the specified period). Large blocks of shares (in some cases as much as 51%) were transferred to management and employees. In some cases, workers and management received some shares free of charge (usually Preferred Shares), and were given the right to purchase other shares (usually ordinary voting shares) for nominal value (usually the price to management) or a discount to nominal value (usually the price to workers). Moreover, during the first two years of the privatization program, workers and management were able to purchase shares using privatization vouchers that were issued free to all Russian citizens in October 1992, and that until near the end of the voucher privatization period in 1994 could generally be purchased at a discount to their nominal value. Finally, workers and management, as well as other Russians and in some cases non-Russians, were able to purchase shares in periodic auctions or tenders held by the GKI.

In the case of Tatneft, the Tatarstan State Property Management Committee (the “Tatarstan GKI”), the legal predecessor to the Tatarstan Ministry of Property Management, initially owned all of our shares, and then distributed them pursuant to our privatization plan of January 21, 1994 (the “Privatization Plan”). Workers were given Preferred Shares free of charge, although a

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few were not taken up and were subsequently returned to the Tatarstan GKI. The Tatarstan GKI offered Ordinary Shares representing approximately 30% of the capital stock to workers at 40% of their nominal value, and offered another 5% to management at nominal value. The Tatarstan GKI gave another block of shares to us to use as bonus shares in order to give incentives to workers and management. The Tatarstan GKI sold some shares in domestic auctions. The Tatarstan GKI also transferred a block of 33,000,000 shares to us, which have since been transferred to Tatneft, Solid & Co. and IFK Solid. See “Item 9—The Offer and Listing—Activities of the Company and its Affiliates in the Market.” Finally, the Tatarstan GKI sold Ordinary Shares in a global offering of ADSs, representing the Ordinary Shares, in December 1996. In connection with that transaction, we caused the ADSs to be listed on the LSE and arranged for the ADSs to be listed on the New York Stock Exchange in March 1998 and on the NewEx trading segment of the Frankfurt Stock Exchange (the “NewEx”) in November 2000. Each ADS represents the right to receive twenty ordinary shares.

We have not issued any additional shares since our inception, and the Tatarstan Ministry of Property Management in 2003 contributed to Svyazinvestneftekhim those shares that it has not previously distributed pursuant to the Privatization Plan.

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

Our shareholding structure at May 12, 2005 is summarized below:


	Number of Shares	Percent of Charter Capital
Ordinary Shares
Shares owned by Svyazinvestneftekhim⁽¹⁾⁽²⁾	781,404,369	33.59
Other Ordinary Shares
Held by individuals	110,448,963	4.75
Held by other legal entities⁽³⁾	1,286,837,368	55.32
Total Ordinary Shares	2,178,690,700	93.66
Preferred Shares
Held by individuals	57,842,749	2.49
Held by other legal entities	29,804,877	1.28
Held by non-residents	59,860,874	2.57
Total Preferred Shares	147,508,500	6.34

Total number of shares outstanding	2,326,199,200	100.00

(1)	Svyazinvestneftekhim is 100% owned by the Tatarstan government. The Tatarstan government also holds a Golden Share in Tatneft.

(2)	Includes 73,209,590 Ordinary Shares, representing 3.15% of our charter capital and 3.36% of our Ordinary Shares, which are owned by OOO Investneftekhim, a subsidiary of Svyazinvestneftekhim.

(3)

Includes 493,351,080 Ordinary Shares, representing 21.2% of our charter capital and 22.6% of our Ordinary Shares, which were held through our ADR program, with 40 registered and 2,400 beneficial holders of such shares, of which over 1,300 holders were U.S. holders. See “Item 9—The Offer and Listing—Markets—The ADS Market.”

The following table sets forth information as of May 12, 2005 regarding the record ownership of Ordinary Shares by shareholders who own more than 5% of such shares and by the directors and executive officers as a group:


Ordinary Shareholders⁽¹⁾	Number of Ordinary Shares	Percent of Ordinary Shares
Svyazinvestneftekhim⁽²⁾	781,404,369	35.87
UBS AG	176,457,216	8.10
Directors and executive officers as a group	15,910,600	0.73

(1)	At December 31, 2003, approximately 191,430,258 of our Ordinary Shares, representing approximately 8.8% of our Ordinary Shares, were held by our subsidiaries and classified as treasury stock under U.S. GAAP. However, under Russian law, shares held by subsidiaries may vote and receive dividends.

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(2)	Includes 73,209,590 Ordinary Shares, representing 3.15% of our charter capital and 3.36% of our Ordinary Shares, which are owned by OOO Investneftekhim, a subsidiary of Svyazinvestneftekhim.

OAO UK Nikoil-Sberezheniye, acting in trust for the Fund for Assistance in Comprehensive Research in the Energy Industry and UBS AG were registered owners of over 5% of our Ordinary Shares as of October 1, 2004, and TAIF acquired in excess of 5% of our Ordinary Shares in late 1998. However, as of May 12, 2005, both OAO UK Nikoil-Sberezheniye and TAIF held less than 5% of our shares. We are not currently aware of any arrangements that might result in a future change in control.

Our major shareholders have the same voting rights per share as other shareholders. See “Item 10—Additional Information—Memorandum and Articles of Association—Voting Rights.”

RELATED PARTY TRANSACTIONS

Svyazinvestneftekhim, which is wholly-owned by the Tatarstan government, is our largest shareholder, owning 33.59% of our capital stock and 35.87% of our Ordinary Shares. The Tatarstan government also holds the Golden Share. See “—Major Shareholders” under this Item. Currently, four of our directors, including the Chairman of the Board, are senior members of the Tatarstan government, and one of our other directors is the CEO of TAIF, an entity partially owned by the Tatarstan government. In the ordinary course of business, we regularly enter into transactions with other entities that are controlled, either directly or indirectly, by the government of Tatarstan. These enterprises include, among others, Tatenergo, TAIF and Nizhnekamskneftekhim. In addition, the Tatarstan government owns 28.8% of Ukrtatnafta, the owner of the Kremenchug oil refinery in Ukraine and one of the major customers for our high sulfur content crude oil. In 2002, we purchased approximately 16,767 hectares of land underneath most of our properties in Tatarstan from the Tatarstan government for approximately RR330 million.

Over the course of 2003, the Company arranged for the purchase of its own shares in anticipation of establishing a stock-based compensation scheme for senior management. See “Item 15—Controls and Procedures” and Note 19 to our audited consolidated financial statements included in this annual report. This scheme was never adopted and the shares are reflected as treasury stock in the Company’s financial statements.

In 2003, we entered into an arrangement to lease fixed assets, primarily related to the production of oil and natural gas, from ZAO Univest-Holding, of which we hold 34.5%, accounted for under the equity method, and controlled an additional 9% through Bank Zenit. As of December 31, 2003, we had capital lease obligations to ZAO Univest-Holding of RR1,002 million. See Note 19 to our consolidated financial statements.

In addition, in 2003 and 2004 we made a significant portion of our export sales of crude oil to Efremov Kautschuk GmbH, a subsidiary of OAO “Efremovsky Zavod Sinteticheskogo Kauchuka,” which sells the crude oil outside of Russia and the CIS. OAO “Efremovsky Zavod Sinteticheskogo Kauchuka” is a related party to us as members of our senior management are on its board of directors.

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 Tupras. Subsequently Efremov Kautschuk GmbH formed a consortium with Zorlu Holding A.S. and established a joint venture, Tatneft-Zorlu, of which we agreed to purchase 50% if Tatneft-Zorlu acquired shares in Tupras. On June 6, 2004, Turkey’s Administrative Court invalidated the tender for the sale of 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 September 2004, we entered into a RR2,000 million loan agreement with Svyazinvestneftekhim. The amount of loan outstanding as of December 31, 2004 was RR2,000 million. The loan interest rate is 0.01% per annum and matures in March 2014.

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

INTERESTS OF EXPERTS AND COUNSEL

This Item is not applicable.

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ITEM 8. FINANCIAL INFORMATION

CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

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

EXPORT SALES

Export sales (outside the CIS) of oil and refined products were RR89,461 million, RR77,854 million, RR80,038 million, RR126,279 million, and RR47,352 million or 51%, 54%, 51%, 63%, and 56% of total revenue for the years ended December 31, 2003, 2002, 2001, 2000 and 1999, respectively.

LEGAL PROCEEDINGS

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

In January 2004, a consortium consisting of Efremov Kautschuk GmbH, acting on our behalf, and Zorlu Holding A.S., was pronounced the winner of a privatization auction for 65.8% of Turkey’s oil refining monopoly Tupras. On June 3, 2004, Turkey’s Administrative Court invalidated the tender for the sale of controlling stake in Tupras in a suit brought by the trade union representing Tupras workers. The Turkish Privatization High Board appealed this ruling to Turkey’s Supreme Administrative Court which affirmed the decision invalidating the tender in November 2004.

DIVIDENDS AND DIVIDEND POLICY

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

The table below illustrates our dividend policies over the five-year period and our interim dividend paid in 2004.

Per Share Dividends on Ordinary and Preferred Shares⁽¹⁾


	1999			2000			2001			2002			2003			2004⁽²⁾
Class of Shares	% of nominal value		Share Dividend (RR)	% of nominal value		Share Dividend (RR)	% of nominal value⁽³⁾		Share Dividend (RR)	% of nominal value		Share Dividend (RR)	% of nominal value		Share Dividend (RR)	% of nominal value		Share Dividend (RR)
Ordinary Shares⁽⁴⁾	100	%	0.10	300	%	0.30	10	%	0.10	10	%	0.10	30	%	0.30	67	%	0.67
Preferred Shares	150	%	0.15	600	%	0.60	100	%	1.00	100	%	1.00	100	%	1.00	100	%	1.00

(1)	Dividends for all periods are stated in nominal rubles.

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(2)	An interim dividend for the nine months ended September 30, 2004 was approved by an extraordinary general meeting of our shareholders held on November 6, 2004. This interim dividend was paid out as of January 1, 2005.

(3)	In 2001, the nominal value of both classes of our shares was increased from 10 kopeks to RR1.00 per share.

(4)	One ADS represents 20 Ordinary Shares. The U.S. dollar amount of the ADS dividend is determined by the exchange rate used by the Depositary to convert the dividend to U.S. dollars on the date of payment.

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.

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

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

SIGNIFICANT CHANGES

On December 6, 2002, we filed a lawsuit in the Arbitration court of Tatarstan against the Tax Ministry of Tatarstan claiming a refund for mineral use tax (royalty tax) in the amount of RR2,251 million. On January 17, 2003, the Arbitration court ruled in our favor and allowed us to apply this amount against future tax payments. The Tax Ministry of Tatarstan appealed this decision, but the Federal Arbitration court of the Povolzhsky district and the Russian Supreme Arbitration Court upheld the decision in our favor. We recorded the gain of RR2,251 million in Tatneft’s Russian statutory accounts for the first quarter of 2004 when we offset the income tax, VAT and tax on production of commercial minerals liability against the amount of the claim. This gain was be reflected in our consolidated financial statements prepared in accordance with the U.S. GAAP for the year ended December 31, 2003.

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.

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

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ITEM 9. THE OFFER AND LISTING

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

MARKETS

The ADS Market

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

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


	U.S.$ per ADS⁽¹⁾
Period	High	Low
1999	9.50	1.38
2000	14.50	6.50
2001	11.73	6.69
2002	17.05	9.88
First Quarter	14.02	9.88
Second Quarter	17.05	12.64
Third Quarter	15.83	11.16
Fourth Quarter	16.91	14.70
2003	26.90	14.25
First Quarter	18.11	14.14
Second Quarter	23.70	16.45
Third Quarter	23.00	18.02
Fourth Quarter	26.90	18.55
2004	37.00	21.47
First Quarter	27.82	22.80
Second Quarter	30.20	22.99
June	26.57	24.30
July	25.05	21.47
August	26.75	21.80
September	31.94	26.88
October	37.00	32.72
November	35.50	30.16
December	30.16	27.21
2005
January	31.89	27.45
February	35.92	31.12
March	36.48	31.65
April	35.34	32.82
May	34.00	31.30
June	36.99	34.52

(1)	The ratio of Ordinary Shares to ADSs is 20:1.

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


	U.S.$ per ADS⁽¹⁾
Period	High	Low
1999	7.15	1.55
2000	14.45	6.58
2001	11.70	6.38
2002	17.20	9.80
First Quarter	14.10	9.80
Second Quarter	17.20	12.75
Third Quarter	15.90	11.40
Fourth Quarter	16.90	14.80
2003	26.90	14.40
First Quarter	18.45	14.36
Second Quarter	24.00	16.50
Third Quarter	23.11	17.80
Fourth Quarter	27.16	18.15
2004	37.00	21.15
First Quarter	28.00	22.50
Second Quarter	29.45	25.88
June	26.50	25.53
July	25.50	21.15
August	26.65	21.60
September	32.00	26.35
October	37.00	32.93
November	35.25	29.50
December	31.00	26.75
2005
January	31.99	27.18
February	36.25	30.85
March	41.00	32.05
April	35.50	33.10
May	34.25	31.00
June	37.20	34.18

(1)	The ratio of Ordinary Shares to ADSs is 20:1.

In June 1996, we launched a program, registered with the SEC, for ADRs representing Ordinary Shares or rights to receive Ordinary Shares. In December 1996, we established two unregistered American depositary receipt programs (the “Restricted ADR Program” and the “Regulation S ADR Program”) in connection with an international offering of certain of our Ordinary Shares in the United States and elsewhere pursuant to Rule 144A and Regulation S under the Securities Act. In March 1998 we merged these two ADR programs into one registered ADR program (the “Registered ADR Program”) in connection with listing the ADRs on the New York Stock Exchange. We also exchanged ADRs issued under the Restricted ADR Program for ADRs issued under the Registered ADR Program, and we formally abolished the Restricted ADR Program in 1999. According to the records of the Depository Trust Company, as of May 12, 2005 there were 40 registered and 2,400 beneficial holders (of which over 1,300 holders were U.S. holders) of 24,667,554 ADRs under the Registered ADR Program. In the aggregate, these holdings constituted approximately 22.6% of our total issued Ordinary Shares, and approximately 21.2% of our capital stock. Since brokers and other nominees hold certain of the ADRs, the above numbers may not represent the actual number of U.S. beneficial holders or of Ordinary Shares or ADRs beneficially held by U.S. persons.

According to the Law on the Securities Markets 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

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programs established after the time of its enactment. There have been articles in the press stating that in January 2004 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 FSFM for this company. We have never applied for FSFM permission for our ADR program. In addition, the number of the Ordinary Shares deposited in our ADR program constitutes 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%. Accordingly, we can give no assurance that The Bank of New York, acting as a depositary for our ADR programs, 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. See “Item 3—Key Information—Risk Factors—The rights of non-Russian residents to own or vote our shares or ADSs may be subject to restrictions.”

The Ordinary Share Market

Trading in Ordinary Shares within Russia has grown significantly since 1996. The primary markets for the Ordinary Shares are the RTS and MICEX. The Ordinary Shares were first quoted on the RTS on October 17, 1995 and listed on MICEX on August 20, 1999.

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


	U.S.$ per Ordinary Share
Period	High	Low
1999	0.38	0.07
2000	0.71	0.33
2001	0.58	0.32
2002	0.85	0.49
First Quarter	0.71	0.50
Second Quarter	0.86	0.62
Third Quarter	0.80	0.55
Fourth Quarter	0.85	0.74
2003	1.35	0.72
First Quarter	0.91	0.71
Second Quarter	1.22	0.83
Third Quarter	1.14	0.87
Fourth Quarter	1.33	0.91
2004	1.86	1.06
First Quarter	1.38	1.13
Second Quarter	1.49	1.16
June	1.32	1.24
July	1.30	1.06
August	1.32	1.06
September	1.61	1.32
October	1.86	1.63
November	1.76	1.47
December	1.47	1.36
2005
January	1.58	1.43
February	1.80	1.56
March	1.83	1.58
April	1.77	1.68
May	1.72	1.55
June	1.85	1.73

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The following table shows, for each period indicated, the reported highest and lowest denominated middle market prices for the Ordinary Shares on the MICEX. These prices are reported in rubles.


	RR per Ordinary Share
Period	High	Low
1999	9.20	3.51
2000	20.35	9.90
2001	16.90	9.36
2002	16.90	9.36
First Quarter	22.00	15.32
Second Quarter	26.57	20.09
Third Quarter	25.17	17.69
Fourth Quarter	26.94	14.35
2003	41.28	22.58
First Quarter	29.37	22.63
Second Quarter	38.60	22.58
Third Quarter	35.60	22.53
Fourth Quarter	41.28	26.80
2004	56.75	29.95
First Quarter	40.48	30.20
Second Quarter	43.00	33.00
June	39.51	33.00
July	38.10	29.95
August	39.20	31.70
September	47.10	38.02
October	56.75	45.80
November	51.50	41.50
December	44.40	36.58
2005
January	45.44	38.45
February	50.19	38.32
March	50.90	43.95
April	50.36	44.81
May	48.25	43.01
June	53.15	47.85

Activities of the Company and its Affiliates in the Market

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

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

Tatneft, IFK Solid and OAO Zenta are the only general partners in the LP. At May 24, 2005, there were 90 limited partners, mainly Tatneft employees (including our directors and executive officers), who generally contributed unrestricted Ordinary Shares to the LP in exchange for their limited partnership interests. The general partners are entitled to 20% of the LP’s net income, and the limited partners to 80%. The general partner and each limited partner share in the net income allocable to its class pro rata to its contribution to the LP. At May 24, 2005, the LP held 2,455,355 Ordinary Shares. See “—The Ordinary Share Market” under this Item.

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

In addition, our wholly-owned subsidiary Tatneft Oil AG has in the past participated in the market for our Ordinary Shares, and this activity may continue in the future.

Overall, at December 31, 2003, approximately 191,430,258 Ordinary Shares were held by our subsidiaries and classified as treasury stock under U.S. GAAP, compared to approximately 200,288,083 Ordinary Shares at December 31, 2002 and approximately 176,133,000 Ordinary Shares at December 31, 2001. Under Russian law, shares held by subsidiaries may vote and receive dividends.

Share Registrar

Our share register is currently held by Aktsionerny Kapital, which holds both federal and Tatarstan licenses to act as a share registrar. In the case of trades of Tatneft shares that involve licensed Russian broker-dealers, a transaction will ordinarily be registered by Aktsionerny Kapital solely on the basis of a transfer order. In the case of a transaction in which neither party is a licensed broker-dealer, additional documentation — including a transfer order, signature verifications and properly executed powers-of-attorney — is required. To facilitate trading, Aktsionerny Kapital has departments that act as transfer agents in Moscow and Kazan. These arrangements ordinarily obviate the need for traders in Moscow and Kazan to travel to Almetyevsk to execute a trade. The registrar generally charges the maximum rates permitted by Russian law for various registrar actions. The maximum rates for these transactions currently include: (i) for opening an account, RR10; (ii) for registration of a transaction, 0.2% of the transaction price up to RR8 million, depending on the value of the transaction; (iii) for amendments or additions to the information on a registered person, RR30; and (iv) for issuing an extract from the share register, RR10.

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

Aktsionerny Kapital was established as an open joint-stock company in December 1996 and received capital contributions from five entities, including Tatneft and Bank Devon-Credit. We have been informed that Aktsionerny Kapital has expanded its operations to act on behalf of other companies in Tatarstan. At March 31, 2005, it acted as share registrar for 287 companies.

The FSFM regulations currently require that the share register of any Russian company with more than 500 shareholders, such as Tatneft, be held by a specialized registrar and that no shareholder of a specialized registrar own more than 20% of the registrar’s share capital. Tatneft owns less than 20% of the shares of Aktsionerny Kapital. The FSFM regulations also generally prohibit (with a few exceptions) a specialized registrar from carrying out any activities other than those of a share registrar, and require that the specialized registrar obtain a license from the FSFM.

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

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ITEM 10. ADDITIONAL INFORMATION

MEMORANDUM AND ARTICLES OF ASSOCIATION

Tatneft is a Russian Open Joint-Stock Company. Tatneft’s affairs are governed by the Joint-Stock Companies Law, as amended, and the Tatarstan Privatization Law. In addition, our affairs are governed by the Charter and Provisions On the Executive Board, Provisions On the Board of Directors, Provisions On the General Director and Provisions On the Revision Committee, each as approved by the shareholders at the June 28, 2002 annual shareholders’ meeting.

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

Directors

Our Board of Directors consists of 15 members elected by cumulative voting at the annual shareholders’ meeting held on June 30, 2005. The term of office of a Director is until the next annual shareholders’ meeting. In cumulative voting, a shareholder may cast a number of votes for one or more nominees for the Board equal to the number of voting shares held by such shareholder multiplied by the number of directors to be elected.

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

Authorized Capital and Dividends

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

Our Board of Directors recommends the payment of interim and annual dividends to our shareholders, who approve such interim and annual dividends by a majority vote at the shareholders’ meeting. The dividends approved at the shareholders’ meeting may not be more than the amount recommended by the Board. Dividends are distributed to shareholders entitled to participate in the shareholders’ meeting that is approving the dividend. Dividends are not paid on treasury shares held by Tatneft.

Holders of Preferred Shares are entitled to a dividend of 100% of the nominal value of their shares unless otherwise decided by the shareholders’ meeting. However, if a dividend declared on the Ordinary Shares is greater than 100% of the nominal value of the Preferred Shares, holders of the Preferred Shares are entitled to receive dividends of at least equal value to the dividend declared on the Ordinary Shares.

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

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the share capital has been paid in full;

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the value of our net assets, minus the proposed dividend payment, is not less than, and would remain following the payment of dividends, not less than the sum of our share capital and reserve fund;

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we have repurchased all shares from shareholders who have exercised their right to demand repurchase; and

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we are not, and would not become as a result of the payment of dividends, insolvent.

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

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Voting Rights

Each fully paid Ordinary Share, except for treasury shares held by OAO Tatneft, gives its holder the right to participate in shareholders’ meetings and vote on matters to be decided thereby. Holders of Preferred Shares are generally not entitled to vote at the shareholders’ meetings. However, both the Charter and the Joint-Stock Companies Law entitle preferred stockholders to vote on changes and additions to the Charter where such changes provide for reorganization or liquidation of the Company, limitation of their rights, including the issuance of preferred shares with broader rights than those of the existing preferred shares, or change the amount of dividends on the Preferred Shares. Holders of preferred shares are also entitled to vote at the shareholders’ meeting on any items that may appear on the agenda in the event that we fail to declare a dividend on Preferred Shares in full.

Shareholders’ Meetings

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

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election of members of the Board of Directors;

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election of members of the Revision Committee;

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approval of the annual report, balance sheet, and profit and loss statement;

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approval of any distribution of profits, except net profit that has been distributed as quarterly dividends or losses; and

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approval of an independent auditor.

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

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

The quorum for a shareholders’ meeting constitutes presence in person or through authorized representatives of holders of more than 50% of our voting shares. Shareholders are entitled to participate in the shareholders’ meeting by forwarding a bulletin to us provided such bulletin is received at least two days before the meeting, except as to the election of Board members, members of the internal audit commission, appointment of the independent auditor, approval of annual reports and annual financial statements, profits distributions (including declaring dividends) and the covering of losses. If the quorum requirement is not met, another shareholders’ meeting must be scheduled, in which case the quorum requirement is met if shareholders owning at least 30% of the issued voting shares have registered at that meeting. Shareholders may participate in meetings by proxy, provided that the proxy holds a power of attorney issued by the shareholder.

Notice and Participation

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

Liquidation

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

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

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

(1)

individuals owed compensation for injuries or deaths caused by a company;

(2)

employees;

(3)

creditors with claims secured by pledges of a company’s property;

(4)

federal and local governmental budgets; and

(5)

other creditors in accordance with Russian law.

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

(1)

payments to repurchase shares from shareholders having the right to demand repurchase;

(2)

payments of declared but unpaid dividends on Preferred Shares and the liquidation value of Preferred Shares, if any; and

(3)

payments to holders of Ordinary Shares and Preferred Shares on a pro rata basis.

Limitations on Share Ownership

There are currently no restrictions under the Charter or under Russian or Tatarstan law that limit the right of non-Russian residents or persons to own or vote our shares either directly or through an ADR program. However, under the Law on the Securities Markets and FSFM regulation, 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. There have been articles in the press stating that in January 2004 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 for FSFM permission for our ADR program. In addition, the number of the Ordinary Shares deposited in our ADR program constitutes 22.6% of our Ordinary Shares and we may be required to limit the amount of the Ordinary Shares deposited in ADR program to 40%. 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 violation of 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. See “Item 3—Key Information—Risk Factors—Risks Relating to Investment in our ADSs.”

Approval of the Federal Antimonopoly Service of the Russian Federation

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

Preemptive Rights

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

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Redemption Provisions

The Joint-Stock Companies Law provides that holders of voting shares can require us to repurchase all or a portion their shares in the event of (i) our reorganization or certain major transactions, or (ii) amendments or restatements of our charter that restrict such shareholder’s rights, in both cases where such shareholders voted against or did not participate in the vote regarding the reorganization, major transaction or amendment or restatement of our charter. We are required to repurchase shares in the above circumstances at a price determined by our Board, provided that such price may not be less than the market value of the shares as determined by an independent appraiser.

Change of Control Provisions

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

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

Additionally, within 30 days of any such acquisition, the acquiring shareholder must offer to the other shareholders to buy all of the issued Ordinary Shares and securities convertible into Ordinary Shares, if any, at their market price, which should not be less than the weighted-average acquisition price of the Ordinary Shares over the six months before the date of the acquisition. The same requirement applies at each five percent increment over the initial 30% threshold. Under the Joint-Stock Companies Law, shareholders holding a majority of the issued Ordinary Shares present at a shareholders’ meeting, excluding the vote of the person acquiring shares and that person’s affiliates, may elect to waive this requirement. Alternatively, the Joint-Stock Companies Law allows us to waive this requirement in our Charter. Our Charter does not contain a waiver of, and our shareholders have not waived, this mandatory offer requirement. Moreover, the listing rules, promulgated by the Federal Service for the Financial Market and applicable to us, bar us from waiving this mandatory offer requirement. If the acquiring person fails to make the required offer, it may vote only those shares that have been acquired in accordance with the above procedures.

MATERIAL CONTRACTS

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

EXCHANGE CONTROLS

Capital import and export restrictions

In December 2003, President Putin signed into law the Exchange Control Law. Most provisions of the Exchange Control Law came into effect in June 2004. The Exchange Control Law significantly liberalizes the exchange control regime in Russia and 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 government and the Central Bank are able to impose mandatory reserve requirements and require use of special accounts for certain transactions of Russian residents with non-residents.

The statute provides that any restrictions on operations are introduced only to prevent significant reduction in reserves, sharp movements in the exchange rate of the ruble, as well as to support Russia’s balance of payments. Such restrictions should be of a non-discriminatory nature and should be eliminated by the currency authorities upon elimination of circumstances that caused implementation of such restrictions. It appears that these formulations are non-precise and thus provide too much flexibility and discretion for the currency authorities to maintain the specified restrictions.

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Russian currency legislation generally allows:

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foreign investors to repatriate income in rubles received from investments in Russia (including profits, dividends and interest) (subject to the rules applicable to non-resident bank accounts and the conversion of rubles into foreign currencies); and

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legal entities to convert rubles into foreign currency for the purposes of making dividend payments to foreign investors and meeting their foreign currency obligations.

The Central Bank may impose a requirement for a non-resident to use a special account in connection with the following currency operations between residents and non-residents:

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making loans by residents to non-residents in rubles;

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receipt of loans by residents from non-residents in rubles;

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operations with external securities, including settlements in connection with transfer of external securities (or rights evidenced by such securities);

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performance by residents of obligations under external securities;

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purchase by non-residents from residents of rights to internal securities, including settlements in connection with transfer of internal securities (or rights evidenced by such securities); and

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purchase by residents from non-residents of rights to internal securities, including settlements in connection with transfer of internal securities (or rights evidenced by such securities), as well as performance by residents of their obligations under internal securities.

Russian exporters are required to repatriate 100% and convert into rubles 10% of foreign currency export proceeds though in the past the requirement has been as high as 75%. Like other Russian companies, we are required to convert up to 10% of all hard currency earnings into rubles unless we obtain an exemption. Under legislation effective from July 7, 2003, the maximum percentage that must be converted was reduced from 50% to 30%. On July 9, 2003, the Central Bank adopted regulations that require the conversion of 25% of such proceeds, and on November 26, 2004 the Central Bank adopted regulations that reduced the requirement to 10%, effective from December 27, 2004.

Russian resident and non-resident companies may exchange rubles for foreign currency and back (including for the purposes of payments of interest and dividends) through special accounts and subject to certain reserve requirements imposed by the Central Bank.

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

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

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

Under the terms of the Deposit Agreement, to which we, the Depositary, and the registered owners of ADRs and the owners of a beneficial interest in book-entry ADRs are parties, ADSs may be sold in Russia to Russian residents without restrictions. However, the Federal Law on Currency Control and Currency Regulation restricts acquisition of foreign securities (including ADSs) by Russian investors by requiring that they conduct these operations through special banking accounts with authorized Russian banks and deposit in a special non-interest bearing account with an authorized Russian bank a monetary sum of 25% of the amount paid for the securities for 15 days.

These arrangements, together with applicable conversion fees and limitations on immediate repatriation, may increase the costs of such repatriation. Furthermore, weaknesses in the existing banking infrastructure may limit the actual transfer within, and the remittance of funds out of, Russia.

The ability of the Depositary and other persons to convert rubles into U.S. dollars (or another hard currency) is also subject to the availability of U.S. dollars (or such other hard currency) in Russia’s currency markets. Although there is currently a market

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within Russia for the conversion of rubles into U.S. dollars and other foreign currencies, including the interbank currency exchange and over-the-counter and currency futures markets, this market may not continue to exist in its present or a substantially comparable form in the future. At present, there is no market for the conversion of rubles into foreign currencies outside of Russia and no viable market in which to hedge ruble-currency and ruble-denominated investments.

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TAXATION

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

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

Russian Tax Considerations

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

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

General comments

For the purposes of this summary, a “Non-Resident Holder” means: a physical person, physically present in the Russian Federation for less than 183 days in a given calendar year; or a legal person or entity not incorporated or otherwise organized in the Russian Federation (with no tax registration in Russia), which holds and disposes of our ordinary shares or ADSs other than through a permanent establishment in Russia. Russian income tax obligations of a Non-Resident Holder may arise with respect to income from a Russian source. Russian tax law does not provide a general definition as to what constitutes Russian source income; however, specific types of income, including dividends and capital gains on disposal of shares in certain Russian companies, are referred to as Russian source income for both individual and corporate Non-Resident Holders.

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

Taxation of dividends

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

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

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

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

Taxation of capital gains

Taxation of legal entities

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

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

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

Taxation of individuals

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

A Non-Resident Holder that is an individual may recognize income as the difference between sale proceeds and the cost of acquisition plus all actual expenses relating to the acquisition, holding and disposition of shares or ADSs. Where the expenses are not documented and cannot be confirmed, the full sale proceeds are subject to tax.

The income tax of a Non-Resident Holder that is an individual must be collected by a tax agent via a withholding procedure. If a tax agent is a professional participant of the securities market (broker, trust manager, or any person acting under an agency or similar agreement for the individual), income tax should be withheld from gross proceeds from the sale of shares or ADSs less deduction of eligible costs and expenses. In other cases, when a tax agent is technically required to withhold income tax from

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gross sales proceeds, the individual may later claim a deduction for costs and expenses based on a tax declaration to be filed with Russian tax authorities at the end of the reporting period. A refund of any overpayment of personal income tax in relation to disposition of our ordinary shares or ADSs may be claimed on the basis of the tax declaration filed by the individual Non-Resident Holder. There is a significant uncertainty regarding the availability and timing of such refunds.

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

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

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

It should be noted that all capital gains should be calculated in the currency in which a Non-Resident Holder receives such income.

Procedure for obtaining double tax treaty relief

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

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

If tax treaty relief is not obtained and income tax is withheld by a tax agent on capital gains or other amounts, a Non-Resident Holder that is an organization as defined by the Russian Tax Code may apply for a tax refund within 3 years from the end of the tax period in which the tax was withheld. To process a claim for a refund, the Russian tax authorities require (i) a confirmation of the tax residence of a Non-Resident Holder in a state with which Russia has concluded the relevant treaty at the time the income was paid; (ii) an application for refund of the income tax withheld in a format provided by the Russian tax authorities; and (iii) copies of the relevant contracts and payment documents confirming the payment of the income tax withheld to the appropriate Russian authorities (Form 1012DT (2002) is designed to combine (i) and (ii) for foreign organizations). The Russian tax authorities may require a Russian translation of some documents. Under the provisions of the Russian Tax Code, the refund of the tax withheld should be granted within one month after the submission of the documents. However, procedures for processing such claims have not been clearly established, and there is significant uncertainty regarding the availability and timing of such refunds.

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

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

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Information for U.S. holders. A U.S. corporate holder seeking to obtain relief from Russian withholding tax under the U.S./Russia Double Tax Treaty must provide a confirmation of its tax residence that complies with the applicable double tax treaty in advance of receiving income. U.S. holders may obtain such confirmation by submitting a Form 8802 and all the required statements and documentation to the Internal Revenue Service, Philadelphia Service Center, U.S. Residency Certification Request, P.O. Box 16347, Philadelphia, PA 19114-0447 U.S.A. The procedures for obtaining certification are described in greater detail in Internal Revenue Service Publication 686.

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

Russian tax reporting obligation of a Non-Resident Holder

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

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

United States Federal Income Tax Considerations

The following is a general description of the material United States federal income tax consequences that apply to you if you are a beneficial owner of ADSs or Ordinary Shares who is a U.S. holder. For purposes of this summary, a “U.S. Holder” is a beneficial owner of ADSs or Ordinary Shares that is:

•

a citizen or resident of the United States;

•

a United States domestic corporation; or

•

otherwise subject to United States federal income tax on a net income basis with respect to income from the ADSs or Ordinary Shares.

If a partnership (including any entity treated as a partnership for United States federal income tax purposes) is a beneficial owner of ADSs or Ordinary Shares, the United States federal income tax treatment of a partner in the partnership will generally depend on the status of the partner and the activities of the partnership. Since your United States federal income and withholding tax treatment may vary depending upon your particular situation, you may be subject to special rules not discussed below. Special rules will apply, for example, if you are:

•

an insurance company;

•

a tax-exempt organization;

•

a financial institution;

•

a person subject to the alternative minimum tax;

•

a person who is a broker-dealer in securities;

•

an S corporation;

•

an expatriate subject to Section 877 of the United States Internal Revenue Code;

•

an owner, directly, indirectly or by attribution, of 10% or more of the outstanding Ordinary Shares; or

•

an owner holding ADSs or Ordinary Shares as part of a hedge, straddle, synthetic security or conversion transaction.

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

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

Taxation of Dividends on Ordinary Shares or ADSs

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

Subject to certain exceptions for short-term and hedged positions, the U.S. dollar amount of dividends received by an individual prior to January 1, 2009 with respect to the ADSs will be subject to taxation at a maximum rate of 15% if the dividends are “qualified dividends.” Dividends paid on the ADSs will be treated as qualified dividends if (i) the ADSs are readily tradable on an established securities market in the United States and (ii) Tatneft was not, in the year prior to the year in which the dividend was paid, and is not, in the year in which the dividend is paid, (a) a passive foreign investment company (“PFIC”) or (b) for dividends paid prior to the 2005 tax year, a foreign personal holding company (“FPHC”) or foreign investment company (“FIC”). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed. Based on Tatneft’s audited financial statements and relevant market and shareholder data, Tatneft believes that it was not treated as a PFIC, FPHC or FIC for U.S. federal income tax purposes with respect to its 2003 and 2004 taxable years. In addition, based on Tatneft’s financial statements and its current expectations regarding the value and nature of its assets, the sources and nature of its income Tatneft does not anticipate being treated as a PFIC for its 2005 taxable year.

The U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs or common stock and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to establish that dividends are treated as qualified dividends. Because such procedures have not yet been issued, it is not clear whether Tatneft will be able to comply with them. Holders of ADSs and Ordinary Shares should consult their own tax advisers regarding the availability of the reduced dividend tax rate in the light of their own particular circumstances.

If a dividend distribution is paid in rubles, the amount includible in income will be the U.S. dollar value of the dividend, calculated using the exchange rate in effect on the date the dividend is includible in income by you in accordance with your method of accounting, regardless of whether the payment is actually converted into U.S. dollars. Any gain or loss resulting from currency exchange rate fluctuations during the period from the date the dividend is includible in your income to the date the rubles are converted into U.S. dollars will be treated as ordinary income or loss. You may be required to recognize foreign currency gain or loss on the receipt of a refund of Russian withholding tax pursuant to the U.S./Russia Double Tax Treaty to the extent the United States dollar value of the refund differs from the dollar equivalent of that amount on the date of receipt of the underlying dividend.

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

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

Taxation on Sale or Exchange of Ordinary Shares or ADSs

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

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

If Russian tax is withheld on the sale of Ordinary Shares or ADSs, you may not be entitled to credits for the amount withheld in spite of the procedures for claiming refunds under the U.S./Russia Double Tax Treaty. Moreover, the practical likelihood that refunds will be made available in a timely fashion is uncertain.

Information Reporting and Backup Withholding

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

DOCUMENTS ON DISPLAY

We are subject to informational requirements of the Exchange Act applicable to foreign private issuers and, in accordance therewith, file annual reports on Form 20-F with the SEC and submit current reports on Form 6-K and other information and documents to the SEC. You may read and copy any materials we file with or submit to the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549 or the SEC’s website http://www.sec.gov. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330 or, from outside the United States, at 1-202-942-8090.

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ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Foreign Currency Risk

Our principal exchange rate risk involves changes in the value of the ruble relative to the U.S. dollar. At December 31, 2003, approximately RR20,237 million of our indebtedness was denominated in U.S. dollars (out of approximately RR26,009 million of our total indebtedness at that date). Decreases in the value of the ruble relative to the U.S. dollar will increase the cost in rubles of our foreign currency denominated costs and expenses and of our debt service obligations for foreign currency denominated indebtedness. A depreciation of the ruble relative to the U.S. dollar will also result in foreign exchange losses as the ruble value of our foreign currency denominated indebtedness is increased. We believe that the risks associated with our foreign currency exposure are mitigated by the fact that a significant portion of our revenues, approximately 65.3%, are U.S. dollar-denominated, and thus more closely matched to our foreign currency costs and debt service obligations. Furthermore, total loans and accounts receivable of RR21,985 million at December 31, 2003 were also U.S. dollar based, and serve to mitigate our exposure to foreign currency fluctuations. As of May 18, 2005, the ruble had increased in value against the U.S. dollar by approximately 5% since December 31, 2003.

A hypothetical, instantaneous and unfavorable 10% change in currency exchange rates on December 31, 2003 would have resulted in additional interest expense, including default interest, of approximately RR116 million per year, reflecting the increased costs in rubles of servicing our foreign currency denominated indebtedness held at December 31, 2003. A hypothetical, instantaneous and unfavorable 10% change in currency exchange rates at December 31, 2003 would have resulted in an estimated foreign exchange loss of approximately RR2,024 million on foreign currency denominated indebtedness held at December 31, 2003.

Interest Rate Risk

We are exposed to interest rate risk on our indebtedness that bears interest at floating rates and to a lesser extent, on our indebtedness that bears interest at fixed rates. At December 31, 2003, we had approximately RR26,009 million in loans outstanding, of which approximately RR12,138 million bore interest at fixed rates and approximately RR13,871 million bore interest at floating rates determined by reference to the London inter-bank offered rate (“LIBOR”) for U.S. dollar deposits.

We undertake debt obligations to support general corporate purposes including capital expenditures and working capital needs. Upward fluctuations in interest rates increase the cost of new debt and the interest cost of outstanding variable rate borrowings. Fluctuations in interest rates can also lead to significant fluctuations in the fair value of our debt obligations. A hypothetical, instantaneous and unfavorable change of 100 basis points in the interest rate applicable to floating-rate financial liabilities held at December 31, 2003 would have resulted in additional net interest expense of approximately RR139 million per year. The above sensitivity analysis is based on the assumption of an unfavorable 100 basis point movement of the interest rates applicable to each homogenous category of financial liabilities. A homogeneous category is defined according to the currency in which financial liabilities are denominated and assumes the same interest rate movement within each homogeneous category (e.g., U.S. dollars, rubles).

As it relates to our fixed rate financial liabilities a hypothetical, instantaneous 10% decrease in interest rates would have resulted in RR121 million increase in the fair value of long-term debt outstanding as of December 31, 2003. However, our sensitivity to decreases in interest rates and corresponding increases in the fair value of our debt portfolio would unfavorably affect our results and cash flows only to the extent that we elected to repurchase or otherwise retire all or a portion of our fixed-rate debt portfolio at prices above carrying value.

Liquidity Risk

Liquidity risk arises when the maturity of assets and liabilities do not match. The matching and/or controlled mismatching of the maturities of assets and liabilities is fundamental to the management of our banking subsidiaries. It is unusual for the maturities and interest rates of assets and liabilities of banks ever to be completely matched since business transacted is often of an uncertain term and of differing types. However, while an unmatched position potentially enhances profitability, it can also increase the risk of losses. The maturities of assets and liabilities and the ability to replace, at an acceptable cost, interest-bearing liabilities as they mature, are important factors in assessing the liquidity of our banking subsidiaries and their exposure to changes in interest and exchange rates. Liquidity risk is managed by our banking subsidiaries’ Asset/Liability Committees. See “Appendix A—Tatneft’s Banking Operations.”

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Derivatives

For the purpose of reducing interest rate risk and currency risk, our banking subsidiaries use a number of derivative instruments. These comprise interest rate swaps, forward rate agreements and forward foreign exchange contracts. The objective, when using any derivative instrument, is to ensure that the risk to reward profile of any transaction is optimized. The normal policy is to measure these instruments at their fair value, using the spot rate at the year end as the basis for the fair value measurement with resultant gains or losses being reported within gains less losses arising from dealing in foreign currency within the statement of operations. We do not believe that the derivatives entered into by our banking subsidiaries are material to us. See “Appendix A—Tatneft’s Banking Operations.”

Credit Risk

Our financial instruments that are potentially exposed to concentrations of credit risk consist primarily of accounts receivable, cash and cash equivalents, prepaid VAT as well as loans receivable and advances. A significant portion of our trade accounts receivable is due from domestic and export trading companies. We do not generally require collateral to limit the exposure to loss; however, sometimes letters of credit and prepayments are used. Although collection of these receivables could be influenced by economic factors affecting these entities, we believe there is no significant risk of loss to us beyond allowances already recorded. Our banking subsidiaries’ maximum exposure to credit risk excluding the value of collateral is generally reflected in the carrying amounts of financial assets on the balance sheet. The impact of possible netting of assets and liabilities to reduce potential credit exposure is not significant. Our banking subsidiaries structure the levels of credit risk they undertake by placing limits on the amount of risk accepted in relation to one borrower, or groups of borrowers, and to geographical and industry segments. Such risks are monitored on a revolving basis and subject to an annual or more frequent review. Limits on the level of credit risk by product, borrower and industry sector are reviewed regularly. Exposure to credit risk is also managed, in part, by obtaining collateral and corporate and personal guarantees. Overall we do not believe that credit risk is material to us. See Note 10 to our consolidated financial statements and “Appendix A—Tatneft’s Banking Operations.”

We deposit available cash primarily with financial institutions in Russia. Deposit insurance of deposits of legal entities is not offered to financial institutions operating in Russia. To manage this credit risk, we allocate available cash across a variety of Russian banks and Russian affiliates of international banks. Management periodically reviews the creditworthiness of the banks in which it deposits cash.

VAT recoverable, representing amounts payable or paid to suppliers, is recoverable from the tax authorities via offset against VAT payable to the tax authorities on our revenue or direct cash receipts from the tax authorities. Management periodically reviews the recoverability of the balance of prepaid VAT and believes it is fully recoverable within one year.

Credit risk for off-balance sheet financial instruments is defined as the possibility of sustaining a loss as a result of another party to a financial instrument failing to perform in accordance with the terms of the contract. Our banking subsidiaries use the same credit policies in making conditional obligations as they do for on-balance sheet financial instruments through established credit approvals, risk control limits and monitoring procedures. We do not believe that off-balance sheet instruments are material to us.

Commodity price risk

Substantially all of our crude oil and refined products are sold on the spot market or under short-term contracts at market sensitive prices. Market prices for export sales of crude oil and refined products are subject to volatile trading patterns in the commodity futures market. Average selling prices can differ from quoted market prices due to the effects of uneven volume distributions during the period, quality differentials, different delivery terms compared to quoted benchmarks, different conditions in local markets and other factors. Domestic prices generally follow the trend of world market prices but are volatile due to the nature of the Russian market. We do not use any derivative instruments to hedge our production in order to decrease our price risk exposure. However, since we do not engage in futures and forward contracts, we do not believe that our value at risk is material.

Equity price risk

As disclosed in Note 7 to our consolidated financial statements, as of December 31, 2003 we had cost method equity investments in certain entities, totaling RR1,692 million at December 31, 2003. These investments are exposed to market risk of fluctuations in equity prices.

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These investments are shares of Russian companies that are not publicly traded and, accordingly, their market values are not available. Currently, it is not practicable for us to estimate the fair values of these investments because we have not yet obtained or developed the valuation models necessary to make the estimates, and the cost of obtaining an independent valuation is believed by the management to be excessive considering the relative insignificance of the investments. Therefore, these investments are omitted from quantitative risk information disclosure presented herein.

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ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

This Item is not applicable.

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PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES, AND DELINQUENCIES

None.

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

None.

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ITEM 15. CONTROLS AND PROCEDURES

•

Tatneft funds were transferred to certain companies unrelated to us outside Russia: (a) in the case of certain loans, at relatively low interest rates, to reciprocate for the making of loans by such companies to us in earlier years; and (b) otherwise, to accumulate funds subsequently used for the purchase of approximately 23,465,175 of our shares at market prices, the total value of which was approximately RR1,088.90 million (approximately U.S.$38.88 million at the official ruble/U.S. dollar exchange rate of RR28.01 to U.S.$1.00 reported by the Central Bank on May 19, 2005), based on the price of RR46.41 per ordinary share quoted as the middle market price for ordinary shares of Tatneft on the MICEX on May 19, 2005, for a possible employee share incentive program, which the relevant employees of Tatneft wished to keep confidential until the details had been worked out, and which therefore was not disclosed to our independent auditors until the auditors started to make inquiries regarding the nature and business purposes of the transactions;

•

Subordinates implemented these transactions on orders from above without understanding, or querying, their true business purpose, and without being able to explain the business purpose accurately to our independent auditors; and

•

Inadequate, or inaccurate, documentation for the transactions resulted, among other things, in our independent auditors not being able to understand their true business purposes.

Based on the documentation, information and evidence obtained by it, Kennedys 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 Exchange Act. As discussed under “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,” Ernst & Young have also noted material weaknesses in our control environment. The General Director and Deputy General Director for Economics have thus concluded that our disclosure controls and procedures, as of December 31, 2003 and December 31, 2004, were not effective to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required.

We have taken and are taking certain measures aimed at improving our control environment and to prevent the recurrence of transactions whose nature and business purposes are not apparent. These include, inter alia: implementation of more stringent procedures with respect to origination, documentation and authorization of transactions; development of procedures to require the approval of certain transactions by our Board of Directors even when such approval is not required under Russian law; strengthening of our financial management and reporting functions by creating a new department responsible for the preparation of our financial statements under U.S. GAAP and hiring additional qualified staff to join this department; and appointment of an experienced senior executive to become our Chief Financial Officer whose responsibilities will include management of and oversight over the preparation of our U.S. GAAP financial statements. Our Board of Directors also approved and are in the process of implementing certain remedial actions with respect to our officers involved in the transactions investigated by Kennedys.

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ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

Our Board has determined that Maria Leonidovna Voskresenskaya qualifies as an “audit committee financial expert” within the meaning of Item 16A of Form 20-F.

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ITEM 16B. CODE OF ETHICS

We have adopted the Code of Corporate Culture satisfying the requirements of a code of ethics, as defined in Item 16B of Form 20-F under the Exchange Act. Our Code of Corporate Culture applies to all of our employees. Our Code of Corporate Culture is both filed as Exhibit 11.1 to this Form 20-F and posted on our website (www.tatneft.ru). If we amend the provisions of our Code of Corporate Culture that apply to our General Director, Deputy General Director for Economics, chief accounting officer and persons performing similar functions, or if we grant any waiver of such provisions, we will disclose such amendment or waiver on our website within five business days of the adoption of such amendment or waiver.

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ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit and Non-Audit Fees

The following table sets forth the fees (excluding VAT) billed to us by our independent auditor PricewaterhouseCoopers during the fiscal year ended December 31, 2002:


		Year ended December 31, 2002
		(in RR millions)
Audit fees		30.4
Audit-related fees		—
Tax fees		—
Other fees		—

Total fees		30.4

The following table sets forth the fees (excluding VAT) billed to us by our independent auditor Ernst & Young during the fiscal years ended December 31, 2003:


		Year ended December 31, 2003
		(in RR millions)
Audit fees		60.2
Audit-related fees		—
Tax fees		0.2
Other fees		—

Total fees		60.4

The following table sets forth the fees (excluding VAT) billed to us by our independent auditor Ernst & Young during the fiscal year ended December 31, 2004:


		Year ended December 31, 2004
		(in RR millions)
Audit fees		15.3
Audit-related fees		—
Tax fees		—
Other fees		—

Total fees		15.4

Audit fees in the above tables are the aggregate fees billed by PricewaterhouseCoopers and Ernst & Young in connection with the audit of our annual financial statements (including statutory) and review of our interim financial statements.

Tax fees comprised advice on the preparation of 2003 annual Dutch tax return of for one of our subsidiaries, IF Solid-Europe B.V.

There were no other fees billed in the above periods by PricewaterhouseCoopers and Ernst & Young, each serving in their respective capacities as the principal accountant related to the performance of the audit of our annual financial statements and review of our interim financial statements.

All fees are based upon fees billed for services rendered during the relevant fiscal year, irrespective of whether the auditors, each serving in their respective capacities as the principal accountant, actually billed us until after year-end.

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Pre-approval Policies and Procedures

Upon proposal by the Board of Directors, the Annual General Meeting of Shareholders appoints the auditor to audit the financial statements of a financial year. The Audit Committee recommends the auditor to the Board of Directors, negotiates the terms of engagement of the auditor and evaluates its performance. All fees relating to audit and other services provided by the independent auditor must be approved on a case-by-case basis by the Audit Committee.

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PART III

ITEM 17. FINANCIAL STATEMENTS

Not applicable.

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ITEM 18. FINANCIAL STATEMENTS

Reference is made to pages F-1 through F-55.

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ITEM 19. EXHIBITS

(a) The following financial statements are filed as part of this Form 20-F:


Index to Consolidated Financial Statements		F-1
Report of Ernst & Young (CIS) Limited, Independent Accountants		F-2
Report of ZAO PricewaterhouseCoopers Audit, Independent Accountants		F-3
Consolidated Balance Sheets as of December 31, 2003 and 2002		F-4
Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2003, 2002 and 2001		F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001		F-7
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2003, 2002 and 2001		F-9
Notes to Consolidated Financial Statements		F-10

(b) Index to Exhibits

Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed certain agreements as exhibits to this annual report on Form 20-F. These agreements may contain representations and warranties by the parties. These representations and warranties have been made solely for the benefit of the other party or parties to such agreement and (i) may be intended not as statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements if those statements turn out to be inaccurate, (ii) may have been qualified by disclosures that were made to such other party or parties and that either have been reflected in our filings or are not required to be disclosed in those filings, (iii) may apply materiality standards different from what may be viewed as material to investors and (iv) were made only as of the date of such agreements or such other date(s) as may be specified in such agreements and are subject to more recent developments. Accordingly, these representations and warranties may not describe our actual state of affairs at the date hereof.


1.1		Translation of the Amended and Restated Charter of OAO Tatneft, as adopted on June 27, 2004.

****1.2		Provisions on the Board of Directors of OAO Tatneft, dated June 28, 2002, together with an English translation thereof.

****1.3		Provisions on the General Director of OAO Tatneft, dated June 28, 2002, together with an English translation thereof.

****1.4		Provisions on the Executive Board of OAO Tatneft, dated June 28, 2002, together with an English translation thereof.

****1.5		Provisions on the Revision Committee of OAO Tatneft, dated June 28, 2002, together with an English translation thereof.

1.6		Provisions on the Audit Committee of OAO Tatneft.

1.7		Provisions on the Remuneration Committee of OAO Tatneft.

*2.1		Form of Deposit Agreement between OAO Tatneft and The Bank of New York, as Depositary, and holders from time to time of American Depositary Shares thereunder (including as an exhibit the form of American Depositary Receipt).

**2.2		Form of Amended and Restated Deposit Agreement between OAO Tatneft and The Bank of New York, as Depositary, and holders from time to time of American Depositary Shares thereunder (including as an exhibit the form of American Depositary Receipt).

***4.1		Agreement on Joint Activities for Shared Investment No. 180 of September 17, 1999 between Tatneft and Nizhnekamsk Oil Refinery.

***4.2		Agreement on Joint Activities in Construction No. 01-37/15 of December 1, 1999.

8.1		List of Significant Subsidiaries of OAO Tatneft.

11.1		Code of Corporate Culture

12.1		Section 302 Certification by the General Director.

12.2		Section 302 Certification by the Deputy General Director for Economics.

†13.1		Section 906 Certification

‡15.1		Report of Reserve Consultants, Miller & Lents, Ltd., dated May 28, 2004.

††15.2		Report of Reserve Consultants, Miller & Lents, Ltd., dated June 14, 2005.

15.3		Consent of Miller & Lents, Ltd.

*	Filed as an exhibit to our Registration Statement on Form F-6 (Reg. No. 333-8488), filed with the SEC on March 19, 1998.

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**		Filed as an exhibit to our amendment to Registration Statement of Form F-6 (Reg. No. 333-8488), filed with the Securities and Exchange Commission on April 30, 1998.

***		Filed as an exhibit to our annual report on Form 20-F for the year ended December 31, 2000, filed with the Securities and Exchange Commission on July 2, 2001.

****		Filed as an exhibit to our annual report on Form 20-F for the year ended December 31, 2001, filed with the Securities and Exchange Commission on July 1, 2002.

†	Furnished, not filed.

‡	Incorporated by reference from our report on Form 6-K furnished to the SEC on July 23, 2004.

††	Incorporated by reference from our report on Form 6-K furnished to the SEC on June 29, 2005.

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

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SIGNATURES

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


OAO TATNEFT
Registrant

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

Date: July 14, 2005

147

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Ernst & Young (CIS) Limited, Independent Accountants		F-2

Reports of ZAO PricewaterhouseCoopers Audit, Independent Accountants		F-3

Consolidated Financial Statements:

Consolidated Balance Sheets as of December 31, 2003 and 2002		F-4

Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2003, 2002 and 2001		F-5

Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001		F-7

Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2003, 2002 and 2001		F-9

Notes to Consolidated Financial Statements		F-10

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of OJSC Tatneft

We have audited the accompanying consolidated balance sheet of OJSC Tatneft and its subsidiaries (jointly referred to as the “Company”) as of December 31, 2003 and the related consolidated statements of operations and comprehensive income, shareholders’ equity, and cash flows for the year ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of OJSC Tatneft and its subsidiaries at December 31, 2003 and the consolidated results of their operations and their cash flows for the year ended December 31, 2003 in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 3 and 11 to the consolidated financial statements, in 2003 the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003.

LOGO

Moscow, Russia

July 2, 2005

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of OAO Tatneft

In our opinion, the accompanying consolidated balance sheet as of December 31, 2002 and the related consolidated statements of operations and comprehensive income, of cash flows and of shareholders’ equity for each of the two years in the period ended December 31, 2002, expressed in constant Russian Roubles of December 31, 2002 purchasing power, present fairly, in all material respects, the financial position, results of operations and cash flows of OAO Tatneft and its subsidiaries (the “Group”) at December 31, 2002 and the for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 4, Restatement of Previously Issued Financial Statements, the Company has restated previously issued financial statements for each of the two years in the period ended December 31, 2002, expressed in constant Russian Roubles of December 31, 2002 purchasing power.

LOGO

June 9, 2003, except for the restatement

described in Note 4 as to which the date

is July 2, 2005.

F-3

TATNEFT

Consolidated Balance Sheets

(in millions of Russian Roubles)


	Notes	At December 31, 2003		At December 31, 2002
				(restated)
Assets
Cash and cash equivalents	5	8,450		7,070
Restricted cash	5	300		40
Accounts receivable, net	6	13,297		13,657
Due from related parties	19	6,631		4,105
Short-term investments	7	3,223		3,477
Current portion of loans receivable and advances, net	10	14,042		9,652
Inventories, net	8	10,051		9,962
Prepaid expenses and other current assets	9	17,506		16,940

Total current assets		73,500		64,903
Restricted cash	5	1,742		1,756
Long-term loans receivable and advances, net	10	6,746		2,978
Long-term investments	7	3,721		4,203
Property, plant and equipment, net	11	177,008		152,448

Total assets		262,717		226,288

Liabilities and shareholders’ equity
Short-term debt and current portion of long-term debt	12	13,213		16,618
Notes payable	13	6,948		3,482
Banking customer deposits	13	16,665		11,408
Trade accounts payable		2,948		6,370
Due to related parties	19	1,034		762
Other accounts payable and accrued liabilities	14	5,427		5,571
Current deferred tax liability	15	196		170
Capital lease obligations to related parties	11,19	643		—
Taxes payable		7,159		3,759

Total current liabilities		54,233		48,140
Long-term debt, net of current portion	12	12,796		14,622
Notes payable	13	1,485		866
Banking customer deposits	13	1,337		1,152
Asset retirement obligations, net of current portion	11	16,955		—
Deferred tax liability	15	21,271		21,287
Capital lease obligations to related parties, net of current portion	11,19	359		—

Total liabilities		108,436		86,067

Minority interest		5,101		5,069

Shareholders’ equity
Preferred shares (authorized and issued at December 31, 2003 and 2002 – 147,508,500 shares; nominal value at December 31, 2003 and 2002 - RR1.00)	16	148		148
Common shares (authorized and issued at December 31, 2003 and 2002 - 2,178,690,700 shares; nominal value at December 31, 2003 and 2002 - RR1.00)	16	2,179		2,179
Additional paid-in capital	16	89,516		88,863
Accumulated other comprehensive income		189		176
Retained earnings		62,291		47,776
Less: Common shares held in treasury, at cost (191,430,258 shares and 200,288,083 shares at December 31, 2003 and 2002, respectively)		(5,143	)	(3,990	)

Total shareholders’ equity		149,180		135,152

Total liabilities and shareholders’ equity		262,717		226,288

The accompanying notes are an integral part of these consolidated financial statements.

F-4

TATNEFT

Consolidated Statements of Operations and Comprehensive Income

(in millions of Russian Roubles)


	Notes	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
				(restated)		(restated)
Sales and other operating revenues	18	155,818		146,328		156,861

Costs and other deductions
Operating		31,799		36,389		31,297
Purchased oil and refined products		28,997		28,372		34,104
Exploration		812		463		839
Transportation		7,635		5,683		5,183
Selling, general and administrative		15,499		16,031		17,282
Bad debt charges and credits, net		(262	)	(261	)	1,027
Depreciation, depletion and amortization	18	8,850		7,541		6,139
Loss on disposals of property, plant and equipment and impairment of investments	10,11	2,325		851		2,502
Taxes other than income taxes	15	43,378		31,988		33,373
Maintenance of social infrastructure	11	279		199		491
Transfer of social assets	11	2,162		1,293		593

Total costs and other deductions		141,474		128,549		132,830

Other income (expenses)
Earnings from equity investments	7	101		148		501
Foreign exchange loss		(225	)	(1,042	)	(851	)
Monetary gain	2	—		871		1,764
Interest income		303		804		1,517
Interest expense		(1,827	)	(2,855	)	(2,875	)
Other income, net		1,961		3,599		511

Total other income		313		1,525		567

Income before income taxes, minority interest and cumulative effect of change in accounting principle		14,657		19,304		24,598

Income taxes
Current		(6,070	)	(4,743	)	(7,072	)
Deferred benefit / (expense)		1,488		(620	)	8,316

Total income tax (expense) / benefit	15	(4,582	)	(5,363	)	1,244

Income before minority interest and cumulative effect of change in accounting principle		10,075		13,941		25,842
Minority interest benefit / (expense)		63		(471	)	(1,698	)

Income before cumulative effect of change in accounting principle		10,138		13,470		24,144

Cumulative effect of change in accounting principle, net of RR 1,498 million tax	11	4,742		—		—

Net income		14,880		13,470		24,144

Foreign currency translation adjustments		3		(20	)	163
Unrealized holding gains on available-for-sale securities, net of tax		43		33		2,329
Less: transfer of realized gains included in net income, net of tax		(33	)	(2,981	)	(622	)

Comprehensive income		14,893		10,502		26,014

F-5

TATNEFT

Consolidated Statements of Operations and Comprehensive Income

(in millions of Russian Roubles, except per share information)


	Notes	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
			(restated)	(restated)
Basic net income per share before cumulative effect of changes in accounting principle (RR)	16
Common		4.70	6.24	10.94
Preferred		5.59	7.12	11.05
Cumulative effect of changes in accounting principle (RR)
Common		2.23	—	—
Preferred		2.23	—	—
Basic net income per share (RR)
Common		6.93	6.24	10.94
Preferred		7.82	7.12	11.05

Diluted net income per share before cumulative effect of changes in accounting principle (RR)	16
Common		4.68	6.23	10.92
Preferred		5.58	7.11	11.02
Cumulative effect of changes in accounting principle (RR)
Common		2.22	—	—
Preferred		2.22	—	—
Diluted net income per share (RR)
Common		6.90	6.23	10.92
Preferred		7.80	7.11	11.02

Weighted average common shares outstanding (millions of shares)	16
Basic		1,983	1,991	2,057
Diluted		1,988	1,993	2,062
Weighted average preferred shares outstanding (millions of shares)	16
Basic		148	148	148
Diluted		148	148	148

F-6

TATNEFT

Consolidated Statements of Cash Flows

(in millions of Russian Roubles)


	Notes	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
				(restated)		(restated)
Operating activities
Net income		14,880		13,470		24,144
Adjustments:
Cumulative effect of change in accounting principle		(4,742	)	—		—
Minority interest		(63	)	471		1,698
Depreciation, depletion and amortization	18	8,850		7,541		6,139
Net barter settlements	5	(1,126	)	(2,425	)	(4,227	)
Deferred income tax expense (benefit)		(1,488	)	620		(8,316	)
Disposals and impairments		2,325		851		2,502
Net realized (gain)/loss on available-for-sale securities		10		(3,408	)	(1,003	)
Effects of foreign exchange		(1,527	)	869		1,638
Monetary gain		—		(871	)	(1,764	)
Undistributed earnings of equity investments		(71	)	(121	)	(381	)
Transfer of social assets		2,162		1,293		593
Other		(1,014	)	(383	)	460
Changes in operational working capital, excluding cash:
Accounts receivable		(3,623	)	6,021		(1,497	)
Inventories		212		1,946		1,338
Prepaid expenses and other current assets		(996	)	(1,686	)	(4,010	)
Trading securities		(193	)	100		(1,867	)
Loans receivable		(8,143	)	(5,615	)	(6,406	)
Notes receivable		1,093		(4,425	)	(472	)
Trade accounts payable		(3,576	)	(2,662	)	1,052
Other accounts payable and accrued liabilities		10,079		664		7,418
Taxes payable		3,372		(2,097	)	(1,780	)

Net cash provided by operating activities		16,421		10,153		15,259

Investing activities
Additions to property, plant and equipment		(12,679	)	(13,100	)	(20,583	)
Proceeds from disposals of property, plant and equipment		1,147		109		142
Proceeds from disposal/ maturity of investments		1,943		6,272		2,805
Purchase of investments		(779	)	(1,681	)	(636	)
Change in restricted cash		(246	)	398		760

Net cash used for investing activities		(10,614	)	(8,002	)	(17,512	)

F-7

TATNEFT

Consolidated Statements of Cash Flows

(in millions of Russian Roubles)


	Notes	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
				(restated)		(restated)
Financing activities
Proceeds from issuance of debt		39,468		40,840		25,019
Repayment of debt		(42,788	)	(39,698	)	(19,215	)
Repayment of capital lease obligations		(1,221	)	—		—
Dividends paid		(354	)	(401	)	(690	)
Purchase of treasury shares		(5,425	)	(1,523	)	(2,119	)
Proceeds from sale of treasury shares		5,495		1,107		345
Proceeds from issuance of shares by subsidiaries		401		—		684

Net cash provided by (used in) financing activities		(4,424	)	325		4,024

Effect of foreign exchange on cash and cash equivalents		(3	)	10		(37	)
Effect of inflation accounting		—		(288	)	(393	)

Net change in cash and cash equivalents		1,380		2,198		1,341
Cash and cash equivalents at beginning of period		7,070		4,872		3,531

Cash and cash equivalents at end of period		8,450		7,070		4,872

F-8

TATNEFT

Consolidated Statements of Shareholders’ Equity

(in millions of Russian Roubles)


	2003				2002				2001
	Shares		Amount		Shares		Amount		Shares		Amount
							(restated)				(restated)
Preferred shares:
Balance at January 1 and December 31 (shares in thousands)	147,509		148		147,509		148		147,509		148

Common shares:
Balance at January 1 and December 31 (shares in thousands)	2,178,691		2,179		2,178,691		2,179		2,178,691		2,179

Treasury shares, at cost:
Balance at January 1	200,288		(3,990	)	176,133		(2,511	)	66,575		(787	)
Purchases	196,452		(5,995	)	195,659		(5,083	)	131,889		(2,119	)
Sales	(205,310	)	4,842		(171,504	)	3,604		(22,331	)	395

Balance at December 31 (shares in thousands)	191,430		(5,143	)	200,288		(3,990	)	176,133		(2,511	)

Additional paid-in capital
Balance at January 1			88,863				89,026				88,863
Stock-based compensation			—				—				163
Stock-options redeemed			—				(163	)			—
Treasury share transactions			653				—				—

Balance at December 31			89,516				88,863				89,026

Accumulated other comprehensive income
Balance at January 1			176				3,144				1,274
Foreign currency translation adjustments			3				(20	)			163
Unrealized holding gains on available-for-sale securities, net of tax			43				33				2,329
Transfer of realized gains included in net income, net of tax			(33	)			(2,981	)			(622	)

Balance at December 31			189				176				3,144

Retained earnings
Balance at January 1			51,002				36,098				12,104
The cumulative effect on prior years of prior year adjustments (see Note 4)			(3,226	)			(903	)			(697	)

Balance at January 1, as adjusted			47,776				35,195				11,407
Net income, as adjusted (see Note 4)			14,880				13,470				24,144
Dividends			(365	)			(387	)			(306	)
Treasury share transactions			—				(502	)			(50	)

Balance at December 31			62,291				47,776				35,195

Total shareholders’ equity at December 31			149,180				135,152				127,181

F-9

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 1: Organization

OAO Tatneft (the “Company”) and its subsidiaries (jointly referred to as “the Group”) are engaged in crude oil exploration, development and production principally in the Republic of Tatarstan (“Tatarstan”), an autonomous republic within the Russian Federation. The Group also engages in refining and marketing of crude oil and refined products and petrochemical and banking activities, as further described in Note 18. The Group’s banking activities comprise the operations of Zenit Bank and Devon Credit Bank.

The Company was incorporated as an open joint stock company effective January 1, 1994 (the “privatization date”) pursuant to the approval of the State Property Management Committee of the Republic of Tatarstan (the “Government”). All assets and liabilities previously managed by the production association Tatneft, Bugulminsky Mechanical Plant, Menzelinsky Exploratory Drilling Department and Bavlinsky Drilling Department were transferred to the Company at their book value at the privatization date in accordance with Decree No. 1403 on Privatization and Restructuring of Enterprises and Corporations into Joint-Stock Companies. Such transfers are considered transfers between entities under common control at the privatization date, and have been recorded at book value.

At December 31, 2003, the Government held 33% of the common shares of the Company. As further described in Note 16, the Government owns one “Golden Share” which carries the right to veto certain decisions taken at meetings of the shareholders and the Board of Directors. The Government of Tatarstan is able to exercise significant influence through its ownership interest in the Company, its legislative, taxation and regulatory powers, its representation on the Board of Directors and informal influence. The Government has used its influence in the past to facilitate 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 the Group), acquiring specified companies or taking actions to raise funds for the benefit of Tatarstan (see Notes 9, 10, 11, 15, 16, 19, 21 and 22).

The Government of Tatarstan controls a number of the Group’s suppliers, such as OAO Tatenergo, the supplier of electricity to the Group, and a number of the Group’s ultimate customers, such as OAO Nizhnekamskneftekhim (“Nizhnekamskneftekhim”), the principal petrochemical company in Tatarstan. Consequently, the Group may be subject to pressures to enter into transactions that we might not otherwise contemplate with suppliers and contractors controlled by the Government. Related party transactions are further disclosed in Note 19.

Note 2: Basis of Presentation

The Group maintains its accounting records and prepares its statutory financial statements principally in accordance with the Regulations on Accounting and Reporting of the Russian Federation (“RAR”). The accompanying financial statements have been prepared from these accounting records and adjusted as necessary to comply with accounting principles generally accepted in the United States of America (“US GAAP”). The principal differences between RAR and US GAAP relate to: (1) revenue recognition; (2) valuation and depreciation of property, plant and equipment; (3) foreign currency translation; (4) deferred income taxes; (5) valuation allowances for unrecoverable assets; (6) capital leases; (7) stock option transactions; and (8) consolidation and accounting for subsidiaries and equity investees.

Use of estimates in the preparation of financial statements. The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. While management uses its best estimates and judgments, actual results could differ from those estimates and assumption used. Among the estimates made by the management are: assets valuation allowances, depreciable lives, oil and gas reserves, dismantling costs and income taxes.

Foreign currency transactions and translation. The functional currency of the Group except for subsidiaries located outside of the Russian Federation is the Russian Rouble because the majority of its revenues, costs, property and equipment purchased, debt and trade liabilities are either priced, incurred, payable or otherwise measured in Russian Roubles. Accordingly, transactions and balances not already measured in Russian Roubles (primarily US Dollars) have been re-measured into Russian Roubles in accordance with the relevant provisions of US Statement of Financial Accounting Standards (“SFAS”) No. 52, “Foreign Currency Translation”.

Under SFAS No. 52, revenues, costs, capital and non-monetary assets and liabilities are translated at historical exchange rates prevailing on the transaction dates. Monetary assets and liabilities are translated at exchange rates prevailing on the balance sheet date. Exchange gains and losses arising from re-measurement of monetary assets and liabilities that are not denominated in Russian Roubles are credited or charged to operations.

F-10

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 2: Basis of Presentation (continued)

For operations of the subsidiaries located outside of the Russian Federation, that use primarily US Dollars as the functional currency, adjustments resulting from translating foreign functional currency assets and liabilities into Russian Roubles are recorded in a separate component of shareholders’ equity entitled accumulated other comprehensive income. Gains or losses resulting from transactions in other than the functional currency are reflected in net income.

Exchange rates, restrictions and controls. At present, the Russian Rouble is not a fully convertible currency outside of the Russian Federation and, further, the Company is required to sell up to 50% (25% from July 9, 2003) of its hard currency earnings for Russian Roubles. Within the Russian Federation, official exchange rates are determined daily by the Central Bank of Russia (“CBR”). Market rates may differ from the official rates but the differences are, generally, within narrow parameters monitored by the CBR. Accordingly, the translation of foreign currency denominated assets and liabilities into Russian Roubles does not indicate that the Group could realize or settle, in Russian Roubles, the reported values of these assets and liabilities. The official rate of exchange of the Russian Rouble (“RR”) to the US Dollar (“US $”) at December 31, 2003 and 2002 was RR 29.45 and RR 31.78 to US $1.00, respectively.

Inflation accounting. Prior to January 1, 2003 the adjustments and reclassifications made to statutory records for the purpose of US GAAP presentation included the restatement of balances and transactions for the changes in the general purchasing power of the RR in accordance with Accounting Principles Board Statement No. 3, “Financial Statements Restated for General Price-Level Changes” (“APB 3”).

Corresponding figures for the year ended December 31, 2002, were restated for the changes in the general purchasing power of the RR at December 31, 2002. The restatement was calculated using the conversion factors derived from the Russian Federation Consumer Price Index, a historical price index published by the Russian State Committee on Statistics (“Goskomstat” prior to October 1999 and “Russian Statistics Agency” since October 1999), and from indices obtained from other sources for years prior to 1992.

The main guidelines followed in restating the corresponding figures were:

•

All corresponding amounts were stated in terms of the measuring unit current at December 31, 2002;

•

Monetary assets and liabilities held at December 31, 2002 were not restated because they were already expressed in terms of the monetary unit current at December 31, 2002.

•

Non-monetary assets and liabilities (those balance sheet items that were not expressed in terms of the monetary unit current at December 31, 2002) and components of shareholders’ equity were restated from their historical cost by applying the change in the general price index from the date the non-monetary item originated to December 31, 2002;

•

All items in the statement of operations and cash flows were restated by applying the change in the general price index from the dates when the items were initially transacted to December 31, 2002.

•

Gains or losses that arose as a result of holding monetary assets and liabilities for the reporting year ended December 31, 2002 were included in the statement of operations as a monetary gain or loss.

On November 25, 2002, the International Practices Task Force of the American Institute of Certified Public Accountants concluded that the Russian Federation would no longer be considered highly inflationary effective January 1, 2003. Accordingly, no restatement was made in the consolidated financial statements of the Group for the years subsequent to January 1, 2003 and the amounts expressed in the measuring unit at December 31, 2002 are treated as the basis for the carrying amounts in these financial statements.

Barter transactions. Transactions settled by barter are included in the accompanying consolidated balance sheets and statements of operations on the same basis as cash transactions.

Barter transactions relate to sales of crude oil and refined products and are generally either in the form of direct settlement by crude oil and refined products to the final customer, or through a chain of non-cash transactions involving several companies. In such cases, both sales and purchases are recorded as a result of the barter transaction. Barter sales are recognized at the fair value as disclosed in Note 3 “Non-monetary transactions”.

Reclassifications. Certain reclassifications in the consolidated financial statements as of and for the years ended December 31, 2002 and 2001 have been made to conform with the current year’s presentation; such reclassifications have no effect on net income or shareholders’ equity.

F-11

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Amounts due to and from related parties were disclosed separately in the consolidated balance sheet. Certain restricted cash balances were reclassified from non-current assets to current assets. Certain prepaid expenses and other current assets were reclassified to long-term loans receivable and advances.

F-12

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 2: Basis of Presentation (continued)

Net banking interest income previously included within other income in the consolidated statement of operations and comprehensive income was reclassified to sales and other operating revenues. Bad debt charges and write-offs previously included within selling, general and administrative expenses were disclosed separately in the consolidated statement of operations and comprehensive income.

Principles of consolidation and long-term investments. The accompanying consolidated financial statements include the operations of all entities that the Group controls through direct or indirect ownership of the voting stock (generally more than 50 percent of the voting stock). Joint ventures and affiliates in which the Group has significant influence but not control (generally 20 percent to 50 percent of the voting stock) are accounted for using the equity method. Intercompany transactions and accounts are eliminated on consolidation. Other long-term investments are carried at cost and adjusted for estimated impairment. The Group reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques, including discounted cash flows.

Note 3: Summary of Significant Accounting Policies

Cash equivalents. Cash equivalents are highly liquid short-term investments that are readily convertible to known amounts of cash and have original maturities within three months from their date of purchase. They are carried at cost plus accrued interest, which approximate fair value.

Inventories. Inventories of crude oil, refined oil products, materials and supplies, and finished goods are valued at the lower of cost or net realizable value. For inventories valued at cost, the Group uses the weighted-average-cost method. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/non-recurring costs or research and development costs.

Short-term investments. Short-term investments consist of debt and equity securities classified as available-for-sale or trading. Securities are classified as available-for-sale when, in management’s judgment, they may be sold in response to or in anticipation of changes in market conditions. Available-for-sale securities are carried at estimated fair values on the consolidated balance sheet. Unrealized gains and losses on available-for-sale securities are reported net as increases or decreases to accumulated other comprehensive income. The specific identification method is used to determine realized gains and losses on available-for-sale securities.

Securities classified as trading are bought and held principally for the purpose of selling them in the near term. Trading securities are carried at fair value on the consolidated balance sheet. In determining fair value, trading securities are valued at the last trade price if quoted on an exchange or, if traded over-the-counter, at the last bid price. Unrealized and realized gains and losses on trading securities are included in other income of the consolidated statements of operations and comprehensive income.

If the decline in fair value of an investment below accounting basis is other-than-temporary, the carrying value of the securities is reduced and a loss in the amount of any such decline is recorded. No such reductions have been required during the past three years.

Sale and repurchase agreements and lending of securities. Sale and repurchase agreements are treated as secured financing transactions. Securities sold under sale and repurchase agreements are included in trading securities. The corresponding liability is presented within short-term and long-term debt as well as banking customer deposits. Securities purchased under agreements to resell (“reverse repurchase”) are recorded as loans receivable and advances. The difference between the sale and repurchase prices is treated as interest and recognized over the life of the repurchase agreements using the effective interest method.

Securities lent to counterparts are retained in the consolidated financial statements. Securities borrowed are not recognized in the consolidated financial statements, unless these are sold to third parties, in which case the purchase and sale are recorded within gains less losses arising from trading securities in the consolidated statement of operations and comprehensive income. The obligation to return them is recorded at fair value as a trading liability.

Trade accounts receivable and allowances for bad debts. Trade accounts receivable are stated at their principal amounts outstanding net of allowances for bad debts. Specific allowances are recorded against trade receivables whose recovery or collection has been identified as doubtful. An estimated allowance is recorded against trade receivables which are inherent in the portfolio but which at the date of preparing the financial statements have not been specifically identified, as doubtful. Estimates of allowances require the exercise of judgment and the use of assumptions.

F-13

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 3: Summary of Significant Accounting Policies (continued)

Loans receivable and allowances for impairment. Loans originated by the Group by providing money directly to the borrower or to a sub-participation agent at draw down are carried at amortized cost less allowance for loan impairment. Loans are recognized when cash is advanced to borrowers.

The allowance is equal to the difference between the carrying amount and estimated recoverable amount, calculated as the present value of expected cash flows, including amounts recoverable from guarantees and collateral, discounted based on the loan’s interest rate at inception.

The allowance for loan impairment also covers losses where there is objective evidence that probable losses are present in components of the loan portfolio at the balance sheet date. These have been estimated based upon historical patterns of losses in each component and the credit ratings assigned to the borrowers, and reflect the current economic environment in which the borrowers operate.

When a loan is uncollectible, it is written off against the related allowance for loan impairment. Such loans are written off after the necessary legal procedures have been completed and the amount of the loss has been determined. Recoveries of amounts previously written off are credited to the related allowance for impairment.

If the required allowance for loan impairment subsequently decreases due to an event occurring after the write-down, the release of the allowance is credited to other income line in the consolidated statements of operations and comprehensive income.

Oil and gas exploration and development cost. Oil and gas exploration and production activities are accounted for using the successful efforts method whereby costs of acquiring unproved and proved oil and gas property as well as costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. Exploration expenses, including geological and geophysical expenses and the costs of carrying and retaining undeveloped properties, are expensed as incurred. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. If proved reserves are not found exploratory well costs are expensed. In an area requiring a major capital expenditure before production can begin, an exploratory well remains capitalized if sufficient reserves are discovered to justify its completion as a production well, and additional exploration drilling is underway or firmly planned. The Group does not capitalize the costs of other exploratory wells for more than one year unless proved reserves are found.

Impairment of long-lived assets. Long-lived assets, including proved oil and gas properties at a field level, are assessed for possible impairment in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. Properties, plant and equipment used in operations are assessed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted pretax future cash flows, the assets are impaired and an impairment loss is recorded through additional amortization or depreciation provisions in the periods in which the determination of impairment is made. The amount of impairment is determined based on the estimated fair value of the assets determined by discounting anticipated future net cash flows or based on quoted market prices in active markets, if available. In the case of oil and gas fields, the net present value of future cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including risk-adjusted probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. The price and cost outlook assumptions used in impairment reviews differ from the assumptions used in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities. In that disclosure, SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” requires the use of prices and costs at the balance sheet date, with no projection of future changes in those assumptions.

Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets - generally on a field-by-field basis for exploration and production assets, at an entire complex level for refining assets or at a site level for service stations. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell. Acquisition costs of unproved oil and gas properties are evaluated periodically and any impairment assessed is charged to expense.

F-14

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 3: Summary of Significant Accounting Policies (continued)

Depreciation, depletion and amortization. The Group calculates depletion expense for acquisition costs of proved properties using the unit of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production equipment and wells is calculated using the unit of production method for each field over proved developed oil and gas reserves (see Note 11). Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives which are as follows:


		Years
Buildings and constructions		25 - 33

Machinery and equipment		5 - 15

Maintenance and repair. Maintenance and repairs, which are not significant improvements, are expensed when incurred.

Capitalized interest. Interest from external borrowings is capitalized on major projects with an expected total cost exceeding RR 100 million each and an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. Since there were no projects which qualified for interest capitalization, no interest was capitalized during the year ended December 31, 2003, 2002 or 2001.

Change in accounting principle of recognition and measurement of asset retirement obligations. Effective January 1, 2003, the Group adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). This new statement applies to legal obligations associated with the retirement and removal of tangible long-lived assets. Following the requirements of SFAS 143 the Group recognizes a liability for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement obligations are incurred (typically when the asset is installed at the production location). The Group capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets in accordance with SFAS 143. Legal obligations, if any, to retire refining and marketing, distribution and banking assets are generally not recognized because of the indeterminable settlement date of these obligations.

Through December 31, 2002, in accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”) the estimated undiscounted costs of dismantling and removing major oil and gas production and transportation facilities, including necessary site restoration, were accrued using the unit-of-production method. The change in accounting of asset retirement obligations was accounted for as a change in accounting principle. See Note 11 for additional information.

Property dispositions. When complete units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the consolidated statements of operations and comprehensive income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

Capital leases. Capital leases, which transfer to the Group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between the interest charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liabilities. Interest charges are charged directly to the consolidated statements of operation and comprehensive income.

Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term unless the leased assets are capitalized by virtue of the terms of the lease agreement granting the Group with ownership rights over the leased assets by the end of the lease term or containing a bargain purchase option. In this case, capitalized assets are depreciated over the estimated useful life of the asset regardless of the lease term.

Leases where the lessor retains substantially all the risks and benefits of ownership of the assets are classified as operating leases. Operating lease payments are recognized as an expense in the consolidated statements of operation and comprehensive income on a straight-line basis over the lease term.

Environmental expenditures. Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated.

F-15

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 3: Summary of Significant Accounting Policies (continued)

Pension and post-employment benefits. The Group’s mandatory contributions to the governmental and discretionary non-governmental defined contribution pension schemes are expensed when incurred. The amount of contributions, frequency of payments and other conditions of non-governmental pension plans are regulated by the “Statement of National non-governmental pension fund of OAO “Tatneft” and the contracts concluded between the Company or its subsidiaries and non-profit organization “National non-governmental pension fund”. In accordance with these contracts the Group is committed to make certain contributions which are determined solely at the discretion of the Group’s or its subsidiary’s management but not less than the minimum annual payment regulated by current Russian legislation. In accordance with the provisions of collective agreements concluded on an annual basis between the Company or its subsidiaries and their employees the Group is obligated to pay certain post-employment benefits the amounts of which are either fixed or depend on the governmental pension amount or at the full discretion of the Group’s management. In 2003, 2002 and 2001 the contributions to non-governmental pension plans and post-employment benefit payments were not material.

Revenue recognition. Revenues from the production and sale of crude oil, petroleum and chemical products and all other products are recognized when deliveries of products to final customers are made, title passes to the customer, collection is reasonably assured and sales price to final customers is fixed or determinable. Revenues include the sales portion of contracts involving purchases and sales necessary to reposition supply to address location or quality or grade requirements (e.g., when the Group repositions crude by entering into a contract with a counter party to sell crude in one location and purchase it in a different location) and sales related to purchase for resale activity.

Bank interest income and expense are recognized on an accrual basis calculated using the effective interest method. The recognition of contractual interest income is suspended when loans become overdue by more than ninety days or when management believes that interest is not collectible. When interest accruals are suspended, interest accrued in a prior year is charged against the allowance for loan impairment while interest accrued in the current year but unpaid is reversed and charged against interest income. Loans are returned to accrual status when, in management’s judgment, the borrower’s ability to make periodic interest and principal payments has improved and payments are made timely over an approximate six month period. Until the loan is returned to accrual status, payments by borrower are applied to loan principal. Bank interest is included on a net basis in sales and other operating revenues in the consolidated statement of operations and comprehensive income since management believes that the activities of the banks are one of the core activities of the Group.

Shipping and handling costs. Shipping and handling costs are included in Transportation expenses caption in the consolidated statements of operation and comprehensive income.

Non-monetary transactions. In accordance with Accounting Principles Board Statement No. 29, “The Accounting for Non-monetary Transactions” (“APB 29”) such transactions are recorded based on the fair values of the assets (or services) involved which is the same basis as that used in monetary transactions. Thus, the cost of a non-monetary asset acquired in exchange for another non-monetary asset is the fair value of the asset surrendered to obtain it, and a gain or loss is recognized on the exchange if the carrying amount of the asset surrendered differs from its fair value. The fair value of the asset received should be used to measure the cost if it is more clearly evident than the fair value of the asset surrendered.

F-16

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 3: Summary of Significant Accounting Policies (continued)

Stock-based compensation. At December 31, 2003, the Group has one stock-based employee compensation plan, which is described more fully in Note 17. The Group accounts for this plan under the recognition and measurement principles of Accounting Principles Board Statement No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and related Interpretations. The following table illustrates the effect on net income and income per share as if the Group applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123), to stock-based employee compensation. The Group records compensation expense for non-vested common stock awards ratably over the vesting period.


	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
Income before cumulative effect of change in accounting principle, as reported	10,138		13,470		24,144
Add: Stock-based employee compensation expense (APB 25) included in reported net income, net of taxes	179		120		163
Deduct: Total stock-based employee compensation expense (SFAS 123) determined under fair value based method, net of taxes	(269	)	(177	)	(190	)

Common share dividends	(217	)	(239	)	(271	)

Preferred share dividends	(148	)	(148	)	(35	)

Pro forma net income available to common and preferred shareholders, net of dividends	9,683		13,026		23,811

Net income per common share:
Basic – as reported	4.70		6.24		10.94
Basic – pro forma	4.65		6.21		10.93

Diluted – as reported	4.68		6.23		10.92
Diluted – pro forma	4.64		6.20		10.91

Net income per preferred share:
Basic – as reported	5.59		7.12		11.05
Basic – pro forma	5.54		7.09		11.04

Diluted – as reported	5.58		7.11		11.02
Diluted – pro forma	5.53		7.08		11.01

Income taxes. Deferred income tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in the periods in which these temporary differences are expected to reverse. Valuation allowances are provided for deferred income tax assets when management believes that it is unlikely that the assets will be realized.

Minority interest. Minority interest represents the minority shareholders’ proportionate share of the equity of the Group’s subsidiaries. This has been calculated based upon the minority interest ownership percentage of these subsidiaries. The Company does not own any preference shares in subsidiaries.

Net income per share. Basic income per share is calculated using the two class method of computing income per share. Under this method, net income is reduced by the amount of dividends declared in the current period for each class of shares, and the remaining income is allocated to common and preferred shares to the extent that each class may share in income if all income for the period had been distributed. Diluted income per share reflects the potential dilution arising from options granted to senior managers and the Directors of the Group.

F-17

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 3: Summary of Significant Accounting Policies (continued)

Treasury shares. Common shares of the Company owned by the Group at the balance sheet date are designated as treasury shares and are recorded at cost using the weighted-average method. Gains on the resale of treasury shares are credited to additional paid in capital whereas losses are charged to additional paid in capital to the extent that previous net gains from resale are included therein or otherwise to retained earnings.

Accounting for guarantees. The Group recognizes a liability for the fair value of the obligation it assumes under the guarantee in accordance with the provisions of Financial Accounting Standard Board (“FASB”) issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). The adoption of the provisions of FIN 45 did not have a material impact on the Group’s results of operations, financial position or cash flow.

Recent accounting pronouncements:

The Group has completed its analysis of compliance with the provisions of FIN 46 as revised by FIN 46R in respect of the existence of VIEs created after January 31, 2003 or VIEs created before that date but which had significant modifications in terms of contracts or nature of transactions with the Group subsequent to that date or VIEs which are SPEs. This analysis did not identify any significant impact of FIN 46 as revised by FIN 46R on the Group’s consolidated financial statements as of and for the year ended December 31, 2003. The Group is still assessing the impact that FIN 46 as revised by FIN 46R may have on its consolidated financial statements for the periods commencing January 1, 2004.

Postretirement Benefits. In December 2003, the FASB revised and reissued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88, and 106,” which revises and requires additional disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by previous Financial Accounting Board Standards. The Group adopted the provisions of this standard. Certain provisions of this Standard regarding disclosure of information about foreign plans and disclosure of estimated future benefit payments are not required until 2004. The adoption of the provisions applicable to 2003 did not have a material impact on the Group’s results of operations, financial position or cash flow, nor will the adoption of the additional provisions in 2004 have a material impact on the Group’s results of operations, financial position or cash flow.

Amendment to SFAS No. 133 on Derivative Instruments and Hedging Activities. In April 2003, the FASB issued SFAS No. 149, “Amendment to Statement 133 on Derivative Instruments and Hedging Activities” (“SFAS 149”). This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”. It is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. All provisions of the statement should be applied prospectively, except as stated further. Provisions related to SFAS 133 Implementation Issues that have been effective for fiscal quarters beginning prior to June 15, 2003, should continue to be applied in accordance with their respective dates. Rules related to forward purchases or sales of when-issued securities or other similar securities, should be also applied to existing contracts. The adoption of the provisions of SFAS 149 did not have a material impact on the Group’s results of operations, financial position or cash flow.

F-18

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 3: Summary of Significant Accounting Policies (continued)

Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“SFAS 150”). This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. On November 7, 2003, the FASB issued FASB Staff Position No. FAS 150-3, which deferred certain provisions of SFAS 150. The adoption of the provisions of SFAS 150 and deferral of certain provisions did not have a material impact on the Group’s results of operations, financial position or cash flow.

SFAS 123R provides two alternatives for adoption: (1) a “modified prospective” method in which compensation cost is recognized for all awards granted subsequent to the effective date of this statement as well as for the unvested portion of awards outstanding as of the effective date and (2) a “modified retrospective” method which follows the approach in the “modified prospective” method, but also permits entities to restate prior periods to reflect compensation cost calculated under SFAS 123 for pro forma amounts disclosure. The Group plans to adopt SFAS 123R using the modified prospective method. The adoption of SFAS 123R is expected to have an impact on our results of operations. On March 30, 2005, the SEC released Staff Accounting Bulletin No. 107, “Share-Based Payment,” (“SAB 107”), which expresses the views of the SEC staff regarding the application of SFAS 123R. The impact of adopting SFAS 123R and SAB 107 cannot be accurately estimated at this time, as it will depend on the amount of share based awards granted in future periods. However, had we adopted SFAS 123R and SAB 107 in a prior period, the impact would approximate the impact of SFAS 123 as described in the disclosure of pro forma net income and income per share in this Note to the consolidated financial statements.

Inventory costs. In November 2004, the FASB issued SFAS No. 151, “Inventory Costs an amendment of ARB No. 43, Chapter 4” (“SFAS 151”). SFAS 151 requires that items, such as idle facility expense, excessive spoilage, double freight, and re-handling costs, be recognized as a current-period charge. The provisions of SFAS 151 are effective for financial statements for fiscal years beginning after June 15, 2005. The Group is analyzing the provisions of this statement to determine the effects, if any, on the Group’s results of operations, financial position or cash flow.

Nonmonetary exchanges of similar assets. In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets” (“SFAS 153”). SFAS 153 addresses the measurement of exchanges of nonmonetary assets. The guidance in APB 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29, however, included certain exceptions to that principle. SFAS 153 amends APB 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of SFAS 153 are effective for financial statements for fiscal years beginning after June 15, 2005. The adoption of the provisions of SFAS 153 is not expected to have a material impact on the Group’s results of operations, financial position or cash flow.

F-19

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 3: Summary of Significant Accounting Policies (continued)

Accounting changes and error corrections. In May 2005, the FASB issued SFAS No. 154, “Accounting changes and error corrections” (“SFAS 154”). SFAS 154 replaces APB Opinion No. 20, “Accounting Changes” (“APB 20”), and SFAS No. 3, “Reporting Changes in Interim Financial Statements”, and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior period’s financial statements of all changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change, if a pronouncement which requires the change in accounting principle does not include specific transition provisions. SFAS 154 carries forward without change the guidance contained in APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of the provisions of SFAS 154 is not expected to have a material impact on the Group’s results of operations, financial position or cash flow.

Income per share calculation. In March 2004, the Emergency Issue Task Force (“EITF”) reached a consensus on Issue 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128, Earnings per Share”, that explained how to determine whether a security should be considered a “participating security” and how income should be allocated to a participating security when using the two-class method for computing basic income per share. The adoption of this standard which is effective for financial statements for fiscal periods beginning after March 31, 2004 is not expected to have a material impact on the Group’s income per share calculation.

Discontinued operations. In November 2004, the EITF issued EITF No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (“EITF 03-13”). EITF 03-13 assists in the development of a model for evaluating (a) which cash flows are to be considered in determining whether cash flows have been or will be eliminated and (b) what types of continuing involvement constitute significant continuing involvement when determining whether the disposal or sale of a component of a business is to be accounted for as discontinued operations. The Group is analyzing the provisions of EITF 03-13 to determine the effects, if any, on the Group’s results of operations, financial position or cash flow.

Conditional asset retirement obligations. In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). This interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event if the liability’s fair value can be reasonably estimated. The Group is analyzing the provisions of this interpretation to determine the effects, if any, on the Group’s results of operations, financial position or cash flow.

Suspended well costs. In April 2005, the FASB issued FASB Staff Position FAS No. 19-1, “Accounting for suspended well costs” (“FSP FAS 19-1”). FSP FAS 19-1 amends SFAS 19 and applies to companies that follow the successful efforts method of accounting. FSP FAS 19-1 concludes that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and an entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. In addition FSP 19-1 requires certain disclosures to provide financial statement users information about management’s evaluation of capitalized exploratory well costs. The provisions of FSP FAS 19-1 are effective for the first reporting period beginning after April 4, 2005 and should be applied prospectively to existing and newly capitalized exploratory well costs. The adoption of the provisions of FSP FAS 19-1 is not expected to have a material impact on the Group’s results of operations, financial position or cash flow.

Implicit variable interest. In March 2005, the FASB issued FASB Staff Position FIN 46(R)-5, “Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities” (“FSP FIN 46(R)-5”). FSP FIN 46(R)-5 is applicable to both nonpublic and public reporting enterprises and addresses an issue that commonly arises in leasing arrangements among related parties, and in other types of arrangements involving related parties and unrelated parties. The Group is analyzing the provisions of this interpretation to determine the effects, if any, on the Group’s results of operations, financial position or cash flow.

F-20

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 4: Restatement of previously issued financial statements

The consolidated financial statements of the Group for the years ended December 31, 2002 and 2001 have been restated to reflect the effects of changes in calculation of deferred income taxes and depreciation, depletion and amortization as described below.

Deferred taxes

For the year ended December 31, 2002, as permitted by the legislation of the Russian Federation, the Group recorded a statutory revaluation of its property, plant and equipment tax base amounting to RR 11,893 million, and inappropriately recorded a decrease in its deferred tax liability of RR 2,854 million calculated on the entire amount of this statutory revaluation. Only a portion of this statutory revaluation, however, will be deductible in the future for tax purposes and as such the tax base of property, plant and equipment as of December 31, 2002 was overstated resulting in an understatement of deferred tax liabilities as of December 31, 2002 amounting to RR 2,158 million. Deferred tax liabilities as of December 31, 2002 and 2001 and the 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 in the amounts of RR 111 million and RR 50 million, respectively.

Depreciation, depletion and amortization calculation

The Group had been depleting oil and gas properties on a unit-of-production basis over total proved reserves, and not proved developed reserves, as required by US GAAP. The Group originally believed that the difference between the two classes of reserves was not material 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, the Group no longer believes that assumption to be appropriate. The cumulative effect of this adjustment to retain earnings as of December 31, 2000 was a decrease of RR 697 million.

The accompanying consolidated financial statements for the year ended December 31, 2002 and 2001 have been restated to adjust deferred income taxes for the non-deductible amount of the statutory revaluation and to adjust depreciation, depletion and amortization for the impact of using total proved reserves, instead of proved developed reserves as follows:


	As reported		As restated
Year ended December 31, 2001
Deferred income tax benefit	8,205		8,316
Depreciation, depletion and amortization adjustments	(5,822	)	(6,139	)
Net income	24,350		24,144

Income per share:
Basic
Common	11.04		10.94
Preferred	11.14		11.05
Diluted
Common	11.01		10.92
Preferred	11.11		11.02

Year ended December 31, 2002
Deferred income tax benefit / (expenses)	1,488		(620	)
Depreciation, depletion and amortization adjustments	(7,325	)	(7,541	)
Net income	15,793		13,470

Income per share:
Basic
Common	7.32		6.24
Preferred	8.20		7.12
Diluted
Common	7.32		6.23
Preferred	8.20		7.11

F-21

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 5: Cash and Cash Equivalents, Restricted Cash, and Cash Flow Information

The consolidated statements of cash flows provide information about changes in cash and cash equivalents. At December 31, 2003, 2002 and 2001, cash and cash equivalents of the Group include US Dollar denominated amounts of RR 2,888 million (US $98 million), RR 4,190 million (US $132 million) and RR 3,295 million (US $109 million), respectively. Short-term restricted cash is cash held in escrow accounts in the amount of RR 300 million and RR 40 million at December 31, 2003 and 2002, respectively. Long-term restricted cash primarily consists of mandatory deposits with the Central Bank of Russia and deposits with lending institutions. Deposits with lending institutions are held over the life of the respective loans. These deposits will unlikely become available to the Group in 2004.

Net cash provided by operating activities reflects payments of interest and income taxes as follows:


	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
Interest paid	1,796	2,908	3,168
Income taxes paid	5,932	5,360	8,419

Non-cash sales. Non-cash sales for the years ended December 31, 2003, 2002 and 2001 totalled RR 4,188 million, RR 6,004 million and RR 8,560 million, respectively, which approximates 3%, 4% and 5% of sales and other operating revenues, respectively.

Non-cash sales, settled by purchases of property, plant and equipment, have been excluded from net cash provided by operating activities and from net cash used for investing activities in the accompanying statements of cash flows.

The following table shows the distribution of non-cash transactions included in the consolidated statements of operations and comprehensive income and as additions to property, plant and equipment:


	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
Taxes other than income taxes	69	60	914
Additions to property plant and equipment	1,126	2,425	4,227
Operating and other expenditures	2,993	3,519	3,419

Total non-cash transactions	4,188	6,004	8,560

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

In 2003 the Group capitalized leased assets in the amount of RR 2,223 million and paid only RR 1,221 million of this amount. Also the effect of adoption of SFAS 143 included an initial increase of property, plant and equipment of RR 9,912 million.

F-22

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 6: Accounts Receivable

Accounts receivable are as follows:


	At December 31, 2003			At December 31, 2002
	Total accounts receivable	Accounts receivable from related parties	Accounts receivable, net	Total accounts receivable	Accounts receivable from related parties	Accounts receivable, net
Trade – domestic	7,203	437	6,766	8,820	199	8,621
Trade – export (US $395 million and US $197 million at December 31, 2003 and 2002, respectively)	11,640	5,109	6,531	6,217	1,181	5,036

Total accounts receivable, net	18,843	5,546	13,297	15,037	1,380	13,657

Trade receivables are presented net of an allowance for doubtful accounts of RR 905 million and RR 1,073 million at December 31, 2003 and 2002, respectively.

Note 7: Short and Long-Term Investments

Short-term investments are classified as available-for-sale and trading securities as follows:


	At December 31, 2003	At December 31, 2002
Available-for-sale securities	379	944
Trading securities	2,844	2,533

Total short-term investments	3,223	3,477

Trading securities are held in the Group’s banks and insurance company, which frequently buy and sell securities with the objective of earning profits on short-term differences in price. All other short-term investments in debt and equity securities are classified as available-for-sale and are as follows:


	Cost	Gross unrealized gains	Fair value (carrying value)
Equity securities	336	43	379

Total available-for-sale securities at December 31, 2003	336	43	379

Corporate debt securities	50	—	50
Equity securities	861	33	894

Total available-for-sale securities at December 31, 2002	911	33	944

F-23

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 7: Short and Long-Term Investments (continued)

Short-term investments classified as trading securities are as follows:


	At December 31, 2003	At December 31, 2002
Bonds and other Russian government securities	647	1,110
Corporate debt securities	1,722	1,259
Equity securities	475	164

Total trading securities	2,844	2,533

Bonds and other Russian government securities at December 31, 2003 and 2002, include mainly Federal Currency Bonds (OVVZ) with a carrying value of RR 51 million and RR 712 million and Russian Federation Eurobonds with a carrying value of RR 334 million and RR 76 million, respectively.

At December 31, 2003, total debt securities with fair values totaling RR 692 million mature during 2004, and with fair values totaling RR 1,677 million mature between 2005 and 2030.

Net gains on trading and realized available-for-sale securities for the year ended December 31, 2003, 2002 and 2001 were RR 235 million, RR 3,583 million, RR 1,736 million, respectively, reported in the consolidated statements of operations and comprehensive income.

Long-term investments are as follows:


	Ownership percentage at December 31, 2003	Net book value at		Income for the year ended December 31,
	Ownership percentage at December 31, 2003	December 31, 2003	December 31, 2002	2003	2002		2001
Investments in and income from equity affiliates and joint ventures:
ZAO Tatex	50	1,788	1,775	42	229		362
OAO Finansovaya Lizingovaya Kompania (“FLK”)	—	—	512	3	(82	)	7
Other	20-50	241	246	56	1		132

Total investments in and income from equity affiliates and joint ventures		2,029	2,533	101	148		501

Long-term investments, at cost:
ZAO Ukrtatnafta	9	504	504
OAO AK Bars Bank	18	609	609
Other	0-20	579	557

Total long-term investments, at cost		1,692	1,670

Total long-term investments		3,721	4,203

At December 31, 2003, consolidated retained earnings included RR 1,755 million (2002 – RR 2,118 million) related to the undistributed earnings of 50% or less owned companies that are accounted for using the equity method. Summary financial information pertaining to these investments has not been presented as the investments are not material to the Group’s consolidated financial statements.

Long-term investments not designated as available-for-sale or trading securities are recorded at cost because they are not traded on the market and it is not practicable to determine their fair value.

At the beginning of 2003 the Group acquired 9% of the share capital of OAO Finansovaya Lizingovaya Kompania, a leasing company equity affiliated to the Group, for RR 263 million in addition to 12% previously owned by the Group. In June 2003 the entire interest in this company (21%) was sold for RR 676 million, resulting in a loss of RR 99 million.

In October 2003, the Group sold its 75% interest in the share capital of OAO Tatincom-T, a regional cellular telecommunications subsidiary, for RR 549 million, resulting in a gain of RR 681 million. Total assets of OAO Tatincom-T as of September 30, 2003 and December 31, 2002 were RR 442 million and RR 336 million, respectively, and total liabilities – RR 574 million and RR 515 million, respectively. Net results from disposal of OAO Finansovaya Lizingovaya Kompania and OAO Tatincom-T were included within other income of the consolidated statements of operations and comprehensive income for 2003.

F-24

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 8: Inventories

Inventories are as follows:


	At December 31, 2003	At December 31, 2002
Materials and supplies	5,282	6,407
Crude oil	1,485	1,861
Refined oil products	2,641	799
Petrochemical supplies and finished goods	643	895

Total inventories	10,051	9,962

Note 9: Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets are as follows:


	At December 31, 2003	At December 31, 2002
VAT recoverable	6,391	5,908
Notes receivable	3,761	3,312
Receivable due from Tax Ministry	2,251	—
Advances	878	2,065
Prepaid export duties	694	1,011
Prepaid transportation expenses	504	252
Interest receivable	229	170
Prepaid profit tax	160	1,561
Other	2,638	2,661

Total prepaid expenses and other current assets	17,506	16,940

Receivable due from Ministry of Tax. On December 6, 2002, the Group filed a lawsuit in the Arbitration court of Tatarstan against the Tax Ministry of Tatarstan claiming a refund for mineral use tax (royalty tax) paid in the amount of RR 2,251 million. On January 17, 2003, the Arbitration court ruled in favor of the Group and permitted the Group to apply this amount against future tax payments. The Tax Ministry of Tatarstan appealed this decision to the Federal Arbitration court of Povolzhsky district which, on April 6, 2003, upheld the decision of the Arbitration court of Tatarstan. Accordingly, the Group recognized the gain of RR 2,251 million as well as a receivable due from the Tax Ministry in the same amount which will be legally offset against the Group’s tax liabilities in 2004 (see Notes 1 and 22).

Note 10: Loans Receivable and Advances


	At December 31, 2003		At December 31, 2002
Banking loans and advances to customers, net	20,146		11,352
Long-term notes receivable	479		227
Other Russian Rouble denominated loans receivable	808		1,893

Total loans receivable and advances	21,433		13,472

Less: current portion of loans receivable and advances	(14,042	)	(9,652	)
Less: due from related parties	(645	)	(842	)

Total long-term loans receivable and advances	6,746		2,978

F-25

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 10: Loans Receivable and Advances (continued)

Banking loans and advances to customers. Banking loans and advances to customers are presented net of allowance for losses of RR 741 million and RR 1,011 million as at December 31, 2003 and 2002, respectively.

At December 31, 2003 and 2002 the weighted average fixed interest rate on banking loans and advances was 14% and 18% on balances denominated in Russian Roubles and 12% and 14% on balances denominated in foreign currency, respectively. The fair values of banking loans and advances approximate the carrying values as interest rates typically adjust on a three months basis and the majority is short-term in nature.

Economic sector risk concentration within the loan portfolio is as follows:


	At December 31, 2003			At December 31, 2002
	Amount	%		Amount	%
Commercial	14,443	72	%	8,834	78	%
Financial	2,988	15	%	650	6	%
Agricultural	1,454	7	%	662	6	%
Individuals	229	1	%	124	1	%
Other	1,032	5	%	1,082	9	%

	20,146			11,352

Loans receivable and advances to customers reported as of December 31, 2003 in the amounts of RR 2,625 million, RR 1,057 million and RR 2,585 mature in 2005, 2006 and after 2007, respectively.

Aggregate non-performing loans on which contractual interest is not being recognized amounted to RR 394 million and RR 884 million as of December 31, 2003 and 2002, respectively. Unrecognized contractual interest related to such loans totaled RR 301 million and RR 228 million as of December 31, 2003 and 2002, respectively.

Included in current loans is RR 838 million and nil as of December 31, 2003 and 2002, respectively, which represents the amounts receivable from customers in connection with security repurchase transactions.

Promissory notes issued by “Nedoimka”. In 2003 the Group purchased promissory notes issued by entity “Nedoimka”, a unitary company controlled by Tatarstan government, in order to finance social expenditures planned under Tatarstan’s budget at the request of Tatarstan government. Management of the Group believes that these notes are not recoverable and, accordingly, all notes in the amount of RR 1,197 million were written off and reported as a loss on disposals of property, plant and equipment and impairment of investments in the consolidated statements of operations and comprehensive income (see also Note 1).

F-26

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 11: Property, Plant and Equipment

Effective January 1, 2003, the Group adopted SFAS 143. This new accounting standard applies to legal obligations associated with the retirement of tangible long-lived assets. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the liability is accreted for the passage of time and the related asset is depreciated over its estimated useful life. The adoption of SFAS 143 affected the accounting and reporting of the assets, liabilities and expenses related to these obligations.

Prior to the adoption of SFAS 143 costs related to asset retirement obligation were accrued ratably over the productive lives of the assets in accordance with SFAS 19. Under SFAS 19, asset retirement costs were accrued on a unit-of-production basis as the oil is produced and recorded as an increase of accumulated depreciation. The SFAS 19 method matched the accruals with the revenues generated from production and results in most of the costs being accrued early in field life, when production is at the highest level. Because SFAS 143 requires accretion of the liability as a result of the passage of time using an interest method of allocation, the majority of the costs will be accrued toward the end of field life, when production is at the lowest level. Accordingly, the cumulative income adjustment described below resulted from reversing the higher amount of depreciation accumulated under SFAS 19 in order to report a liability to the lower present value amount resulting from transition to SFAS 143. This amount being reversed in transition, which was previously charged to operating earnings under SFAS 19, will again be charged to those earnings under SFAS 143 in future years.

The Group has numerous asset removal obligations that it is required to perform under law or contract once an asset is permanently taken out of service. The Group’s field exploration, development, and production activities include assets related to: well bores and related equipment and operating sites, gathering and oil processing systems, oil storage facilities and pipelines to main transportation trunks. Generally, the Group’s licenses and other operating permits require certain actions to be taken by the Group in the abandonment of these operations. Such actions include well abandonment activities, equipment dismantlement and other reclamation activities. The Group’s estimates of future abandonment costs consider present regulatory or license requirements and are based upon management’s experience of the costs of and requirement for 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 general Group resources at the time of removal. Legal or contractual obligations, if any, to retire or otherwise abandon petrochemical, refining and marketing, distribution and banking assets are generally not recognized because of limited history of such activities in these operating areas, absence of clear and definitive legal requirements and indeterminable lives of these assets. Inasmuch as the regulatory and legal environment in Russia continues to evolve, there could be future changes to the requirements and costs associated with abandoning long-lived assets.

SFAS 143 calls for measurements of asset retirement obligations to include, as a component of expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties and unforeseeable circumstances inherent in the obligations, sometimes referred to as a market-risk premium. To date, the oil and gas industry has no examples of credit-worthy third parties who are willing to assume this type of risk, for a determinable price, on major oil and gas production facilities and pipelines. Therefore, because determining such a market-risk premium would be an arbitrary process, it has been excluded from the SFAS 143 estimates. As of January 1, 2003, the Group recorded a cumulative-effect adjustment resulting in an after-tax increase to net income of RR 4,742 million in relation to this change in accounting principle. The effect of adoption also included an initial increase of property, plant and equipment of RR 9,912 million, reduction of accumulated depreciation of RR 11,807 million and recognition of asset retirement obligation in the amount of RR 15,479 million as well as deferred tax liabilities of RR 1,498 million.

F-27

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 11: Property, Plant and Equipment (continued)

The cumulative effect of the change on prior years resulted in a credit to income of RR 4,742 million (RR 2.23 per share), which is included in income for the year ended December 31, 2003. The pro forma effects of the application of SFAS 143 if the Statement had been adopted on January 1, 2001 (rather than January 1, 2003) are presented below:


	2002	2001
	(restated)	(restated)
Net income (historical)	13,470	24,144
Basic net income per common share (historical)	6.24	10.94

Net income (as if Statement 143 had been adopted January 1, 2001)	11,380	22,394
Basic net income per common share (as if Statement 143 had been adopted January 1, 2001)	5.26	10.15
Basic net income per preferred share (as if Statement 143 had been adopted January 1, 2001)	6.14	10.25
Diluted net income per common share (as if Statement 143 had been adopted January 1, 2001)	5.25	10.13
Diluted net income per preferred share (as if Statement 143 had been adopted January 1, 2001)	6.13	10.23

During 2003, the overall asset retirement obligation changed as follows:


Opening balance at January 1, 2003	15,479
Accretion of discount	1,548
New obligations	68
Spending on existing obligations	(3	)

Closing balance at December 31, 2003	17,092

Less: current portion of asset retirement obligations	(137	)

Closing long-term balance at December 31, 2003	16,955

The pro forma asset retirement obligations as if Statement 143 had been adopted on January 1, 2002 (rather than January 1, 2003) are as follows:


	2003	2002
Pro forma amounts of liability for asset retirement obligation at beginning of year	15,479	14,071
Pro forma amounts of liability for asset retirement obligation at end of year	17,092	15,479

F-28

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 11: Property, Plant and Equipment (continued)

Property, plant and equipment are as follows:


	Cost	Accumulated depreciation, depletion and amortization	Net book value
Oil and gas properties	256,731	124,312	132,419
Buildings and constructions	26,657	8,418	18,239
Machinery and equipment	43,226	30,126	13,100
Assets under construction	13,250	—	13,250

December 31, 2003	339,864	162,856	177,008

Oil and gas properties	235,223	129,168	106,055
Buildings and constructions	27,559	7,806	19,753
Machinery and equipment	38,872	27,415	11,457
Assets under construction	15,183	—	15,183

December 31, 2002 (restated)	316,837	164,389	152,448

As stated in Note 3, the Group calculates depreciation, depletion and amortization using the unit of production method over proved or proved developed oil and gas reserves depending on the nature of the costs involved. The proved or proved developed reserves used in the unit of production method assume the extension of our production license beyond their current expiration dates until the end of the economic lives of the fields as discussed below in further detail.

The Group’s oil and gas fields are located principally on the territory of Tatarstan. The Group obtains 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 these dates. Under Russian law, the Group is entitled to renew the 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. The Group has 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 the Group’s licenses that could prevent their extension and that, based on approved development plans and in accordance with the Subsoil Law, the Group’s licenses will be extended at the Group’s request. The Group’s right to extend licenses is, however, dependent on the Group continuing to comply with the terms of the licenses, and management has the ability and intent to do so. Management plan to request the extension of the licenses and are currently in the process of requesting extensions for the Group’s most significant fields, including Romashkinksoye. The Group’s current production plans are based on the assumption, which management considers to be reasonably certain, that the Group will be able to extend all existing licenses. These plans have been designed on the basis that the Group will be producing crude oil through the economic lives of the fields and not with a view to exploiting the Group’s reserves to maximum effect only through the license expiration dates.

Miller & Lents, the Group’s independent oil and gas consultants, have confirmed management’s view that it is “reasonably certain” that the Group will be allowed to produce oil from the Group’s reserves after the expiration of 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, management has included in proved reserves in the supplementary information on oil and gas exploration and production activities of the consolidated financial statements as of and for the year ended December 31, 2003 all reserves that otherwise meet the standards for being characterized as “proved” and that the Group estimates the Group can produce through the economic lives of Group’s 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. The Group believes that the extension of the licenses is a matter of course as fully described above. To assist the financial statement reader in understanding the proved oil reserves that will be produced during the existing license period and those that will be produced during the period of the expected license extension, the proved oil reserves have been presented separately for each of these two periods in the accompanying supplementary oil and gas information.

F-29

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 11: Property, Plant and Equipment (continued)

The Group’s cash flow from operations is dependent on the level of oil prices, which are historically volatile and are also significantly impacted by the proportion of production that the Group can sell on the export market. Historically, the Group has supplemented its cash flow from operations with additional borrowings and may continue to do so. Should oil prices decline for a prolonged period and should the Group not have access to additional capital, the Group would need to reduce its capital expenditures, which could limit its ability to maintain or increase production and in turn meet its debt service requirements and pay dividends.

Capital leases. The Group leases machinery and equipment. The following is an analysis of the leased property under capital leases:


	At December 31, 2003		At December 31, 2002
Machinery and equipment	2,223		—
Less: accumulated amortization	(318	)	—

	1,905		—

All capital lease transactions are conducted with related parties as further described in Note 19.

The following is a schedule by year of future lease payments under capital leases together with the present value of the future minimum lease payments as of December 31, 2003:


Year ended December 31:
2004	643
2005	345
2006	173
2007	5

Total future lease payments	1,166

Less interest	(164	)

Present value of future minimum lease payments	1,002

Less current portion	(643	)

Long-term portion of capital lease obligations	359

F-30

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 11: Property, Plant and Equipment (continued)

Social assets. During years ended December 31, 2003, 2002 and 2001 the Group transferred social assets with a net book value of RR 2,162 million (including medical equipment to Medical Center with a net book value of RR 1,917 million), RR 1,293 million and RR 593 million, respectively, to local authorities for no consideration. At December 31, 2003, and December 31, 2002, the Group held social assets with a net book value of RR 4,870 million and RR 5,833 million all of which were constructed after the privatization date. The remaining social assets comprise mainly dormitories, hotels, gyms and others. The Group has no intention to transfer these assets to the local authorities. The Group incurred social infrastructure expenses of RR 279 million, RR 199 million and RR 491 million for the years ended December 31, 2003, 2002, and 2001, respectively, for maintenance that mainly relates to housing, schools and cultural buildings (see also Note 1).

Impairment of property, plant and equipment. In 2001, based on a reassessment of its future development plans and cash flows of its telecommunications subsidiary, the Group wrote off its investment resulting in a charge to operations of RR 394 million, which is included in loss on disposals and impairment in the consolidated statements of operations and comprehensive income for the year ended December 31, 2001.

Note 12: Debt


	At December 31, 2003		At December 31, 2002
Short-term debt

Foreign currency denominated debt
Current portion of long-term debt	4,768		6,112
Other foreign currency denominated debt	4,335		5,565
Rouble denominated debt	4,110		4,941

Total short-term debt	13,213		16,618

Long-term debt

Foreign currency denominated debt
BNP Paribas	8,734		11,743
Credit Suisse First Boston	4,220		5,721
Bank Zenit Eurobonds	2,915		—
Commerzbank AG	—		2,207
Other foreign currency denominated debt	33		491
Rouble denominated debt	1,662		572

Total long-term debt	17,564		20,734
Less: current portion	(4,768	)	(6,112	)

Total long-term debt, net current portion	12,796		14,622

Foreign currency debts are primarily denominated in US Dollars.

Short-term foreign currency denominated debt. As of December 31, 2003 other short-term foreign currency denominated debt includes loans from Winter Bank, Credit Suisse Zurich and interbank loans.

In July 2001 the Group entered into a RR 1,042 million (US $30 million) loan agreement with Winter Bank. The loan bears an interest rate of 6 month LIBOR plus 4.5% per annum. The loan must be repaid in full every six months and may be renewed immediately for an additional six months during the three year term of the commitment. The loan matures in November 2004. The amount of loan outstanding as of December 31, 2003 was RR 884 million.

In December 2003, the Group entered into a RR 1,034 million (US $35 million) one month revolving overdraft facility with Credit Suisse Zurich. The monthly revolving loan bears interest at 2.85% per annum and is collateralized by crude oil sales. The amount of loan outstanding as of December 31, 2003 was RR 725 million (US $25 million).

F-31

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 12: Debt (continued)

In November 2003 the Group entered into a RR 3 million (US $0.1 million) loan agreement with Alesworth Ltd. The loan bears interest at 16% per annum and matures in November 2004. The amount of loan outstanding as of December 31, 2003 was RR 3 million.

Interbank loans from foreign banks of RR 2,723 million and RR 2,522 million as at December 31, 2003 and 2002 had effective average interest rates of 6% and 7% per annum, respectively.

Short-term Russian Rouble denominated debt. Russian Rouble denominated short-term debt primarily comprises of loans with Russian banks. Short-term Rouble denominated loans of RR 4,110 million and RR 4,941 million bear contractual interest rates from 10% to 20% and 10% to 25% per annum for the periods ended December 31, 2003 and 2002, respectively. The loans are collateralized by the assets of the Group.

The carrying amount of short-term debt approximate fair value. Weighted average interest rate on short-term debts were 7% and 8% as of December 31, 2003 and 2002, respectively.

Long-term foreign currency denominated debt. In November 2001, the Group entered into a loan agreement with BNP Paribas for RR 3,014 million (US $100 million). The loan bears interest at LIBOR plus 3.5% per annum, is collateralized by crude oil export contracts of 50 thousand tons per month and matures in February 2004. The amount of loan outstanding as of December 31, 2003 was RR 614 million. In October 2002, the Group entered into another loan agreement with BNP Paribas for US $300 million. The amount outstanding under this loan as of December 31, 2003 was RR 8,120 million. The loan proceeds are payable in two tranches. First tranche in the amount US $125 million bears interest of LIBOR plus 4.25% per annum. Second tranche in the amount US $175 million bears interest of LIBOR plus 3.75%, per annum. The loan is collateralized by crude oil export contracts of 120 thousand tons per month, and matures in October 2007. The loan agreements require compliance with certain financial covenants including, but not limited to, minimum levels of consolidated tangible net worth, and maximum debt and interest coverage ratios.

In March 2002 the Group entered into a US $200 million loan agreement with Credit Suisse First Boston. The amount of loan outstanding as of December 31, 2003 was RR 4,220 million (US $143 million). The loan bears interest at LIBOR plus 3.78% per annum, is collateralized by crude oil export contracts of 80 thousand tons per month and matures in March 2007.

In 2003, 2002 and 2001 the Group was in compliance with all covenants required by the loan agreements except for the matter discussed below.

In April 2005, BNP Paribas notified the Group that it considered an event of default to have occurred under the terms of the loan agreement as a result of the Group failure to provide its audited consolidated US GAAP financial statements for the year ended December 31, 2003 and interim consolidated financial information for the six months ended June 30, 2004, and reserved its rights to accelerate amounts outstanding under the loan agreement and to enforce the related security. However, to date BNP Paribas has taken no action in this respect. The Group’s management believes that the delivery to BNP Paribas of the US GAAP audited consolidated financial statements for the year ended December 31, 2003 would cure this event of default.

Eurobonds. Eurobonds issued represent internationally traded long-term notes issued by the Group on June 12, 2003 with a face value of US $125 million and an interest rate of 9.25% payable semi-annually in arrears on June 12 and December 12 in each year commencing on December 31, 2003. The issue matures on June 12, 2006. Effective interest rate on the Eurobonds is 10%. The entire amount of Eurobonds outstanding at December 31, 2003 was RR 2,915 million. The Group is in compliance with the covenant of the financing agreement to maintain a specified capital adequacy ratio. The Group performs trading operations with its Eurobonds.

Other long-term foreign currency denominated debt. During the period ended December 31, 2002 the Group entered into a RR 278 million (US $9 million) loan agreement with West Deutsche Landesbank Vostok. The amount outstanding under this loan as of December 31, 2003 was RR 33 million. The loan bears interest at LIBOR plus 4.5% per annum and is collateralized by crude oil export contracts of approximately 7.5 thousand tons per month. The loan matures in February 2004.

F-32

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 12: Debt (continued)

Long-term Russian Rouble denominated debt. Long-term Russian Rouble denominated debt includes debentures and other loans bearing interest rates from 9% to 19%. Debentures outstanding as of December 31, 2003 amounted to RR 1,391 million. Other loans represent non-banking loans. The loans mature between 2004 to 2015.

The fair value of the Group’s long-term debt is similar to its book value. Fair value assessment is subject to considerable uncertainty.

Aggregate maturities of long-term debt outstanding at December 31, 2003 are as follows:


2004		4,768
2005		3,996
2006		7,119
2007		1,580
2008		—
2009		70
2010- and thereafter		31

Total long-term debt		17,564

Note 13: Notes payable and banking customer deposits

Notes payable are as follows:


	At December 31, 2003		At December 31, 2002
Bank notes payable	3,739		1,707
Other notes payable	4,694		2,641
Less: current notes payable	(6,948	)	(3,482	)

Notes payable long-term	1,485		866

Bank notes payable as of December 31, 2003 include short-term and long-term notes payable of Zenit Bank in the amounts of RR 3,528 million and RR 20 million, respectively, and short-term notes payable of Devon Credit Bank in the amount of RR 191 million. Bank notes payable for the year ended December 31, 2002 include short-term and long-term notes payable of Zenit Bank in the amounts of RR 1,640 million and RR 13 million, respectively, and short-term notes payable of Devon Credit Bank in the amount of RR 54 million. Bank notes payable bear contractual interest rates ranging from 8% to 10% both in 2003 and 2002.

Other notes payable as of December 31, 2003 include short-term and long-term trade promissory notes payable to third parties and bear contractual interest rates ranging from 1% to 7%, respectively.

Long-term notes payable in the amounts of RR 578 million, RR 657 million and RR 250 million outstanding at December 31, 2003 are payable in 2005, 2007 and after 2008, respectively.

Banking customer deposits are as follows:


	At December 31, 2003		At December 31, 2002
Term deposits	9,546		9,012
Demand deposits	8,556		4,133
Less: current banking customer deposits	(16,665	)	(11,408	)
Less: due to related parties	(100	)	(585	)

Banking customer deposits long-term	1,337		1,152

Contractual interest rates were 9% and 12% for Russian Rouble interest deposits, and 6% and 6% for foreign currency interest deposits for the periods ended December 31, 2003 and 2002, respectively.

F-33

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 13: Notes payable and banking customer deposits (continued)

The carrying values of notes payable and banking customer deposits approximate their fair values.

Long-term banking customer deposits in the amount of RR 1,337 million outstanding at December 31, 2003 is payable in 2005.

Note 14: Other Accounts Payable and Accrued Liabilities

Other accounts payable and accrued liabilities are as follows:


	At December 31, 2003	At December 31, 2002
Salaries and wages payable	2,105	1,606
Insurance provision	1,174	788
Interest payable	505	474
Current portion of asset retirement obligations (Note 11)	137	—
Deferred revenues	113	132
Advances received	33	552
Other accrued liabilities	1,360	2,019

Total other accounts payable and accrued liabilities	5,427	5,571

Note 15: Taxes

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for statutory tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2003 and 2002:


	At December 31, 2003		At December 31, 2002
Inventories	4		—
Accounts receivable	3		68
Long-term investments	18		32
Obligations under capital leases	241		—
Other accounts payable	66		39
Prepaid expenses and other current assets	119		—

Deferred tax assets	451		139

Property, plant and equipment	(21,177	)	(20,828	)
Inventories	—		(222	)
Long-term investments	(353	)	(491	)
Other liabilities	(388	)	(55	)

Deferred tax liabilities	(21,918	)	(21,596	)

Net deferred tax liability	(21,467	)	(21,457	)

At December 31, 2003 and 2002, deferred taxes were classified in the consolidated balance sheet as follows:


	At December 31, 2003		At December 31, 2002
Current deferred tax liability	(196	)	(170	)
Non-current deferred tax liability	(21,271	)	(21,287	)

Net deferred tax liability	(21,467	)	(21,457	)

F-34

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 15: Taxes (continued)

Presented below is a reconciliation between the provision for income taxes and taxes determined by applying the statutory tax rate to income before income taxes:


	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
			(restated)		(restated)
Income before income taxes and minority interest	14,657		19,304		24,598

Theoretical income tax expense at statutory rate (2003, 2002 – 24%, 2001 – 35%)	3,518		4,633		8,609

Increase (reduction) due to:
Inflationary effects	—		2,244		3,132
Non-deductible expenses	1,131		434		5,231
Profit exempt from taxable income resulting from qualified capital investments	—		—		(7,676	)
Non-taxable income	(275	)	(2,195	)	(1,629	)
Effect of reduction in income tax rate	—		—		(9,352	)
Other	208		247		441

Income tax expenses / (benefit)	4,582		5,363		(1,244	)

In August 2001, changes in the Russian Tax Code were enacted, which introduced a new income tax rate of 24%, effective January 1, 2002 compared to 35% in 2001. The net deferred tax benefit recognized as a result of remeasuring the deferred tax liability for tax rate changes on an enactment date basis, amounted to RR 9,352 for the year ended December 31, 2001.

In 2001 and prior years in accordance with Russian profit tax legislation, companies had the right to decrease their taxable profit by the amount of their cash used for investment in production property, plant and equipment less depreciation charge for the year but not to exceed 50% of the taxable profit. This investment incentive deduction was accounted for as a reduction of current taxable income in the year in which the deduction arose. On August 6, 2001 the profits tax law was amended to eliminate such deduction effective January 1, 2002.

No provision has been made for additional income taxes of RR 2,794 million on undistributed earnings of a foreign subsidiary. These earnings have been and will continue to be reinvested. These earnings could become subject to additional tax of approximately RR 419 million if they were remitted as dividends.

The Company is subject to a number of taxes other than income taxes, which are detailed as follows:


	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
Unified production tax	19,818	16,940	—
Export tariffs	18,174	11,890	16,697
Excise taxes	2,031	104	135
Property tax	1,389	1,336	1,087
Road users tax	—	1,079	1,285
Mineral restoration tax and royalty	—	—	11,773
Housing fund	—	—	1,432
Research and development tax	—	—	572
Penalties and interest	686	108	35
Other	1,280	531	357

Total taxes other than income taxes	43,378	31,988	33,373

F-35

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 15: Taxes (continued)

Effective January 1, 2002, the unified production tax was introduced and replaced the mineral restoration tax, royalty tax and excise tax on crude oil production. The base tax rate for the unified production tax is set at RR 340 per metric ton of crude oil produced, and is adjusted depending on the market price of Urals blend and the US $/ RR exchange rate. The tax becomes zero if Urals blend price falls to or below US $8.00 per barrel. The rate increased to RR 347 per ton of crude oil produced starting from January 1, 2004. In August 2004, the law was approved that increased the base tax rate for the unified production tax from RR 347 to RR 419 per ton of crude oil starting from January 1, 2005. From January 1, 2007, the unified production tax rate is set by law at 16.5% of the value of extracted crude oil which may be calculated by either reference to actual sale prices of natural resources or the deemed value of natural resources net of Value Added Tax (“VAT”) less export duties, transportation expenses and certain other distribution expenses.

In April 2005 the Group received a tax claim from the tax authorities, who conducted tax audit of the Group’s tax returns filed for 2001, 2002 and 2003, in the amount of RR 1,380 million. This amount includes both alleged non-payment and under-payment of taxes as well as fines and penalties. In May 2005, as full settlement of the tax claim, the Group paid RR 1,380 million (see also Note 1).

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

Note 16: Share Capital, Additional Capital and Other Comprehensive Income

Authorized share capital. At December 31, 2003 the authorized share capital consists of 2,178,690,700 voting common shares and 147,508,500 non-voting preferred shares; both classes of shares have a nominal value of RR 1.00 per share.

Golden share. OAO Svyazinvestneftekhim, a company wholly owned by the government of Tatarstan, as of December 31, 2003 holds approximately 30.44% of the Company’s capital stock. These shares were contributed to Svyazinvestneftekhim by the Ministry of Land and Property Relations of Tatarstan in 2003. 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 the Board of Directors and Revision Committee of the Company and to veto certain major decisions, including those relating to changes in the share capital, amendments to the Charter, liquidation or reorganization and “major” and “interested party” transactions as defined under Russian law. The Golden Share currently has an indefinite term. The Tatarstan government also controls a number of the Company’s suppliers and contractors, such as the electricity producer OAO Tatenergo and the petrochemicals company OAO Nizhnekamskneftekhim (see also Note 1).

Restricted common and preferred shares. Under the privatization laws of Tatarstan, initially certain common shares were issued subject to restrictions on transfer. These include shares sold to employees at a discount from nominal value and common shares sold to any individual for privatization vouchers. The preferred shares of the Company were also subject to restrictions on transfer. The preferred shares were originally allocated pursuant to applicable privatization laws to employees, former employees, and pensioners who had worked for the Group for a specified period of time. Afterwards by decree of the President of Tatarstan, all restrictions on common and preferred shares have been removed.

F-36

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 16: Share Capital, Additional Capital and Other Comprehensive Income (continued)

Rights attributable to preferred shares. Unless a different amount is approved at the annual shareholders meeting, preferred shares earn dividends equal to their nominal value. The amount of a dividend for a preferred share may not be less than the amount of a dividend for a common share.

Preferred shareholders may vote at meetings only on the following decisions:

-	the amendment of the dividends payable per preferred share;

-	the issuance of additional shares with rights greater than the current rights of preferred shareholders; and

-	the liquidation or reorganization of the Company.

The decisions listed above can be made only if approved by 75% of preferred shareholders.

Holders of preferred shares acquire the same voting rights as holders of common shares in the event that dividends are either not declared, or declared but not paid, on preferred shares. On liquidation, the shareholders are entitled to receive a distribution of net assets. Under Russian Joint Stock Companies Law and the Company’s charter in case of liquidation preferred shareholders have priority over ordinary shareholders to be paid declared but unpaid dividends on preferred shares and the liquidation value of preference shares, if any.

Amounts available for distribution to shareholders. Amounts available for distribution to shareholders are based on the Company’s non-consolidated statutory accounts prepared in accordance with RAR, which differ significantly from US GAAP (see Note 2). The statutory accounts are the basis for profit distribution and other appropriations. Russian legislation identifies the basis of distribution as the current period net profit calculated in accordance with RAR. However, this legislation and other statutory laws and regulations dealing with distribution rights are open to legal interpretation. For the years ended December 31, 2003 and 2002, the Company had a statutory current profit of RR 11,415 million and RR 6,309 million, respectively, as reported in the published statutory accounts of the Company.

At the annual general meeting of shareholders on June 27, 2003, final dividends of RR 0.10 per common share and RR 1.00 per preferred share, expressed in nominal Russian Roubles, were approved for 2002 for all shareholders. At December 31, 2003 the Company had paid RR 354 million of RR 365 million of its accrued dividends for 2002.

No interim dividends for 2003 were declared.

Net income per share. Under the two-class method of computing net income per share, net income is computed for common and preferred shares according to dividends declared and participation rights in undistributed earnings. Under this method, net income is reduced by the amount of dividends declared in the current period for each class of shares, and the remaining income is allocated to common and preferred shares to the extent that each class may share in income if all income for the period had been distributed.

Other comprehensive income. The balance of accumulated other comprehensive income as reported on the consolidated balance sheet consists of the following components:


	At December 31, 2003	At December 31, 2002
Net unrealized gain on available-for-sale securities	43	33
Net foreign currency translation adjustment gain	146	143

Accumulated other comprehensive income	189	176

F-37

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 16: Share Capital, Additional Capital and Other Comprehensive Income (continued)


	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
			(restated)		(restated)
Income before cumulative effect of change in accounting principle	10,138		13,470		24,144
Common share dividends	(217	)	(239	)	(271	)
Preferred share dividends	(148	)	(148	)	(35	)

Income available to common and preferred shareholders, net of dividends	9,773		13,083		23,838

Basic:
Weighted average number of shares outstanding (millions of shares):
Common	1,983		1,991		2,057
Preferred	148		148		148

Combined weighted average number of common and preferred shares outstanding	2,131		2,139		2,205

Basic net income per share before cumulative effect of changes in accounting principle (RR)
Common	4.70		6.24		10.94
Preferred	5.59		7.12		11.05

Cumulative effect of changes in accounting principle (RR)
Common	2.23		—		—
Preferred	2.23		—		—

Basic net income per share (RR)
Common	6.93		6.24		10.94
Preferred	7.82		7.12		11.05

Diluted:
Weighted average number of shares outstanding (millions of shares):

Common	1,988		1,993		2,062
Preferred	148		148		148

Combined weighted average number of common and preferred shares outstanding assuming dilution	2,136		2,141		2,210

Diluted net income per share before cumulative effect of changes in accounting principle (RR)
Common	4.68		6.23		10.92
Preferred	5.58		7.11		11.02

Cumulative effect of changes in accounting principle (RR)
Common	2.22		—		—
Preferred	2.22		—		—

Diluted net income per share (RR)
Common	6.90		6.23		10.92
Preferred	7.80		7.11		11.02

Minority interest. Minority interest is adjusted by dividends paid by the Group’s subsidiaries amounting to RR 112 million.

F-38

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 17: Stock-Based Compensation

On December 31, 2000 the Board of Director of the Company approved the Company stock compensation plan (the “Plan”) for senior management and directors of the Company. Under the provisions of the Plan the Company is entitled to issue options to its directors and senior management on an annual basis based on approval of the Board of Directors. The Board of Directors determines the number and exercise price of options as well as their expiration and vesting periods. In accordance with the Plan for all options issued, the Company reserves the right to repurchase outstanding options at the price determinable as the maximum weighted average daily market price for the preceding three years for trades on the Moscow Interbank Currency Exchange less the exercise price of option.

Option issuance must be registered with the Federal Financial Markets Service (formerly the Federal Commission for the Securities Markets of the Russian Federation) within one year after the approval of the Board of Directors. After registration, the number of options, their exercise prices and other conditions are communicated to the eligible person usually within three weeks after registration through the signing of a security sales contract between the Company or its subsidiary and such person. On the signing date, the option holder pays the non-refundable portion of the exercise price and the remaining amount is payable on the exercise date. The vesting period commences from the date of signing (the grant date).

All options issued in 2003, 2002 and 2001 vest in 270 days from the grant date and expire in 365 days after the grant date. Each option gives the option holders the right to purchase one share of the Company. Since the options are granted with an option repurchase feature and because the Company expects to repurchase the stock options after vesting, variable accounting for stock-based compensation under APB No. 25, “Accounting for Stock Issued to Employees”, and related Interpretations is applied. The compensation cost is determined prospectively as an excess of repurchase price over the exercise price of the option until full vesting is achieved. Total compensation cost is allocated rateably over the vesting period and corresponding liability recorded in other accounts payable and accrued liabilities.

In 2003 and 2002 the Company repurchased the options granted in 2002 and 2001 through cash settlement at the price of RR 27.00 and RR 16.50 per option, respectively. The amount of compensation expense in respect of the Plan recognized in the consolidated statements of operations for the years ended December 31, 2003, 2002 and 2001 was RR 179 million, RR 120 million and RR 163 million, respectively.

The following table summarizes the stock option activity for the periods presented:


	2003				2002				2001
	Shares		Price		Shares		Price		Shares	Price
Outstanding, beginning of year	9,300,000		RR	10.50	9,395,000		RR	0.10	—		—
Granted	9,300,000		RR	11.70	9,300,000		RR	10.50	9,395,000	RR	0.10
Repurchased	(9,300,000	)	RR	10.50	(9,395,000	)	RR	0.10	—		—

Outstanding, end of year	9,300,000		RR	11.70	9,300,000		RR	10.50	9,395,000	RR	0.10

Exercisable, end of year	—			—	—			—	—		—

The remaining lives of options outstanding at December 31, 2003, 2002 and 2001 were 0.50, 0.70 and 0.50 years, respectively.

F-39

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 17: Stock-Based Compensation (continued)

The fair value of the Group’s stock options is the estimated present value at the date of grant using the Black-Scholes option pricing model with the following assumptions:


	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
Average grant date fair value of options	36.42		17.85		16.40
Assumption used:
Risk-free interest rate	6.25		18.75		18.75
Dividend yield	1	%	1	%	1	%
Volatility factor	36	%	38	%	53	%
Expected life (years)	1		1		1

The Black-Scholes option pricing model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, this option pricing model requires the input of highly subjective assumptions, including the expected stock price volatility.

Note 18: Segment Information

The Group’s business activities are conducted predominantly through four business segments: exploration and production, refining and marketing, petrochemicals, and banking. The segments were determined on the way management recognizes the segments within the Group for making operating decisions and how they are evident from the Group structure.

Exploration and production segment activities consist of oil extraction by production divisions. Intersegment sales in exploration and production constitute transfers of crude oil and gas from production divisions to the refining and marketing divisions and subsidiaries.

The Group’s investments in equity method investees and equity in the net income of investees accounted for by the equity method are included within exploration and production segments, as the Group’s major equity investees are engaged in exploration and production activities. The Group’s investments and equity in the income of the equity investees are disclosed in Note 7.

Refining and marketing comprises purchases and sales of crude oil and refined products from the Group’s own production divisions and third parties, own refining activities and retailing operations. As in prior years, the Company sold significant volumes of oil to intermediaries, which refine oil in domestic refineries, and purchased refined products processed from its oil.

Sales of petrochemical products include sales of petrochemical raw materials and refined products, which are used in production of tires. Sales of tires are disclosed by geographic segment for the reporting periods.

Other sales include revenues from ancillary services provided by the specialized subdivisions and subsidiaries of the Group, such as sales of oilfield equipment and drilling services provided to other companies in Tatarstan, revenues from the sales of auxiliary petrochemical related services and materials as well as other business activities, which do not constitute reportable business segments.

In accordance with SFAS No.131, “Disclosures about Segments of an Enterprise and Related Information”, the Group reports bank interest revenue net of interest expense since a majority of the banking segment’s revenues are from interest and the management relies primarily on the “spread” between interest revenue and interest expense (net interest revenue) to assess performance of the segment and to make resource allocation decisions.

F-40

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 18: Segment Information (continued)

For the years ended December 31, 2003, 2002 and 2001 the Group had one customer which accounted for RR 34,249 million, RR 19,258 million and RR 3,144 million of sales, which represents 22%, 13% and 2% of total sales, respectively. These sales are included within refining and marketing revenues. Management does not believe that the Group is reliant on any particular customer.

The Group evaluates performance of its reportable operating segments and allocates resources based on income or losses before income taxes and minority interest not including non-banking net interest expense and monetary effects. Segment accounting policies are the same as those disclosed in Note 3. Intersegment sales are at prices that approximate market.

Segment sales and other operating revenues. Reportable operating segment sales and other operating revenues are stated in the following table:


	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
Exploration and production
Intersegment sales	93,155		84,394		91,528

Total exploration and production	93,155		84,394		91,528

Refining and marketing
Crude oil	11,346		11,901		32,371
Refined products	23,545		24,378		18,971

Domestic sales	34,891		36,279		51,342

Crude oil	9,470		11,510		6,997
Refined products	336		30		705

CIS sales⁽¹⁾	9,806		11,540		7,702

Crude oil	69,511		57,886		55,855
Refined products	19,950		19,968		24,183

Non – CIS sales⁽²⁾	89,461		77,854		80,038

Total refining and marketing	134,158		125,673		139,082

Petrochemicals
Intersegment sales	233		322		1,311
Tires - domestic sales	7,764		7,046		2,517
Tires - CIS sales	1,799		908		38
Tires - non-CIS sales	739		814		163
Petrochemical and refined products	1,281		1,152		1,415

Total petrochemicals	11,816		10,242		5,444

Banking
Net interest income – intersegment	530		335		265
Net interest income	1,001		845		1,350

Total banking	1,531		1,180		1,615

Total segment sales	240,660		221,489		237,669

Other sales	9,177		10,038		12,797

Elimination of intersegment sales	(93,918	)	(85,051	)	(93,104	)

Elimination of income from equity investments reported separately in the consolidated statements of operations and comprehensive income	(101	)	(148	)	(501	)

Total sales and other operating revenues	155,818		146,328		156,861

⁽¹⁾	- CIS is an abbreviation for Commonwealth of Independent States (excluding the Russian Federation).

⁽²⁾	- Non-CIS sales of crude oil and refined products are mainly made to European markets.

F-41

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 18: Segment Information (continued)

Segment earnings and assets. Segment earnings are as follows:


	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
			(restated)		(restated)
Segment earnings (loss)
Exploration and production	13,566		18,227		19,585
Refining and marketing	2,730		2,627		3,846
Petrochemicals	(311	)	(139	)	337
Banking	421		811		1,275

Total segment earnings	16,406		21,526		25,043

Exchange loss	(225	)	(1,042	)	(851	)
Monetary gain	—		871		1,764
Interest expense, net	(1,524	)	(2,051	)	(1,358	)

Income before income taxes and minority interest	14,657		19,304		24,598

Segment assets are as follows:


	At December 31, 2003	At December 31, 2002
Assets
Exploration and production	186,632	161,420
Refining and marketing	38,814	37,623
Petrochemicals	8,924	9,591
Banking	28,347	17,654

Total assets	262,717	226,288

The Group’s assets and operations are primarily located and conducted in Russia.

Segment depreciation, depletion and amortization and additions to property, plant and equipment are as follows:


	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
		(restated)	(restated)
Depreciation, depletion and amortization
Exploration and production	7,150	5,938	5,315
Refining and marketing	742	667	462
Petrochemicals	924	912	346
Banking	34	24	16

Total segment depreciation, depletion and amortization	8,850	7,541	6,139

Additions to property, plant and equipment
Exploration and production	21,320	10,519	18,824
Refining and marketing	2,766	3,576	5,027
Petrochemicals	1,768	818	939
Banking	86	612	20

Total additions to property, plant and equipment	25,940	15,525	24,810

F-42

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 19: Related Party Transactions

Transactions are entered into in the normal course of business with significant shareholders, directors and companies with which the Group has significant shareholders and directors in common (see also Note 1). These transactions include sales of crude oil and refined products, purchases of electricity and banking transactions.

In 2003 the Group transferred RR 672 million to several companies outside the Russian Federation unrelated to the Group which the Group intended to use for an acquisition of Company’s shares. The shares acquired for the benefit of the Group were accumulated by one of these companies located in Cyprus with the intention of being used by the Group in the development and establishment of an anticipated incentive scheme for its senior employees. In 2003, RR 570 million of the total funds transferred were used in the acquisition of 20,676,875 Group’s shares and reported in the consolidated financial statements as common shares held in treasury as of December 31, 2003. The remaining funds of RR 98 million were recorded within other prepaid expenses and other current assets as of December 31, 2003. In January 2004, an additional 2,788,300 shares were acquired using these funds. All shares accumulated by the Cyprus based company were transferred to the Group in November 2004.

The transactions for each year and the outstanding balances at each year end with related parties are as follows:


	Year ended December 31, 2003		Year ended December 31, 2002		Year ended December 31, 2001
Sales of crude oil	23,644		12,387		10,452
Volumes of crude oil sales (thousand tons)	4,409		3,037		3,460
Sales of refined products	14,080		9,621		5,632
Volumes of refined product sales (thousand tons)	4,101		2,817		2,036
Sales of petrochemical products	671		645		1,232
Other sales	704		429		—
Purchases of crude oil	(798	)	(1,330	)	(11,457	)
Volumes of crude oil purchases (thousand tons)	249		376		3,372
Purchases of refined products	—		(6	)	(1,837	)
Volumes of refined products purchases (thousand tons)	—		1		838
Purchases of petrochemical products	(2,072	)	(2,001	)	(2,546	)
Purchases of electricity	(2,940	)	(3,038	)	(2,324	)
Other purchases	(1,186	)	(761	)	(946	)
Sales of investment (AK Bars Bank shares sold to FLK)	—		—		403
Interest receivable	12		38		33
Bank commission receivable	6		22		55
Additions to property, plant and equipment	(2,223	)	—		—

F-43

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 19: Related Party Transactions (continued)


	At December 31, 2003		At December 31, 2002
*Assets*
Trade accounts receivable (Note 6)	5,546		1,380
Notes receivable	440		1,883
Loans and advances to customers (Note 10)	645		842

Due from related parties	6,631		4,105

*Liabilities*
Banking customer deposits (Note 13)	(100	)	(585	)
Loans payable	(394	)	(111	)
Trade accounts payable	(540	)	(66	)

Due to related parties	(1,034	)	(762	)

Capital lease obligations	(1,002	)	—

*Other*
Common shares held in treasury for an anticipated incentive scheme, at cost (20,676,875 shares at December 31, 2003)	570		—
Loan guarantee obligations	(181	)	(211	)

The Group continued to enter into back-to-back crude oil transactions with various parties. These transactions are not recorded as purchases and sales of crude oil but the net commission amounting to RR 956 million, RR 1,514 million, and RR 1,414 million, of which nil, nil and RR 595 million were associated with transactions with related parties, for the years ended December 31, 2003, 2002 and 2001, respectively, are included within selling, general and administrative expenses. The volumes of crude oil sold and purchased under these transactions were 853 thousand, 2,829 thousand, and 2,500 thousand tons for the years ended December 31, 2003, 2002 and 2001, respectively.

Note 20: Financial Instruments and Risk Management

Fair values. The carrying amounts of short-term financial instruments approximate fair value because of the relatively short period of time between the origination of these instruments and their expected realization.

Information concerning the fair value of long-term investments is disclosed in Note 7.

Information concerning the fair value of loans receivable and advances is disclosed in Note 10.

Information concerning the fair value of short-term and long-term debt is disclosed in Note 12.

Information concerning the fair value of notes payable and banking customer deposits is disclosed in Note 13.

Credit risk. The Group’s financial instruments that are potentially exposed to concentrations of credit risk consist primarily of accounts receivables, cash and cash equivalents, prepaid VAT as well as loans receivable and advances. A significant portion of the Groups’s accounts receivable is due from domestic and export trading companies. The Group does not generally require collateral to limit the exposure to loss; however, sometimes letters of credit and prepayments are used. Although collection of these receivables could be influenced by economic factors affecting these entities, management believes there is no significant risk of loss to the Group beyond provisions already recorded.

The Group deposits available cash mostly with financial institutions in the Russian Federation. Deposit insurance for deposits of legal entities is not offered to financial institutions operating in the Russian Federation. To manage this credit risk, the Group allocates its available cash to a variety of Russian banks and Russian affiliates of international banks. Management periodically reviews the credit worthiness of the banks in which it deposits cash.

F-44

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Prepaid VAT, representing amounts payable or paid to suppliers, is recoverable from the tax authorities via offset against VAT payable to the tax authorities on the Group’s revenue or direct cash receipts from the tax authorities. Management periodically reviews the recoverability of the balance of prepaid VAT and believes it is fully recoverable within one year.

F-45

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 20: Financial Instruments and Risk Management (continued)

The Group’s banks take on exposures to credit risk which is the risk that a counter party will be unable to pay amounts in full when due. The banks structure the level of credit risk they undertake by placing limits on the amount of risk accepted in relation to one borrower, or groups of borrowers, and to geographical and industry segments. Such risks are monitored on a revolving basis and subject to an annual or more frequent review. Limits on the level of credit risk by product, borrower and industry sector are reviewed regularly. Exposure to credit risk is also managed in part by obtaining collateral and corporate and personal guarantees.

Note 21: Commitments and Contingent Liabilities

Guarantees and commitments. At December 31, 2003, the Group was liable for certain contingent obligations under various contractual arrangements. Credit-related commitments comprise Zenit Bank loan commitments and guarantees of RR 1,809 million and RR 2,062 million at December 31, 2003 and 2002, respectively. The contractual amount of these commitments represents the value at risk if the bank’s clients default and all existing collateral becomes worthless. The Group is required to recognize a liability at inception for the fair value of the obligation as a guarantor for guarantees issued or modified after December 31, 2002. The Group has not recognized a liability either because the guarantees were issued prior to December 31, 2002 and have not been subsequently modified, or because the fair value of the obligations is not material.

Operating environment. While there have been improvements in the economic situation in the Russian Federation in recent years, the country continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible in any countries outside of the Russian Federation, restrictive currency controls, and relatively high inflation. The prospects for future economic stability in the Russian Federation are largely dependent upon the effectiveness of economic measures undertaken by the government, together with legal, regulatory, and political developments.

Taxation. Russian tax legislation is subject to varying interpretations and constant changes. Further, the interpretations of tax legislation by tax authorities as applied to the transactions and activities of the Group may not coincide with that of management. Also interpretations on the application of the tax legislation may vary between regional and Federal tax authorities. As a result, transactions may be challenged by tax authorities and the Group may be assessed for additional taxes, penalties and interest. Consolidated tax returns are not required under existing Russian tax legislation and tax audits are performed on an individual entity basis only. Tax periods remain open to review by the tax authorities for three years.

Environmental contingencies. The Group, through its predecessor entities, has operated in Tatarstan for many years without developed environmental laws, regulations and Group policies. Environmental regulations and their enforcement are currently being considered in the Russian Federation and the Group is monitoring its potential obligations related thereto. The outcome of environmental liabilities under proposed or any future environmental legislation cannot reasonably be estimated at present, but could be material. Under existing legislation, however, management believes that there are no probable liabilities that are in addition to the immaterial amounts already accrued in the consolidated financial statements, which would have a material adverse effect on the operating results or financial position of the Group.

Legal contingencies. The Group is subject to various lawsuits and claims arising in the ordinary course of business. The outcomes of such contingencies, lawsuits or other proceedings cannot be determined at present. In the case of all known contingencies, the Group accrues a liability when the loss is probable and the amount is reasonably estimable. Based on currently available information, management believes that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the Group’s consolidated financial statements.

In 2003 OAO “TAIF”, a related party to the Group, brought a case before the Arbitration Court of Tatarstan Republic claiming a return of equipment leased to OAO “Nizhnekamsk NPZ”, a subsidiary of the Group (the “Refinery”), because of breach by the Refinery of several provisions of the lease agreement dated December 29, 2001. This equipment was installed at the Refinery in 2002 and represents vital assets for the operations of the Refinery. On October 6, 2003 the Arbitration Court ruled in favor of OAO “TAIF” and this decision was reinforced by the instance of appeals of the Arbitration Court of Tatarstan Republic on January 13, 2004. Currently, the Refinery operates at full capacity and no actions have been taken by OAO “TAIF” to remove the leased equipment. The management of the Group believes that the government of Tatarstan Republic will not allow OAO “TAIF” to proceed with the court decision and cease operations of the Refinery or to claim any other compensation from the Refinery for the breach of the lease agreement. Therefore management believes there is no financial statements impact from this court ruling (see also Note 1).

F-46

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 21: Commitments and Contingent Liabilities (continued)

Social commitments. The Group contributes significantly to the maintenance of local infrastructure and the welfare of its employees within Tatarstan, which includes contributions towards the construction, development and maintenance of housing, hospitals and transport services, recreation and other social needs. Such funding is periodically determined by the Board of Directors after consultation with governmental authorities and recorded as expenditures when incurred.

In addition, the Group is committed to make certain contributions which are determined solely at the discretion of the Group’s or its subsidiaries’ management but not less than the minimum annual payment regulated by current Russian legislation. Also the provisions of collective agreements concluded on an annual basis between the Company or its subsidiary and their employees require the Group to pay certain post-employment and other benefits, to follow health and safety standards as well as a variety of other social benefits in excess of those required by law. In 2003, 2002 and 2001 the contributions to the non-governmental pension plan and post-employment benefit payments were not material (see also Note 1).

Transportation of crude oil. The Group benefits from the blending of its crude oil in the Transneft pipeline system since the Group’s crude oil production is generally of a lower quality than that produced by other regions of the Russian Federation which supply through the same pipeline system. There is currently no equalization scheme for differences in crude oil quality within the Transneft pipeline system and the implementation of any such scheme is not determinable at present. However, if this practice were to change, the Group’s business could be materially and adversely affected.

Banking contingent liabilities. Zenit Bank fiduciary assets and trust arrangements at nominal value amounted to RR 10,857 million and RR 4,148 million at December 31, 2003 and 2002, respectively, and are recorded off balance sheet as they are not assets of Zenit Bank. There is no insurance coverage maintained.

The Central Bank of Russian Federation requires banks to maintain a capital adequacy ratio of 10% of risk-weighted assets, computed based on Russian accounting legislation. As of December 31, 2003 and 2002, the Zenit Bank and Devon-Credit Bank capital adequacy ratio on this basis exceeded the statutory minimum.

Note 22: Subsequent Events

TUPRAS auction. In January 2004, Efremov Kautschuk GmbH (“EKG”), a subsidiary of OAO “Efremovsky Zavod Sinteticheskogo Kauchuka” was pronounced winner of a privatization auction for 65.8% of Turkey’s oil refining company – Türkiye Petrol Rafinerileri A.S. (“TUPRAS”). OAO “Efremovsky Zavod Sinteticheskogo Kauchuka” is a related company to the Group because of representation of the Group’s senior managers on the Board of Directors of OAO ”Efremovsky Zavod Sinteticheskogo Kauchuka”. Subsequently EKG formed a consortium with Zorlu Holding A.S. and established a joint venture, Tatneft Zorlu Petrol Yatirimlari Ve Ticaret A.S. (“Tatneft-Zorlu”), in which the Company agreed to purchase 50% if Tatneft-Zorlu acquires the shares in TUPRAS.

In November 2004 the Turkish High Administrative Court cancelled the results of the auction and, therefore, the Company’s undertaking to purchase 50% in Tatneft-Zorlu from EKG was terminated. In May 2005 the Turkish government announced a new auction for 51% of the shares in TUPRAS. The Group is not participating in this new auction and has no commitment to participate in any future auction or tender for the sale of TUPRAS’ shares, which may be organized by the Turkish government, or otherwise to acquire any shares in TUPRAS.

New significant borrowings. In March 2004 the Group issued 1 million unsecured bonds with a nominal value of RR 1,000 per bond for RR 1,000 million. Bonds carry a coupon yield of 8.69% for the first and the second payments due in September 2004 and March 2005. Subsequent coupon yields are determined by the Chairman of the Board of Zenit Bank. Bonds mature in March 2007.

Repayments of loans. In 2004 - 2005 the Group was repaying its debts in accordance with the original schedules of repayment.

F-47

TATNEFT

Notes to Consolidated Financial Statements

(in millions of Russian Roubles)

Note 22: Subsequent Events (continued)

Transactions with government authorities (see also Note 1). In the first quarter of 2004 upon receipt of the letter from the Tax Ministry of Tatarstan the Group offset previously recognized receivable due from the Tax Ministry (see Note 9) against income tax, VAT and unified production tax liability in the amount of RR 2,251 million.

In September 2004 the Group entered into a RR 2,000 million loan agreement with OAO “Svyazinvestneftekhim”, a company controlled by Tatarstan government. The loan interest rate is 0,01% per annum and matures in March 2014.

In 2004 the Group purchased promissory notes issued by entity “Tatgospostavki”, a unitary company controlled by Tatarstan government, in the amount of RR 960 million in order to finance social expenditures planned under Tatarstan’s budget at the request of Tatarstan government.

Dividends. At the annual general meeting of shareholders on June 25, 2004, final dividends of RR 0.30 per common share and RR 1.00 per preferred share, expressed in nominal Russian Roubles, were approved for 2003 for all shareholders.

At the extraordinary general meeting of shareholders on November 6, 2004, interim dividends of RR 0.67 per common share and RR 1.00 per preferred share, expressed in nominal Russian Roubles, were approved for the nine months ended September 30, 2004 for all shareholders.

At the annual general meeting of shareholders in June 2005, additional dividends of RR 0.23 per common share and RR 0 per preferred share, expressed in nominal Russian Roubles, were approved for 2004 for all shareholders.

Transactions with employees’ stock options. In 2004 the Company repurchased the options granted in 2003 through cash settlement at the price of RR 40.26 per option.

Changes in Group’s composition. In April 2005 the Group decreased its share in the equity of a major subsidiary, Zenit Bank (the “Bank”), by selling 26.75% of the Bank’s shares to three Cyprus based companies, acting for the benefit of certain beneficiaries of Urals Energy, which is not related to the Group. As a result of this transaction, as of April 28, 2005 the Group no longer controls the Bank and will account for its remaining 25.95% equity investment in the Bank under equity method in its US GAAP financial statements for the periods subsequent to the sale. The sales price for the Bank’s shares, RR 1,214 million (US$ 41.2 million), was determined based on the results of an independent evaluation. The sale of 26.75% of the bank’s shares resulted in a loss on disposal of approximately RR 700 million.

In September 2004 the Group increased its shareholding in AK Bars bank from 19.9% to 30% for RR 2,000 million.

In December 2003, together with the government of Tatarstan, OAO Tatneftekhiminvest-Holding, OAO Nizhnekamskneftekhim, LG International Corp. and LG Engineering and Construction Corp., the Group signed a letter of intent contemplating future joint work on the construction of an oil refining and petrochemical complex on the territory of Tatarstan. The Group 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. The Group holds a 45.5% interest in OAO TKNK; OAO 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, the Group provided TKNK with a RR 127 million (US $4.3 million) loan for financing feasibility studies and services as part of developing the oil refining and petrochemical complex. In addition, the Group has invested RR40 million into 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, total necessary investment will amount to approximately RR 53 billion (US $1.8 billion). However, at this stage the Group cannot predict the level of additional capital investment that may be required from the Group in connection with this project as the financing structure of the venture has yet to be determined.

F-48

TATNEFT

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(in millions of Russian Roubles)

In accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”, this section provides supplemental information on oil and gas exploration and production activities of the Group.

The Group’s oil and gas production is predominantly in Tatarstan within the Russian Federation; therefore, all of the information provided in this section pertains entirely to that region.

Oil Exploration and Production Costs

The following tables set forth information regarding oil exploration and production costs. The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year.

Costs Incurred in Exploration and Development Activities


	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
Exploration costs	1,091	1,153	1,140
Development costs	6,679	7,807	14,091

Total costs incurred in exploration and development activities	7,770	8,960	15,231

Property acquisitions are immaterial to the Group’s oil activities.

Capitalized Costs of Proved Oil Properties


	At December 31, 2003		At December 31, 2002
			(restated)
Wells, support equipment and facilities	256,731		235,223
Uncompleted wells, equipment and facilities	3,837		4,346

Total capitalized costs of proved oil properties	260,568		239,569
Accumulated depreciation, depletion and amortization (Note 11)	(124,312	)	(129,168	)

Net capitalized costs of proved oil properties	136,256		110,401

The following information pertains to the drilling activities of the Group:


	Year ended December 31, 2004	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
Net productive development wells drilled	359	420	427	610
Net productive exploratory wells drilled	29	28	35	32

Total wells drilled	388	448	462	642

As of December 31, 2004 and 2003 the number of net productive oil wells were 18,659 and 19,209, respectively.

For the five months ended May 31, 2005 the Group drilled 135 new productive wells. The Group received an additional four licenses for the exploration and production of hydrocarbon materials in deposits on the territory of the Samara and Orenburg Regions in a license tenders held in 2005.

F-49

TATNEFT

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(in millions of Russian Roubles)

Results of Operations for Oil and Gas Producing Activities

The Group’s results of operations from oil producing activities are shown below. Proved natural gas reserves do not represent a significant portion of the Group’s total reserves.

In accordance with SFAS 69, results of operations do not include general corporate overhead and monetary effects nor their associated tax effects. Income taxes are based on statutory rates for the year, adjusted for tax deductions, tax credits and allowances.


	Year ended December 31, 2003	Year ended December 31, 2002	Year ended December 31, 2001
		(restated)	(restated)
Revenues from net production:
Sales	79,344	70,360	78,957
Transfers⁽¹⁾	13,811	14,034	12,571

Total revenues from net production	93,155	84,394	91,528

Less:
Production costs⁽²⁾	26,562	24,521	26,821
Exploration expenses	812	463	839
Depreciation, depletion and amortization	6,985	5,677	5,182
Taxes other than income taxes	32,977	25,977	20,331
Related income taxes	6,197	6,661	6,904

Results of operations for oil and gas producing activities	19,622	21,095	31,451

⁽¹⁾	Transfers represent crude oil transferred to the refining subsidiaries at the estimated market price of those transactions.

⁽²⁾	Production costs include transportation expenses and accretion of discount in accordance with SFAS 143.

The average sales price (including transfers) per ton for 2003, 2002 and 2001 are RR 3,736, RR 3,391 and RR 3,682, respectively. The average production cost per ton for 2003, 2002, and 2001 are RR 1,065, RR 985 and RR 1,079, respectively.

Proved Oil Reserves

As determined by the Group’s independent reservoir engineers, Miller and Lents, Ltd., the following information presents the balances of proved oil reserves at December 31, 2003, 2002 and 2001. The definitions used are in accordance with applicable US Securities and Exchange Commission (“SEC”) regulations.

Proved reserves are the estimated quantities of oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change over time as additional information becomes available.

Management believes that proved reserves should include quantities which are expected to be produced after the expiry dates of the Group’s production licenses. Most significant licenses expire in 2013. Management believes the licenses may be extended at the initiative of the Group and management expects to extend such licenses for properties expected to produce subsequent to their license expiry date. The Group has disclosed information on proved oil and gas reserve quantities and standardized measure of discounted future net cash flows for periods up to and past the license expiry dates separately (see Note 11).

Proved developed reserves are those reserves which are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those reserves which are expected to be recovered as a result of future investments to drill new wells and/or to install facilities to collect and deliver the production from existing and future wells.

“Net” reserves exclude quantities due to others when produced.

F-50

TATNEFT

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(in millions of Russian Roubles)

Proved Oil Reserves (continued)

A significant portion of the Group’s total proved reserves are classified as either developed non-producing or undeveloped. The developed non-producing proved reserves can be produced from existing well bores but require capital costs for workovers, recompletions, or restoration of shut-in wells or additional completion work or future recompletion prior to the start of production. Of the developed non-producing proved reserves, a significant portion represents existing wells which are expected to be put back into production at a future date.

Net proved reserves of crude oil at December 31, 2003:


	Net proved reserves of crude oil recoverable up to license expiry dates		Net proved reserves of crude oil recoverable past license expiry dates		Total net proved reserves of crude oil
	(millions of barrels)	(millions of tons)	(millions of barrels)	(millions of tons)	(millions of barrels)	(millions of tons)
Net proved developed producing reserves	1,448	204	2,067	290	3,515	494
Net proved developed non-producing reserves	531	75	1,536	215	2,067	290

Net proved developed reserves	1,979	279	3,603	505	5,582	784

Net proved undeveloped reserves	137	19	240	34	377	53

Net proved developed and undeveloped reserves	2,116	298	3,843	539	5,959	837

Net proved reserves of crude oil at December 31, 2002:


	Net proved reserves of crude oil recoverable up to license expiry dates		Net proved reserves of crude oil recoverable past license expiry dates		Total net proved reserves of crude oil
	(millions of barrels)	(millions of tons)	(millions of barrels)	(millions of tons)	(millions of barrels)	(millions of tons)
Net proved developed producing reserves	1,567	220	1,840	258	3,407	478
Net proved developed non-producing reserves	627	88	1,485	208	2,112	296

Net proved developed reserves	2,194	308	3,325	466	5,519	774

Net proved undeveloped reserves	168	24	285	40	453	64

Net proved developed and undeveloped reserves	2,362	332	3,610	506	5,972	838

F-51

TATNEFT

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(in millions of Russian Roubles)

Proved Oil Reserves (continued)

Net proved reserves of crude oil at December 31, 2001:


	Net proved reserves of crude oil recoverable up to license expiry dates		Net proved reserves of crude oil recoverable past license expiry dates		Total net proved reserves of crude oil
	(millions of barrels)	(millions of tons)	(millions of barrels)	(millions of tons)	(millions of barrels)	(millions of tones)
Net proved developed producing reserves	1,621	228	1,539	216	3,160	444
Net proved developed non-producing reserves	718	101	1,157	162	1,875	263

Net proved developed reserves	2,339	329	2,696	378	5,035	707

Net proved undeveloped reserves	173	24	247	35	420	59

Net proved developed and undeveloped reserves	2,512	353	2,943	413	5,455	766

F-52

TATNEFT

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(in millions of Russian Roubles)

Movements in Proved Oil Reserves


	Net proved reserves of crude oil recoverable up to license expiry dates				Net proved reserves of crude oil recoverable past license expiry dates				Total net proved reserves of crude oil
	(millions of barrels)		(millions of tons)		(millions of barrels)		(millions of tons)		(millions of barrels)		(millions of tons)
Balance at December 31, 2000	2,303		324		3,641		510		5,944		834
Revisions	384		54		(698	)	(97	)	(314	)	(43	)
Production	(175	)	(25	)	—		—		(175	)	(25	)

Balance at December 31, 2001	2,512		353		2,943		413		5,455		766
Revisions	25		4		667		93		692		97
Production	(175	)	(25	)	—		—		(175	)	(25	)

Balance at December 31, 2002	2,362		332		3,610		506		5,972		838
Revisions	(70	)	(9	)	233		33		163		24
Production	(176	)	(25	)	—		—		(176	)	(25	)

Balance at December 31, 2003	2,116		298		3,843		539		5,959		837

Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Cash Flows

For the purposes of the following disclosures, estimates were made of quantities of proved reserves and the periods in which they are expected to be produced. Future cash flows were computed by applying year-end prices (as described below) to the Group’s estimated annual future production from proved oil reserves. Future development and production costs were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income taxes were computed by applying, generally, year-end statutory tax rates (adjusted for tax deductions, tax credits and allowances) to the estimated future pretax cash flows. The discount was computed by application of a 10% discount factor. The calculations assumed the continuation of existing political, economic, operating and contractual conditions at each of December 31, 2003, 2002, and 2001. However, such arbitrary assumptions have not necessarily proven to be the case in the past and may not in the future. Other assumptions of equal validity would give rise to substantially different results. As a result, future cash flows calculated under this methodology are not necessarily indicative of the Group’s future cash flows nor the fair value of its oil reserves.

The net price used in the forecast of future net revenue is the weighted average year end price received for sales domestically, for exports to Commonwealth of Independent States (“CIS”) countries, and for exports to non-CIS countries, after adjustments, where applicable, for certain costs, duties, and taxes. The weighted average net prices per ton used in the forecasts for 2003, 2002, and 2001, are US $120.61, US $93.81 and US $81.89 (US $16.93, US $13.17 and US $11.50 per barrel), respectively.


	Year ended December 31, 2003
	Future cash flows attributable to net proved reserves recoverable up to license expiry dates		Future cash flows attributable to net proved reserves recoverable past license expiry dates		Future cash flows attributable to total recoverable net proved reserves
Future cash inflows from production	1,092,195		1,984,230		3,076,425
Future development and production costs	(636,470	)	(1,237,051	)	(1,873,521	)
Future income taxes	(157,631	)	(121,647	)	(279,278	)

Future net cash flows	298,094		625,532		923,626

10% annual discount	(109,124	)	(527,740	)	(636,864	)

Discounted future net cash flows	188,970		97,792		286,762

F-53

TATNEFT

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(in millions of Russian Roubles)

Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Cash Flows (continued)


	Year ended December 31, 2002
	Future cash flows attributable to net proved reserves recoverable up to license expiry dates		Future cash flows attributable to net proved reserves recoverable past license expiry dates		Future cash flows attributable to total recoverable net proved reserves
Future cash inflows from production	1,005,955		1,537,793		2,543,748
Future development and production costs	(637,002	)	(1,016,709	)	(1,653,711	)
Future income taxes	(97,381	)	(107,108	)	(204,489	)

Future net cash flows	271,572		413,976		685,548

10% annual discount	(102,970	)	(343,204	)	(446,174	)

Discounted future net cash flows	168,602		70,772		239,374


	Year ended December 31, 2001
	Future cash flows attributable to net proved reserves recoverable up to license expiry dates		Future cash flows attributable to net proved reserves recoverable past license expiry dates		Future cash flows attributable to total recoverable net proved reserves
Future cash inflows from production	1,018,291		1,192,994		2,211,285
Future development and production costs	(683,160	)	(814,821	)	(1,497,981	)
Future income taxes	(91,967	)	(71,449	)	(163,416	)

Future net cash flows	243,164		306,724		549,888

10% annual discount	(93,774	)	(255,707	)	(349,481	)

Discounted future net cash flows	149,390		51,017		200,407

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserve Quantities


	Year ended December 31, 2003
	Future cash flows attributable to net proved reserves recoverable up to license expiry dates		Future cash flows attributable to net proved reserves recoverable past license expiry dates		Future cash flows attributable to total net proved reserves
Beginning of year	168,602		70,772		239,374
Sales and transfers of oil produced, net of production costs and other operating expenses	(34,194	)	—		(34,194	)
Net change in prices received per ton, net of production costs and other operating expenses	77,633		35,356		112,989
Change in estimated future development costs	4,532		(8,347	)	(3,815	)
Revisions of quantity estimates	(8,514	)	5,024		(3,490	)
Development costs incurred during the period	6,958		—		6,958
Accretion of discount	21,228		8,195		29,423
Net change in income taxes	(41,721	)	13,847		(27,874	)
Changes in production rate and other	(5,554	)	(27,055	)	(32,609	)

End of year	188,970		97,792		286,762

F-54

TATNEFT

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

(in millions of Russian Roubles)

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserve Quantities (continued)


	Year ended December 31, 2002
	Future cash flows attributable to net proved reserves recoverable up to license expiry dates		Future cash flows attributable to net proved reserves recoverable past license expiry dates		Future cash flows attributable to total net proved reserves
Beginning of year	149,390		51,017		200,407
Sales and transfers of oil produced, net of production costs and other operating expenses	(33,896	)	—		(33,896	)
Net change in prices received per ton, net of production costs and other operating expenses	50,332		7,082		57,414
Change in estimated future development costs	(1,565	)	(510	)	(2,075	)
Revisions of quantity estimates	3,676		28,673		32,349
Development costs incurred during the period	8,104		—		8,104
Accretion of discount	18,861		4,953		23,814
Net change in income taxes	(8,155	)	(10,976	)	(19,131	)
Changes in production rate and other	(18,145	)	(9,467	)	(27,612	)

End of year	168,602		70,772		239,374


	Year ended December 31, 2001
	Future cash flows attributable to net proved reserves recoverable up to license expiry dates		Future cash flows attributable to net proved reserves recoverable past license expiry dates		Future cash flows attributable to total net proved reserves
Beginning of year	299,447		95,533		394,980
Sales and transfers of oil produced, net of production costs and other operating expenses	(44,376	)	—		(44,376	)
Net change in prices received per ton, net of production costs and other operating expenses	(225,457	)	(123,632	)	(349,089	)
Change in estimated future development costs	(27,409	)	11,089		(16,320	)
Revisions of quantity estimates	26,574		(34,697	)	(8,123	)
Development costs incurred during the period	14,392		—		14,392
Accretion of discount	42,325		11,987		54,312
Net change in income taxes	104,187		55,208		159,395
Changes in production rate and other	(40,293	)	35,529		(4,764	)

End of year	149,390		51,017		200,407

F-55

APPENDIX A

TATNEFT’S BANKING OPERATIONS

We own shares in a number of banking and financial entities, but following the sale of our controlling share in Bank Zenit, 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:

•

Our principal banking business activity is commercial banking operations within the Russian Federation. The number of employees engaged in our banking activities was 1,823, 1,642 and 1,273 at December 31, 2004, 2003 and 2002, respectively. Bank Zenit employed 1,218, 1,101 and 782 persons at December 31, 2004, 2003 and 2002, respectively, and Bank Devon-Credit employed 574, 539 and 491 persons at December 31, 2004, 2003 and 2002, respectively.

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

Banking Supervision and Regulation

The Russian Banking Sector

The Russian banking sector consists of the Central Bank, credit organizations (banks and non-bank credit organizations) and representative offices of foreign banks. Non-bank credit organizations provide only limited banking services, such as maintaining accounts and making payments, whilst banks provide a wide range of banking services. The representative offices of foreign banks, in practice, do not carry out the same operations as Russian licensed credit institutions, and their activities are generally limited to facilitating banking operations of their respective parents by representing their interests. As of December 1, 2004, 1,304 banks and other non-bank credit organizations that have banking licenses were registered in Russia. An additional 227 credit organizations had had their banking licenses revoked by the Central Bank as of that date. A majority (672 as of December 1, 2004) of operating Russian credit organizations are located in Moscow and the Moscow region.

According to the Central Bank, as of November 1, 2004, the total assets of the Russian banking sector were valued at RR6.6 trillion and the five largest banks accounted for 44.7% of all banking sector assets (under RAR) in Russia. Expert magazine identifies Sberbank, VTB, Gazprombank, Alfa-Bank and Bank of Moscow as the five largest banks (under RAR) by assets as of November 1, 2004, with Sberbank having the largest assets (RR1.86 trillion as of July 1, 2004).

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The main business areas of Russian banks are deposit taking and maintaining accounts, providing settlement services for legal entities, lending and investing in securities.

According to the Central Bank (based on RAR financial statements of credit organizations), as of July 1, 2004, funds in current accounts, budget accounts and deposits of legal entities, liabilities under corporate debt securities and other liabilities to clients (excluding retail deposits, other accounts of individuals, funds in correspondent accounts and interbank loans and deposits) comprised 59.7% (RR3.7 trillion) of the total liabilities of Russian credit organizations, whilst retail deposits accounted for 28.6% (RR1.77 trillion). Loans to customers and other investments (other than in securities) comprised 60.1% (RR3.7 trillion) of all assets of credit organizations, including 44.6% (RR2.8 trillion) in loans to companies and other legal entities in the non-financial sector and 6.6% (RR406.5 billion) in loans to and deposits with banks.

According to the Central Bank, loans extended by Russian banks to non-financial sector companies rose from 14.7% of gross domestic product (“GDP”) as of January 1, 2003 to 17.1% as of January 1, 2004. The share of loans to non-financial sector companies in the overall assets of the Russian banking sector rose from 38.4% as of January 1, 2003 to 40.5% as of January 1, 2004.

Loans extended by Russian banks to legal entities are often overcollateralized. According to the Central Bank (based on RAR financial statements of credit organizations), as of July 1, 2004, overdue loans were valued at RR47.7 billion, accounting for 0.8% of all banking assets in Russia.

As of July 1, 2004, investments in securities by credit organizations (based on RAR accounts of credit organizations) represented 18.1% (RR1.1 trillion), including 7.5% (RR460.7 billion) in debt securities of the Russian Federation, of all bank assets in Russia.

According to the Central Bank, as of July 1, 2004, 1,270 operating credit organizations were profitable, whilst 53 were not (data for 3 operating credit organizations was not available).

A private, self-regulatory body, the Association of Russian Banks, established pursuant to the provisions of the Banking Law as a non-commercial and self-regulatory organization, offers technical support to its members and lobbies for the interests of commercial banks in various branches of power (including the Federal Assembly of the Russian Parliament, the government and the Central Bank). As of January 21, 2005, it comprised 624 members, including 505 credit organizations.

Legislative Framework for the Russian Banking Sector

The main law regulating the Russian banking sector is the Federal Law No. 395-I “On Banks and Banking Activity,” dated December 2, 1990, as amended (the “Banking Law”). Among other things, it defines credit organizations, sets out the list of banking operations and other transactions that may be performed by credit organizations and establishes the framework for the registration and licensing of credit organizations and the regulation of banking activity by the Central Bank.

The Banking Law names the following services as “banking operations” that require receipt of an appropriate license from the Central Bank: taking deposits from individuals and legal entities (both demand and fixed-term deposits); investing the deposited funds as a principal; opening and maintaining bank accounts for individuals and legal entities; performing settlements in accordance with the instructions of individuals and legal entities, including correspondent banks, from/to their bank accounts; cash, cheques, promissory notes, payment documents handling services and over-the-counter services provided to individuals and legal entities; sale and purchase of foreign currency (including banknotes and coins); taking deposits in precious metals and investing them; issuing bank guarantees; and making payments in accordance with the instructions of individuals without opening bank accounts (excluding payments by post).

The Banking Law provides that a credit organization may be authorized to take deposits from individuals only after it has been registered for two years. According to the Central Bank, as of December 1, 2004, 1,165 operating credit organizations registered by the Central Bank had been authorized to provide banking services to individuals.

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A system of insurance of private deposits was introduced late in 2003 and is being gradually implemented. According to the Deposit Insurance Law, which was signed into law by President Putin in December 2003, banks holding a Central Bank license for attracting deposits from individuals and opening and administering individual accounts are required to qualify for such activities. Subject to a bank’s compliance with certain regulatory requirements (including all of the Central Bank’s mandatory economic ratios), the bank enters the system for the insurance of individuals’ deposits and thus qualifies for the attraction of retail deposits and opening accounts for individuals. Banks that hold a valid retail banking license must have applied to the Central Bank prior to June 27, 2004 in order to be eligible to become registered as a participant in the mandatory deposit insurance system. There are a number of requirements that such banks are expected to meet before they will be admitted to the system: (i) the Central Bank must be comfortable that the bank’s financial statements and reporting are true; (ii) the bank is in full compliance with the Central Bank mandatory ratios (capital adequacy, liquidity, etc.); (iii) the Central Bank considers the applicant’s solvency position sufficient; and (iv) the Central Bank is not conducting any enforcement actions with respect to the bank and no grounds for such enforcement actions have arisen during the Central Bank’s review of the bank’s application. The Central Bank should consider all applications within nine months of the filing date, but in any event prior to March 27, 2005. If a bank fails to comply with the applicable requirements or chooses not to participate in the insurance system, it will be precluded from taking retail deposits and opening accounts for individuals.

Bank Zenit, Bank Devon-Credit and Bank Ak Bars were all accepted into the system for the insurance of deposits on November 30, 2004, December 15, 2004 and November 23, 2004, respectively.

The Deposit Insurance Law provides for the establishment of a new regulator, the Agency for Deposits’ Insurance (the “Agency”), which is expected, among other things, to assume responsibility for collecting insurance contributions, managing the funds in the mandatory insurance pool, determining insurance premiums and monitoring insurance payments. All banks that have a retail banking license will be entered into the register of the Agency.

Under the Deposit Insurance Law, the protection for each client is limited to RR100,000 (U.S.$3,395.59 at the exchange rate of RR29.45 per U.S.$1.00 in effect on December 31, 2003) per bank and banks are required to make quarterly payments into a deposit insurance fund. The insurance payment from the deposit insurance fund will become payable to depositors if the bank’s license has been revoked or if a moratorium on payments by the bank has been imposed by the Central Bank. The basis of the deposit insurance contribution is the quarterly average of daily balances of retail deposits (excluding bearer deposits). Standard contribution premiums cannot exceed 0.15% of the contribution basis. In certain circumstances, the premium can be increased up to 0.3% of the contribution basis, but not for more than two quarters per every 18 months. When the size of the insurance fund reaches 5% of combined retail deposits of all Russian banks, all succeeding contribution premiums cannot exceed 0.05% of the contribution basis, and when the size of the insurance fund exceeds 10% of all Russian banks’ retail deposits, no contributions need to be made, but will resume once the insurance fund has fallen below 10%.

On July 29, 2004, the President Putin signed federal laws to regulate certain issues arising in connection with the turmoil that the Russian banking sector experienced from April through July 2004 (the “Turmoil Legislation”). The Turmoil Legislation contemplates, among other things, that the Central Bank will make payments to the private depositors of insolvent Russian banks if such banks have not been admitted to the system of the insurance of private deposits (introduced in December 2003) prior to their bankruptcy. The Turmoil Legislation also authorizes the Central Bank to impose, for the term of one year, a limit on the interest rates on deposits paid by banks to private depositors. In addition, under the Turmoil Legislation, banks will be required to disclose certain information related to the interest rates on deposits, banks’ liabilities in respect of deposits and amounts of cash withdrawals by private depositors. It is anticipated that the Central Bank will issue regulations with respect to particular disclosure requirements.

In addition to banking operations, credit organizations are permitted to give sureties for obligations of third parties contemplating payment in cash; to take assignments of rights to demand payment; to engage in trust management of monetary funds and other property for individuals and legal entities; to engage in operations with precious stones and metals (in accordance with the Federal Law “On Precious Stones and Precious Metals” No. 41-FZ of March 26, 1998 and subordinate legislation); to rent out special premises and safe deposit boxes to individuals and legal entities to store documents and valuables; to finance leasing operations; and to provide consultancy services. A credit organization may enter into any other transactions in accordance with the relevant legislation of the Russian Federation.

Under the Banking Law a credit organization cannot engage in production, commodities trading (excluding precious metals) or insurance activities.

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Pursuant to Federal Law No. 3615-I “On Currency Regulation and Currency Control” of October 1992 (the “Old Currency Law”), banks holding general banking licenses (which allow them to perform virtually all banking operations set out in the Banking Law in rubles and foreign currency) acted as “currency control agents.” Currency control agents must supervise all operations of their clients in foreign currency and operations of non-Russian clients in Russian rubles and to report these operations to the Central Bank.

On December 10, 2003, President Putin signed the New Currency Law, which replaces the Old Currency Law. The majority of provisions of the New Currency Law came into effect on June 18, 2004. Under the New Currency Law, Russian banks authorized to conduct transactions in foreign currencies continue to act as “currency control agents.”

The New Currency Law is generally aimed at the gradual liberalization of Russian currency control regulations, but at the same time it introduces some new forms of currency control (such as the placement of mandatory deposits with the Central Bank and the use of special accounts). The New Currency Law provides for most current restrictions to be effective until January 1, 2007. See “Risk Factors – Russian banking and financial regulation has been undergoing significant changes.” Under the New Currency Law, no individual licenses can be issued for foreign currency transactions. Instead the government and the Central Bank are authorized to adopt a general regime for the use of foreign currency applicable to all market participants. With respect to certain currency operations, residents and non-residents may be subject to mandatory deposit requirements in the amount of either up to 100% of the amount of the operation for a period of up to 60 days or up to 20% for a period of up to one year (excluding export/import operations for which special rules are established). In addition, the Central Bank requires residents and non-residents to carry out certain operations through special accounts in addition to the above mandatory deposit requirements. In particular, settlements between residents and non-residents in relation to loans in foreign currency and rubles, as well as securities, non-banking operations of banks and conversion operations may be covered by such special account and mandatory reserve requirements (however, conversion restrictions may not be imposed on authorized banks).

Under the New Currency Law, the Central Bank retains the right to introduce special rules on forms of currency controls set forth in the New Currency Law as applicable to banking operations of credit organizations.

Pursuant to the New Currency Law, the new restrictive measures should be applied by the Central Bank and/or the government with reference to the current economic situation in order to prevent a substantial reduction in Russia’s gold and foreign exchange reserves, to neutralize currency rate swings and to secure a stable balance of payments of the Russian Federation. This implies that these restrictions should not be applied unless the Russian economy is in decline. At the same time, the criteria for the introduction of these restrictive measures are vague enough to allow the Central Bank and the Russian government to apply them at their discretion and on a long-term basis.

Acting as securities broker or dealer and providing custody services (other than when acting as a paying agent) are not covered by any banking license and a credit organization must obtain specific licenses from the FSFM, pursuant to the Federal Law No. 39-FZ “On the Securities Market” of April 22, 1996, as amended, to perform these services. The operations of Russian banks in the securities markets are subject to Russian securities laws and regulations adopted by the FSFM or its predecessor that prescribe detailed rules for acting in Russia’s securities market as a broker, dealer or securities depositaries, govern the relations between professional market participants and investors. The FSFM also acts as the supervisory and control authority for all professional market participants, including banks, with respect to their compliance with Russia’s securities laws and regulations.

In August 2001, the Federal Law “On Combating the Legalization (Laundering) of Income Obtained by Criminal Means” (the “Anti-Money Laundering Law”) was adopted to comply with the requirements of the Financial Action Task Force on Money Laundering (“FATF”). The Anti-Money Laundering Law came into effect on February 1, 2002. Credit organizations are required to comply with the provisions of the Anti-Money Laundering Law relating to, amongst other things, development of appropriate internal standards and procedures, customer identification, control over customer operations and reporting of suspicious activities.

One of the main obligations of banks under the Anti-Money Laundering Law is the control function which involves identification of banks’ clients, information gathering with respect to clients operations and reporting of specific operations to the Federal Service for Financial Monitoring that is the anti-money laundering authority in Russia. The Anti-Money Laundering Law requires that banks control any operations with money or other property if the sum of such operation is equal to or exceeds RR600,000 (or its equivalent in foreign currencies) when such operation involves any of the following: cash transactions, transactions when one of the counter-parties is resident or has a bank account in a country that does not participate in international efforts to combat money-laundering,

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making certain bank deposits that do not identify beneficiaries, other similar transactions involving precious stones, precious metals and other property. In addition, banks are required to control any operation involving any individual or organization that is known to participate in terrorist activities, any legal entity they control or their agents. If bank officers suspect that an operation is conducted in order to legalize any funds received as a result of illegal activity or to finance terrorist activities, banks are required to report such operations whether or not they qualify as controlled operations. Banks are not allowed to inform customers that transactions are being reported to the Federal Service for Financial Monitoring.

Credit organizations are subject to specific insolvency procedures, which are set out in the Federal Law No. 40-FZ “On Insolvency of Credit Organizations” of February 25, 1999, as amended (the “Bank Insolvency Law”). Among other things, the Bank Insolvency Law provides that in the event of winding-up of a credit organization its retail depositors are paid first. Federal Law No. 121-FZ of August 20, 2004, which amends certain provisions of the Bank Insolvency Law, entered into force in late November 2004. The principal changes include: (i) clarification with respect to the period of activity of the temporary administration; (ii) amendment to the definition of “transactions at under value” (increasing the number of transactions which may fall within the scope of that definition); (iii) certain changes in the creditors’ priority ranking in liquidation; and (iv) introduction of a detailed procedure for the liquidation of credit organizations. These new provisions only apply to insolvency proceedings commenced after November 26, 2004.

The Central Bank and Its Role

The Central Bank’s main aim is to protect the ruble and provide for its stability. The Central Bank is also responsible for the development and strength of the Russian banking system and regulates banking activity in Russia. The status of the Central Bank as the banking sector’s regulator is determined by the Constitution of the Russian Federation and developed by the Federal Law of July 10, 2002 No. 86-FZ “On the Central Bank of the Russian Federation (Bank of Russia),” as amended (the “Central Bank Law”). The Central Bank issues licenses authorizing banks to perform a full range of banking operations either in both rubles and foreign currencies or only in rubles and to take deposits from individuals.

The Central Bank was established on July 13, 1990 as a successor to the Russian Republican Bank of Gosbank of the USSR (State Bank of the USSR). With the collapse of the USSR in 1991, the Central Bank inherited the operational facilities and resources of Gosbank of the USSR, including its subsidiaries and branches. According to the Central Bank Law, the government is not liable for the Central Bank’s obligations, nor is the Central Bank liable for the obligations of the government, unless the relevant liability has been undertaken or is required under other Russian laws. The charter capital and other assets of the Central Bank are federal property. As of November 1, 2004, the Central Bank’s assets amounted to approximately RR3.64 trillion, and its gold and hard currency reserves, as of January 14, 2004, amounted to U.S.$120 billion.

The Central Bank is a separate legal entity and is financially independent from the government. Under the Central Bank Law, the Central Bank is generally prohibited from extending loans to the government and regional and municipal governments for the purpose of budget deficit financing and from purchasing state securities in the primary market.

The Central Bank consists of the Moscow Head Office, which hosts the Board of Directors, the National Banking Council (a collegial management body of the Central Bank that conducts certain governing functions, such as making decisions on maximum capital expenditures of the Central Bank, distribution of its profits, appointment of its auditor and approval of its accounting rules and requirements) and central departments. The Central Bank also has a number of regional branches in the constitutive subjects of Russia (in some of the Russian republics the Central Bank’s regional branches are called National Banks) and local branches. The Chairman of the Central Bank is nominated by the President of the Russian Federation and appointed for a fixed term of four years by the State Duma (the lower chamber of the Russian Parliament).

The Chairman of the Central Bank can be replaced under the same procedure and has the right to participate in government (cabinet) meetings. Of the 12 members of the National Banking Council, two are appointed by the Federation Council (the upper chamber of the Russian Parliament) from among its members, three are appointed by the State Duma from among its deputies, three are appointed by the President and three are appointed by the government of the Russian Federation. The Chairman of the Central Bank is an ex officio member of the National Banking Council.

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Under current legislation, the Central Bank has the following major functions:


Function		Summary
Issuing money and regulating its circulation		The Central Bank is the sole issuer of Russian ruble banknotes and regulates their circulation. The Central Bank plans and arranges for the printing of banknotes and the engraving of coins, establishes the rules for their transportation and storage and regulates over-the-counter operations with cash.

Financing/Monetary policy		The Central Bank establishes interest rates for its financings, refinances credit organizations, performs currency interventions, establishes reserve requirements for the banks, sets capital adequacy and similar ratio requirements for banks, issues its own bonds (which can be offered to credit organizations only) and trades in the governmental securities market.

Transactions with banks		Extending loans to banks; maintaining correspondent accounts of banks in rubles; purchasing and selling Russian state securities, Central Bank bonds, certificates of deposit, precious metals and natural gems and holding them in depositary accounts; purchasing and selling foreign currencies and payment documents in foreign currencies issued by Russian and foreign banks. Unless otherwise directly provided for in federal laws, the Central Bank is not permitted to participate in charter capital of banks.

Implementing the federal budget and debt service		Under the Central Bank Law, the Central Bank is prohibited from extending loans to the government in order to finance the state’s budget deficit or purchasing state securities in the primary market, unless a specific exception is established by the federal budget. However, the Central Bank acts as a placement agent with respect to domestic government securities issued by the Ministry of Finance of the Russian Federation, maintains budget accounts and acts as an agent for servicing of the Russian Federation domestic state debt.

Exchange control		The Central Bank regulates dealing and settlements in rubles, foreign currency operations in Russia and by Russian residents abroad, administers Russia’s gold and currency reserves and establishes the regimes for ruble and foreign currency accounts of residents and non-residents in Russia. Formerly it issued permits for performing capital flow operations but ceased to have this authority on June 18, 2004 upon the effectiveness of the New Currency Law.

Licensing		The Central Bank is responsible for rendering decisions on the state registration of banks; registering securities issued by bank; issuing, suspending and revoking banking licenses of credit organizations.

Banking control and supervision		The Central Bank is responsible for monitoring and controlling banks’ compliance with ratios and reserve requirements that it sets. See “– The Central Bank Regulation of the Russian Banking Sector – Mandatory Economic Ratios.” The Central Bank imposes administrative sanctions for violations of banking legislation by credit organizations operating in Russia. The Central Bank sets out standards for financial, accounting and statistical reporting by credit organizations in Russia. The Central Bank appoints the temporary administration of banks that are facing insolvency. The Central Bank receives notifications regarding, and in certain cases controls, the acquisition and trust management of significant (more than 5%) stakes in credit organizations and assesses the financial standing of banks’ founders.

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The Central Bank is authorized to enter into transactions with credit organizations, foreign banks and the government in order to perform the functions outlined above.

The Central Bank has a number of supervisory roles (described below). However, other governmental authorities have indirect influence over credit organizations in Russia. For instance, the FSFM issues, and its predecessor has issued in the past, licenses to banks acting as a broker/dealer or a depositary in the Russian securities market. Tax authorities supervise tax assessments of banks. The Federal Anti-Monopoly Service controls, and its predecessor in the past controlled, mergers of credit organizations and acquisitions of more than 20% of voting stock in a credit organization.

The Central Bank Regulation of the Russian Banking Sector

Under the Central Bank Law, the Banking Law, the Old Currency Law and the New Currency Law, the Central Bank is authorized to adopt binding regulations concerning banking and currency operations. The Central Bank has actively used this power in recent years, creating a detailed and extensive body of regulations.

Set out below are some of the principal features of the supervisory regime governing banks in Russia:

1. Licensing

A Central Bank license must be obtained for any “banking activity” as defined in the Banking Law. Applicants must be incorporated within the Russian Federation, submit an application for state registration with an attached feasibility report regarding the future business activity of the applicant and submit detailed information on the suitability of its management as well as other information.

Under the Banking Law, a bank can be created in the form of a joint stock company, a limited liability company or a company with additional liability, although in practice the latter form is not used. An application for a banking license may be turned down if the founding documents do not comply with the requirements set out in the Banking Law and the Central Bank’s regulations, the financial or banking records of the founders are unsatisfactory or proposed candidates for executive and head accountant positions do not meet qualification requirements.

2. Mandatory Economic Ratios

The Central Bank is authorized to introduce various capital adequacy and liquidity requirements applicable to banks. Such requirements currently exist in the form of the relevant mandatory economic ratios described in Instruction No. 110-I of the Central Bank “On the Banks’ Mandatory Economic Ratios.” Set out below is the system of the mandatory economic ratios which banks are required to observe on a daily basis and regularly report to the Central Bank. Unless stated otherwise, all ratios described below are calculated on the basis of RAR, as formulated by the applicable Russian laws and Central Bank regulations.

Mandatory Economic Ratios

Description

Central Bank Mandatory

Economic Ratio Requirements

Capital adequacy ratio (N1)

This is intended to limit the risk of a bank’s insolvency and sets requirements for the minimum size of the bank’s capital base necessary to cover credit and market risks. It is formulated as a ratio of a bank’s capital base to its risk-weighted assets.

The risk-weighted assets are calculated under a formula that takes into account the bank’s capital, select categories of assets, reserves created for possible losses of those assets, credit risk on contingent liabilities, credit risk on forward transactions, as well as risks relating to interest rates, securities markets and currencies, in each case separating the systemic and idiosyncratic factors.

Minimum 11% (where a bank’s capital base is below EUR 5 million) and minimum 10% (where a bank’s capital base is equal or more than EUR 5 million).

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Mandatory Economic Ratios	Description	Central Bank Mandatory Economic Ratio Requirements
Instant liquidity ratio (N2)	This ratio is intended to limit the bank’s liquidity risk within one operational day. It is formulated as the minimum ratio of a bank’s highly liquid assets to its liabilities payable on demand.	Minimum 15%

Current liquidity ratio (N3)	This ratio is intended to limit the bank’s liquidity risk within 30 calendar days preceding the date of the calculation of this ratio. It is formulated as the minimum ratio of a bank’s liquid assets to its liabilities payable on demand and liabilities with terms of up to 30 calendar days.	Minimum 50%

Long-term liquidity ratio (N4)	This ratio is intended to limit the bank’s liquidity risk from placement of funds into long-term assets. It is formulated as the maximum ratio of the bank’s credit claims maturing in more than one year to the sum of its capital base and liabilities maturing in more than one year.	Maximum 120%

General liquidity ratio (N5)	This ratio is intended to limit the general liquidity risk of the bank. It is formulated as the minimum ratio of the bank’s liquid assets to its total assets. The Central Bank recommended that its regional units use this ratio to analyze the quality of banks’ liquidity management but not to apply sanctions to banks for breach of this ratio, unless the results of such analysis show deficiencies in the banks’ liquidity or liquidity management.	Minimum 20%

Maximum exposure to a single borrower or a group of related borrowers (N6)	This ratio is intended to limit the credit exposure of a bank to one borrower or a group of related borrowers (defined as persons who belong to the same banking or financial industrial group, are close relatives, or persons who can directly or indirectly materially influence the decisions of legal entity borrowers). It is formulated as the maximum ratio of the aggregate amount of the bank’s various credit claims to a borrower (or a group of related borrowers) to its capital base.	Maximum 25%

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Mandatory Economic Ratios	Description	Central Bank Mandatory Economic Ratio Requirements
Maximum amount of major credit risks (N7)	This ratio is intended to limit the aggregate amount of a bank’s major credit risks (defined as the sum of loans to, and guarantees or sureties in respect of, one client that exceeds 5% of a bank’s capital base). It is formulated as the maximum ratio of the aggregate amount of major credit risks to a bank’s capital base.	Maximum 800%

Maximum amount of loans, bank guarantees and sureties extended by the bank to its participants (shareholders) (N9.1)	This ratio is intended to limit a bank’s credit exposure to the bank’s owners. It is formulated as the maximum ratio of the amount of loans, bank guarantees and sureties extended by the bank to its participants or shareholders, to its capital base.	Maximum 50%

Aggregate amount of exposure to the bank’s insiders (N10.1)	This ratio is intended to limit the aggregate credit exposure of a bank to its insiders (defined as individuals capable of influencing credit decisions). It is formulated as the maximum ratio of the aggregate amount of the bank’s credit claims against its insiders to its capital base.	Maximum 3%

Ratio for the use of the bank’s capital base to acquire shares (participation interests) in other legal entities (N12)	This ratio is intended to limit the aggregate risk of a bank’s investments in shares (participation interests) of other legal entities. It is formulated as the maximum ratio of the bank’s investments in shares (participation interests) of other legal entities to its capital base.	Maximum 25%

In addition, in May 2004 the Central Bank passed Regulation No.112-I, which outlines the mandatory economic ratios for credit organizations that issue bonds secured by mortgages. The new regulation provides that the capital adequacy (N1) ratio for such banks should be at least 14% and establishes new methodologies for calculation of the general liquidity ratio (N5). In addition, the new regulation details the methods of calculation of new ratios that were introduced by the Federal Law “On Mortgage-Backed Securities,” such as the minimum ratio of 10% for loans secured by mortgages to a bank’s capital base (N17), the minimum ratio of 100% for claims relating to principal and interest of loans secured by mortgages to the principal plus interest of issued mortgage-backed bonds (N18) and the maximum ratio of 50% for a bank’s aggregate obligations to the creditors who have priority right to satisfy their claims before holders of mortgage-backed bonds (such as a bank’s depositors) to a bank’s capital base (N19). Banks are required to comply with these special ratios from the time when the decision is taken to issue mortgage-backed bonds until the complete redemption of such bonds.

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The capital base of a bank is calculated on the basis of RAR and defined in Central Bank regulations as the aggregate amount of its capital (including, inter alia, its statutory charter capital, paid-in capital and certain reserve and other internal funds, as well as certain amounts of profit) and additional capital (including, inter alia, revaluation surpluses, subordinated loans and certain preferred shares) decreased by certain mandatory reserves and other amounts.

3. Capital Requirements

The Central Bank sets minimum equity (charter capital) requirements for banks. Under Central Bank Directive No. 1346-U of December 1, 2003, the minimum charter capital requirement is set at EUR5 million for each newly-founded bank. Banks whose charter capital exceeds their capital base, are required to adjust their capital base (or, if impossible, their charter capital) accordingly. The procedure for reducing a banks’ charter capital to adjust the amount of their capital base is established by Central Bank Directive No. 1260-U of March 24, 2003.

4. Reporting Requirements and Auditing Practices

Banks must regularly submit to the Central Bank their balance sheets, together with financial statements, all under RAR, showing their financial position.

Banking groups and consolidated groups (i.e., alliances of legal entities in which one bank, directly or indirectly, controls decisions of the governing bodies of the other banks or legal entities and non-credit organizations within such alliances, respectively) must regularly submit consolidated financial statements to the Central Bank.

The Central Bank may, at any time, conduct full or selective checks of a bank’s financial reports, and may inspect all of its accounting books and records. In addition, annual audits of banks must be carried out by a licensed auditing company under Russian auditing standards applicable to banks.

The Central Bank has established accounting policies for credit organizations and a standard format for the presentation of a bank’s financial statements. A bank’s financial statements and other accounting information must be prepared and submitted in accordance with Central Bank Directive No. 1375-U “On the Rules for the Preparation and Submission of Reports to the Central Bank by Credit Organizations,” dated January 16, 2004.

Starting with periods after January 1, 2004, all credit organizations are required to prepare their accounting reports in accordance with IFRS. Credit organizations will continue the preparation of their financials under RAR until January 1, 2006, when only IFRS financial statements will need to be prepared.

5. Mandatory Reserve Requirements

To cover possible loan losses and currency, interest and financial risks, banks are required to comply with the Central Bank requirements for the formation of various types of mandatory reserves. The Board of Directors of the Central Bank sets particular reserve requirements from time to time. Banks are currently required to post mandatory reserves to be held on non-interest bearing accounts with the Central Bank in the amount equal to 3.5% in respect of funds in rubles and foreign currency attracted from legal entities and individuals and 2% in respect of short-term funds in rubles and foreign currency attracted from non-resident banks.

Prior to July 2004, mandatory reserves of banks to be deposited with the Central Bank were required to be calculated under Central Bank Order No. 02-77 of March 30, 1996. From July 2004, the mandatory reserves are calculated by banks in accordance with Central Bank Regulation No. 255-P of March 29, 2004 (the “New Reserves Regulation”), which changes the methods of reserves calculation but not the amounts set by the Board of Directors of the Central Bank. Both regimes require prompt reporting by banks to the Central Bank and its regional units after the end of each calendar month with calculation of reserves and prompt posting of additional reserves, if necessary. The Central Bank and its regional units have a right to conduct unscheduled audits of credit organizations to check their compliance with the reserves rules. The New Reserves Regulation no longer requires creation of reserves for certain long-term borrowings, instead it requires posting of reserves for short-term obligations to non-resident banks. In addition, credit organizations with good reserves and credit history will be offered a new mechanism that would allow posting of reserves in accordance with certain calculated averages.

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6. Provisions and Loss Allowances

The Central Bank’s rules concerning the creation of allowances for losses for loans extended by banks and other losses (including, inter alia, losses on securities and amounts held in correspondent accounts), requires credit organizations to rank their loans into specified risk categories. From August 2004, the range of loans that must be provided for has been extended to include, among others, rights assigned under contracts, mortgages acquired in the secondary markets, claims relating to purchase of financial assets with deferred payment, rights under repossession contracts (if such repossession contracts are concluded in respect of unlisted securities). In addition, credit organizations are required to classify their loan security into two groups on the basis of its quality. The Central Bank has somewhat simplified the procedures for writing off bad debts, especially minor debts, as compared with the procedures prior to August 2004. Banks must also provide allowances for assets and operations other than loans that comply with the relevant Central Bank rules. Banks must report to the Central Bank on the amounts of created non-loan allowances monthly within ten days following the reporting month.

Mandatory allowances are also created for operations with residents of off-shore areas in the amount of up to the higher of (a) 100% held on the bank’s balance sheet accounts, and (b) average daily turnover with residents of off-shore zones during the last month.

7. Regulation of Currency Exposure

In its Instruction No. 41 of May 22, 1996, the Central Bank established rules regarding exposure of banks to foreign currency and precious metals (collectively, “currency exposure”), as well as controls over such exposure. Currency exposure is calculated with respect to net amounts of balance sheet positions, spot market positions, forward positions, option positions and positions under guarantees. Open currency position is calculated as the sum of all these net amounts. Such exposure is calculated for each currency and each precious metal, and then recalculated into rubles in accordance with the official exchange rates and Central Bank’s prices for precious metals.

The Central Bank established that at the end of each operational day the total amount of all long or short currency positions shall not exceed 20% of a bank’s capital base. At the same time, at the end of each operational day the long or short position with respect to one particular currency or precious metal shall not exceed 10% of the bank’s capital base.

Banks with a capital base not exceeding EUR 6 million are required to report to the Central Bank about their currency exposure once a week with breakdowns for each day. Banks with a capital base equal to or exceeding EUR 6 million are required to report about their currency exposure daily on the day following the reporting day.

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Selected Statistical Information

Average balance sheets and interest rates

The following table shows major assets and liabilities as at December 31, 2003, 2002 and 2001, together with their respective interest amounts and rates earned or paid during 2003, 2002 and 2001 by Bank Zenit.


	Average balance⁽¹⁾			Interest income/expense			Average yield/rate
	2003	2002	2001	2003	2002	2001	2003	2002	2001
	(in RR millions)						(%)
Interest earning assets
Cash and cash equivalents	1,664	967	703	8	25	63	0.5	2.6	9.1
Due from other banks	1,150	1,919	1,273	72	151	137	6.3	7.9	10.8
Trading and available-for-sale securities	2,722	2,414	2,119	332	353	230	12.2	14.6	10.9
Loans and advances to customers⁽²⁾	18,348	9,600	7,969	2,061	1,491	1,257	11.2	15.5	15.8

Total interest earning assets	23,884	14,900	12,064	2,473	2,020	1,687	10.3	13.2	13.9

Cash and cash equivalents	3,227	1,054	647
Mandatory cash balances with the Central Bank	1,397	1,171	967
Other non-interest bearing assets	626	1,415	1,210

Intercompany balances, net	1,465	2,372	1,875

Total assets	30,599	20,912	16,763

Liabilities and shareholders equity
Interest bearing liabilities
Customers deposits	7,019	4,022	2,828	545	512	223	7.8	12.7	7.7
Due to other banks	2,953	3,154	2,407	177	108	151	6.0	3.4	6.3
Other borrowed funds	533	403	450	9	2	10	1.7	0.5	2.3
Securities issued by the bank	6,596	4,596	2,574	582	421	131	8.8	9.2	5.1
Eurobonds issued	2,915	—	—	159	—	—	5.5	—	—

Total interest bearing liabilities	20,016	12,175	8,259	1,473	1,043	515	7.4	8.6	6.3

Demand deposits	4,052	4,097	4,241
Other non-interest bearing liabilities	552	447	908

Intercompany balances, net	1,512

Total liabilities	26,132	16,719	13,408

Shareholders equity	4,467	4,193	3,355
Total liabilities and shareholders’ equity	30,599	20,912	16,763
Net interest income				1,000	977	1,172
Interest spread							2.9	5.0	7.6
Net yield on interest earning assets							4.2	6.6	9.7
Interest earning assets to interest bearing liabilities							120.4	122.4	146.1

(1)	Average balances are based only on the respective year-end data.

(2)	Loans and advances to customers include overdue and non-accruing loans, net of provisions for loan impairment. See “—Provisions for loan impairment” below.

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Interest rate risk

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

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

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

The tables below summarize the effective average period-end interest rates, by major currencies, for monetary financial instruments outstanding as at December 31, 2003, 2002 and 2001. The analysis has been prepared for the various instruments using period end contractual rates.


	2003		2002		2001
	USD	RR	USD	RR	USD	RR
	(in millions)
Assets
Cash and cash equivalents	0.3	0.3	0.7	0.9	3.1	—
Trading securities	6.5	15.3	8.1	12.7	37.1	28.8
Available-for-sale securities	—	6.7	—	8.2	—	—
Due from other banks	1.8	5.4	1.5	13.2	1.9	32.4
Loans and advances to customers	11.8	14.2	14.0	18.3	16.8	20.4

Liabilities
Due to other banks	6.4	5.5	7.0	4.0	3.7	19.8
Customer term accounts	6.0	8.8	5.8	12.0	9.0	12.6
Securities issued by Bank Zenit	7.9	10.1	8.0	10.0	5.6	11.3
Eurobonds issued	9.3	—	—	—	—	—
Other borrowed funds	6.8	—	11.1	—	6.4	—

Trading securities

The following table sets forth the book value of trading securities as at December 31, 2003, 2002 and 2001:


	December 31,
	2003	2002	2001
	(in RR millions)
Ruble denominated securities
Corporate bonds	656	334	863
Promissory notes	558	273	411
Municipal bonds	67	158	296
Corporate shares	61	19	1
Federal loan bonds (OFZ)	—	3	—
U.S. dollar and other foreign currency denominated securities
Corporate Eurobonds	713	521	341
Russian Federation Eurobonds	197	76	—
Vnesheconombank (“VEB”) 3% coupon bonds	50	15	64
U.S. dollar-denominated securities sold under repurchase agreements
Russian Federation Eurobonds	138	—	—
VEB 3% coupon bonds	—	307	705

Total trading securities	2,440	1,706	2,681

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Corporate bonds held at December 31, 2003 consist of ruble-denominated bonds issued by large Russian companies engaged primarily in the telecommunications, food manufacturing and trading, finance and investment and chemical industries and maturing from January 2005 to June 2009. The annual coupon rates on these securities range from 8.5% to 21.0%, and yields to maturity from 9.9% to 24.9%.

Promissory notes held at December 31, 2003 are ruble-denominated promissory notes of major Russian companies engaged primarily in energy and banking purchased at a discount to nominal value and maturing from January 2004 to April 2005. Average yield to maturity on these promissory notes is 15.8%.

Municipal bonds held at December 31, 2003 are ruble-denominated bonds issued by the Moscow government and Krasnoyarsk Territory administration. Bank Zenit’s portfolio of municipal bonds matures from November 2004 to May 2007. The annual coupon rate on these bonds is 10.0-10.3%, and yield to maturity is 5.0-12.54%.

Corporate shares noted above include quoted equity shares of Gazprom and Sberbank.

Corporate Eurobonds held at December 31, 2003 are U.S. dollar-denominated and other currency denominated securities issued by Russian and Kazakh companies and banks and are freely tradable internationally. The annual coupon rates on the corporate

Eurobonds vary from 7.3% to 10.9%. The corporate Eurobonds mature from February 2004 to March 2013, and the average yields to maturity vary from 3.8% to 8.7%.

VEB bonds held at December 31, 2003 are U.S. dollar-denominated securities that are commonly referred to as “MinFin bonds.” The bonds are purchased at a discount to nominal value and carry an annual coupon of 3.0%. The bonds mature from November 2007 to May 2011, and have a yield to maturity of 4.6-6.0%.

Russian Federation Eurobonds held at December 31, 2003 are U.S. dollar-denominated securities. These bonds are purchased at a discount to nominal value and carry an annual coupon of 5.0%. The bonds mature in March 2030, and have a yield to maturity of 6.7%.

Since 2001, Bank Zenit has been involved in underwriting corporate bond issues. Since 2002, Bank Zenit has acted as a lead manager or an underwriter in a number of domestic bond issuances by leading Russian companies, as well as in municipal bond issuances. In addition to Russian bond issuances, Bank Zenit participates in the underwriting of Eurobond issuances and has participated in a lending syndicate for one major client. In aggregate Bank Zenit participated in domestic bond issuances of RR47,660 and RR72,250 in 2003 and 2004, respectively, and Eurobond issuances of U.S.$890 million and U.S.$1,525 million in 2003 and 2004, respectively.

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

As at December 31, 2004 there were no holdings of securities of an individual issuer that exceeded 10% of Bank Zenit’s shareholders’ equity.

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Available-for-sale securities

The following table summarizes the book value of available-for-sale securities as at December 31, 2003, 2002 and 2001:


	December 31,
	2003	2002	2001
	(in RR millions)
Ruble-denominated securities
Promissory notes	275	532	—
Corporate shares	7	727	16
Corporate bonds	—	50	—

Total available-for-sale securities	282	1,309	16

Corporate shares held at December 31, 2003 include unquoted shares of Russian companies owned by Bank Zenit through other companies that hold the legal title for those shares.

Loans and advances to customers

Bank Zenit’s loans and advances to customers as at December 31, 2003, 2002 and 2001 are as follows:


	December 31,
	2003		2002		2001
	(in RR millions)
Current loans	18,595		11,203		8,986
Overdue loans ⁽¹⁾	465		623		396
Less: Provision for bad and doubtful debts	(712	)	(947	)	(1,061	)

Total loans and advances to customers	18,348		10,879		8,321

(1)	Loans are classified as overdue when principal repayments are past their contractual due date.

Analysis of loans to customers by type of customer

Economic sector risk concentrations within the customer loan portfolio as at December 31, 2003, 2002 and 2001 are summarized in the table below.


	December 31,
	2003		2002		2001
	Amount	% of total customers loan portfolio	Amount	% of total customers loan portfolio	Amount	% of total customers loan portfolio
	(in RR millions)
Trade, retail and food	9,076	47	5,731	49	4,681	50
Manufacturing	3,268	17	3,108	26	848	9
Agricultural	1,512	8	715	6	592	7
Finance	2,420	13	702	6	951	10
Oil and gas	1,345	8	328	3	1,104	12
Individuals	242	1	133	1	115	1
Other	1,197	6	1,108	9	1,091	11

Total loans and advances to customers (aggregate amount)	19,060	100	11,825	100	9,382	100

Lending concentrations

As at December 31, 2003, our banking operations had seven borrowers with aggregated loan amounts above RR450 million. The aggregate amount of these loans was RR3,992 million or 21% of the loan portfolio.

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Analysis of loans to customers by maturity and geography

The following table summarizes loans and advances to customers at December 31, 2003, by maturity.


	Demand and less than 1 month	From 1 to 6 months	From 6 to 12 months	More than 1 year	Overdue	Total
			(in RR millions)
Loans and advances to customers (net)	1,812	7,224	3,215	5,849	248	18,348

As at December 31, 2003, the majority of loans and advances to customers have been issued to customers located in Russia, except for RR739 million of loans to foreign borrowers.

Provisions for loan impairment

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

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

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

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

Movements in loan impairment provisions. The following table shows movements in loan impairment provisions for each of the three years ended December 31, 2003.


	Year Ended December 31,
	2003		2002		2001
	(in RR millions)
Loan impairment provision at January 1	947		1,061		911
Charge for loan impairment during the year	(235	)	25		325
Effect of inflation	—		(139	)	(175	)
Loan impairment provision at December 31	712		947		1,061

In addition, a further RR1 million (2002: RR4 million) of loan impairment provisions is held in respect of amounts due from banks.

Summary of loan impairment provisions by economic sector. The following table summarizes loan impairment provisions on loans to customers by economic sector as at December 31, 2003, 2002 and 2001.

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	Year Ended December 31,
	2003		2002		2001
	Amount	% of total loan impairment provision	Amount	% of total loan impairment provision	Amount	% of total loan impairment provision
	(in RR millions)		(in RR millions)		(in RR millions)
Trade, retail and food	407	58	488	52	470	44
Agricultural	58	8	104	11	289	28
Oil and gas	37	4	101	11	78	8
Manufacturing	104	15	102	11	67	6
Finance	37	5	20	2	54	4
Individuals	14	2	—	—	13	1
Other	55	8	132	14	90	9

Total loan impairment provisions	712	100	947	100	1,061	100

Funding

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

Customer Accounts

The following table summarizes customer deposit accounts as at December 31, 2003, 2002 and 2001.


	Year Ended December 31,
	2003	2002	2001
	(in RR millions)
State and public organizations
Current/settlement accounts	148	117	525
Term deposits	33	—	60
Other legal entities
Current/settlement accounts	3,464	3,052	3,785
Term deposits	4,152	3,178	2,057
Individuals
Current/demand accounts	439	383	332
Term deposits	2,835	1,921	828

Total customer accounts	11,071	8,651	7,587

Other borrowed funds

The following table summarizes borrowed funds by type as at December 31, 2003, 2002 and 2001.


	As of December 31,
	2003	2002	2001
	(in RR millions)
Syndicated loan from non-residents	483	—	694
Term borrowings from shareholders	50	54	59

Total other borrowed funds	533	54	753

In June 2003, Bank Zenit entered into a credit facility agreement with WestLB AG (“WestLB”) in the amount of U.S.$125 million, bearing interest at 9.25%, payable semi-annually. Simultaneously, WestLB issued U.S.$125

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million of 9.25% notes due in June 2006. WestLB loaned the proceeds from this issuance to Bank Zenit under the credit facility agreement. Payments made by Bank Zenit under the credit facility agreement fund WestLB’s payment obligations under the notes. As part of this series of transactions, Bank Zenit has guaranteed the obligations of WestLB under the notes.

Derivatives

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

The table below includes contracts with a maturity date subsequent to December 31, 2003. These contracts were entered into in December 2003 and are short term in nature, except for contracts with precious metals, which have a longer-term nature.


	Domestic					Foreign
	Principal or agreed amount		Unrealized Loss		Unrealized Gain	Principal or agreed amount		Unrealized Loss		Unrealized Gain
Deliverable forwards
Precious metals
sale of precious metals	—		—		—	(180	)	(1	)	—
Foreign currency
purchase of foreign currency	—		—		—	257		—		1
Futures
Foreign currency
sale of foreign currency	(206	)	—		—	—		—		—
Spot
Foreign currency
sale of foreign currency	(71	)	(1	)	—	—		—		—
Securities
purchase of securities	14		—		—	—		—		—

Total	(263	)	(1	)	—	77		(1	)	1

The unrealized gain/loss in the table above reflects the fair value adjustment of outstanding derivatives as at December 31, 2003.

The table below includes contracts with a maturity date subsequent to December 31, 2004. These contracts were entered into in December 2004 and mature in the first half of 2005.


	Domestic				Foreign
	Principal or agreed amount	Unrealized Loss		Unrealized Gain	Principal or agreed amount	Unrealized Loss		Unrealized Gain
Deliverable forwards
Precious metals
sale of precious metals	—	—		—	1.33	—		12
Securities
sale of securities	—	—		—	205	—		1
purchase of securities	—	—		—	270	(1	)	—
Futures Securities
sale of securities	812	—		—	—	—		—
purchase of securities	286	—		—	—	—		—
Options
Securities
sale of call options	765	(12	)	—	—	—		—
sale of put options	7.313	—		—	—	—		—
purchase of call options	5.246	—		7	—	—		—
purchase of put options	5.349	421			—	—		—

Total	19.771	(12	)	428	1.814	(1	)	13

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Competition

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.

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