yukos annual report 2002

1

2

3

4

5

6

7

8

9

10

11

12

12

34

5

6

7

8

9

10

11

12

13

14

15

16

page

40

.D

ecem

ber 3

1, 2

00

2YUKOSU.S. GAAPConsolidatedFinancialStatements

U.S. GAAP Consolidated Financial Statements p. 42

Report of Independent Accountants p. 41

Table of Contents

Management’s Discussion and Analysis p. 73

Shareholder Information p. 96

2

00

2

To the Board of Directors and Shareholders of YUKOS Oil Company

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cashflows, and of changes in shareholders’ equity present fairly, in all material respects, the financial position of YUKOS OilCompany and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2002, in conformity with accounting principles generally acceptedin the United States of America. These financial statements are the responsibility of the Company’s management; ourresponsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of thesestatements in accordance with auditing standards generally accepted in the United States of America, which require that weplan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material mis-statement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financialstatements, assessing the accounting principles used and significant estimates made by management, and evaluating theoverall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Moscow, Russian FederationMay 8, 2003

report of independent accountants

2

00

2YUKOS Oil CompanyAnnual Report 2002

(Expressed in millions of U.S. Dollars, except as indicated)

December 31, Notes 2002 2001

AssetsCash and cash equivalents 4 982 684Cash and cash equivalents deposited with equity investees 4, 16 665 725Marketable securities and other short-term investments 5 2,348 2,036Accounts and notes receivable, net 7 2,446 1,906Inventories 8 541 390Current deferred income tax asset and other current assets 14 250 169Total current assets 7,232 5,910Equity investees and long-term investments 9, 10 446 204Property, plant and equipment, net 11 6,116 3,763Noncurrent deferred income tax asset 14 107 71Other long-term assets 493 554Total assets 14,394 10,502

Liabilities and Shareholders’ EquityShort-term debt and current portion of long-term debt 12 121 109Trade accounts and notes payable 502 294Other accounts payable and accrued liabilities 13 664 319Taxes payable 14 392 512Current deferred income tax liability 14 25 30Total current liabilities 1,704 1,264Long-term debt 12 378 7Noncurrent deferred income tax liability 14 1,121 669Other long-term liabilities 320 317Total liabilities 3,523 2,257Minority interest 316 182Ordinary shares (authorized and issued at December 31, 2002

and 2001 – 2,237 million shares; nominal value – RR 0.004 per share) 9 9Additional paid in capital 934 924Retained earnings 9,599 7,214Accumulated other comprehensive income (net of income tax expense of

USD 6 and of USD 1 at December 31, 2002 and 2001, respectively) 117 26Ordinary shares held in treasury, at cost (December 31, 2002 – 81 million shares;

December 31, 2001 – 85 million shares) (104) (110)Total shareholders’ equity 10,555 8,063Commitments and contingent liabilities 19 – –Total liabilities and shareholders’ equity 14,394 10,502

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

YUKOS Oil Company consolidated balance sheets

2

00

2


Year ended December 31, Notes 2002 2001 2000

Sales and other operating revenues (including excise and fuel sales tax of USD 459, USD 476 and USD 245 for the years ended December 31, 2002, 2001 and 2000, respectively) 20 11,373 9,461 9,032

Operating costs and other deductionsCrude oil and petroleum products purchased 340 481 662Operating expenses 1,479 1,182 872Distribution expenses 1,514 1,048 697Selling, general and administrative expenses 835 671 562Depreciation, depletion and amortization 459 270 218Taxes other than income tax 14 3,087 2,075 1,246Write-offs of property and investments 39 48 52Goodwill impairment 50 – –Exploration expenses 87 52 35Total operating costs and other deductions 7,890 5,827 4,344

Other income (expenses)Realized gains on marketable securities, net 5 46 128 165Income from equity affiliates 9 29 7 15Other income, net 101 3 67Interest income 5 333 309 132Interest expense (64) (45) (160)Exchange gain (loss), net (118) (170) 43Total other income, net 327 232 262Income before income tax and minority interest 3,810 3,866 4,950

Income taxCurrent income tax expense 490 598 612Deferred income tax expense 256 104 595Total income tax expense 14 746 702 1,207Income before minority interest 3,064 3,164 3,743Minority interest (6) (8) (19)Net income 3,058 3,156 3,724

Earnings per share (USD per share)

Basic 1.42 1.47 1.68Diluted 1.41 1.47 1.68

Weighted-average shares outstanding (Millions of shares) 17Basic 2,155 2,142 2,212Diluted 2,163 2,145 2,212


YUKOS Oil Company consolidated statements of income

2

00


(Expressed in millions of U.S. Dollars)

Year ended December 31, 2002 2001 2000

Operating activitiesNet income 3,058 3,156 3,724Adjustments to reconcile net income to net cash provided by operating activities:

Deferred income tax expense 256 104 595Depreciation, depletion and amortization 459 270 218Realized gains on marketable securities (46) (128) (165)Write-offs of property and investments 39 48 52Reversal of provision for doubtful debts (20) (40) (35)Minority interest 6 8 19Income from equity affiliates (29) (7) (15)Effect of foreign exchange on balance sheet items 118 170 (43)Goodwill impairment 50 – –Other 84 (5) (41)

Changes in operational working capital, excluding cash and debt:Accounts receivable (731) (350) (768)Inventories (25) (63) (105)Other current assets (91) (62) 8Trade accounts and notes payable 46 94 (68)Other accounts payable and accrued liabilities (2) 33 (206)Taxes payable (205) (114) 140

Net cash provided by operating activities 2,967 3,114 3,310

Investing activitiesNet additions to property, plant and equipment (1,263) (954) (589)Net purchases of long-term investments, including additional shares of subsidiaries and

advances to investment dealers, net of cash acquired (1,032) (653) (368)Purchases of available-for-sale marketable securities (2,313) (4,746) (1,417)Proceeds from sales and maturity of available-for-sale marketable securities 2,265 4,068 908Loans issued (2,273) (1,035) –Repayment of loans issued 2,247 459 –Other 20 (101) (167)Net cash used for investing activities (2,349) (2,962) (1,633)

Financing activitiesNet proceeds from (repayments of) short-term debt 3 (50) 40Net repayments of long-term debt (36) (256) (399)Net sales of treasury shares 13 67 9Dividends paid (280) (473) (103)Return of proceeds from share emission (60) – –Other – 73 236Net cash (used for) financing activities (360) (639) (217)Effect of foreign exchange on cash balances (20) (43) (19)Net change in cash and cash equivalents 238 (530) 1,441Cash and cash equivalents at beginning of year 1,409 1,939 498Cash and cash equivalents at end of year 1,647 1,409 1,939

Supplemental cash flow information:Cash paid for interest 18 24 60Cash paid for income taxes 445 489 447


YUKOS Oil Company consolidated statements of cash flows

2

00

2


Number of Accumulated

ordinary Additional other Ordinary Total

shares issued Ordinary paid in Retained comprehensive shares held shareholders’

(Millions) shares capital earnings income in treasury equity

Balance at December 31, 1999 2,237 9 854 917 – (1) 1,779Net income – – – 3,724 – – 3,724Change in net unrealized gains

on securities – – – – 34 – 34Total comprehensive income 3,758Purchases of treasury shares – – – – – (171) (171)Sales of treasury shares – – 37 – – 28 65Dividends declared – – – (205) – – (205)

Balance at December 31, 2000 2,237 9 891 4,436 34 (144) 5,226Net income – – – 3,156 – – 3,156Change in net unrealized gains

on securities – – – – (8) – (8)Total comprehensive income 3,148Purchases of treasury shares – – – – – (1) (1)Sales of treasury shares – – 32 – – 35 67Stock-based compensation plans – – 1 – – – 1Dividends declared – – – (378) – – (378)

Balance at December 31, 2001 2,237 9 924 7,214 26 (110) 8,063Net income – – – 3,058 – – 3,058Change in net unrealized gains

on securities – – – – 84 – 84Foreign currency

translation adjustment – – – – 7 – 7Total comprehensive income 3,149Sales of treasury shares – – 7 – – 6 13Stock-based compensation plans – – 3 – – – 3Dividends declared – – – (673) – – (673)Balance at December 31, 2002 2,237 9 934 9,599 117 (104) 10,555


YUKOS Oil Company consolidated statements of changes in shareholders’ equity

2

00


Note 1: OrganizationYUKOS Oil Company (or “OAO NK YUKOS”) was incor-porated as an open joint stock company on April 15, 1993 in accordance with Presidential Decree No. 1403 onPrivatization and Restructuring of Enterprises and Cor-porations into Joint Stock Companies.

YUKOS Oil Company and its subsidiaries and associates(the “Company”) are a vertically integrated group of com-panies. The Company, which is incorporated in the RussianFederation and includes domestic and foreign subsidiariesand associates, engages in the exploration, developmentand production of crude oil and natural gas, refining crudeoil into finished petroleum products, and marketing anddistributing crude oil, natural gas and petroleum products.

The Company is controlled by Group MENATEP Limited(“Group MENATEP”) through two wholly owned sub-sidiary holding companies, YUKOS Universal Limited(“YUKOS Universal”) and Hulley Enterprises Limited,which together owned a majority interest in the Company’soutstanding shares at December 31, 2002. Three seniormanagers of the Company, including the Company’sChairman of the Executive Committee of the Board ofDirectors, are principal shareholders of Group MENATEP(the Company’s Chairman of the Executive Committee ofthe Board of Directors had a majority beneficial interest inGroup MENATEP at December 31, 2002). Group MENATEPalso directly or indirectly controls the Company’s twoequity investee banks, Trust and Investment Bank (Note 9)and Bank MENATEP Saint Petersburg (Note 9), as well as anumber of other entities. AKB Bank MENATEP (“BankMENATEP”), which declared bankruptcy in 1999 and wassubsequently liquidated in 2001, was also related to theCompany by virtue of common shareholdings.

Note 2: Basis of PresentationThe consolidated financial statements are presented inaccordance with accounting principles generally acceptedin the United States of America (“U.S. GAAP”).

Use of estimates. The preparation of consolidated financialstatements in conformity with U.S. GAAP requires esti-mates and assumptions that affect the reported amountsof assets, liabilities, revenues and expenses, and the disclo-sure of contingent assets and liabilities. Actual amountsmay differ from such estimates.

Reporting and functional currencies. The Company’sreporting currency is the U.S. Dollar. As the economy of theRussian Federation was considered highly inflationarythrough December 31, 2002, transactions and balances ofdomestic operations not already measured in U.S. Dollarswere remeasured as if the functional currency were theU.S. Dollar, in accordance with the relevant provisions ofStatement of Financial Accounting Standards No. 52,Foreign Currency Translation. The U.S. Dollar is also thefunctional currency of substantially all of the Company’sinternational operations. Beginning January 1, 2003, theeconomy of the Russian Federation ceased to be consid-ered highly inflationary. There will be no effect from exitinghyperinflation for the Company’s principal Russian oil andgas operations, as the U.S. Dollar is the functional currencyfor those subsidiaries. The Russian Ruble is the functionalcurrency for all other Russian operations.

Currency exchange rates. The following summarizes theend of period exchange rates of the Russian Ruble (“RR”)to the U.S. Dollar (“USD”) for the dates presented:

Russian Rubles

2002 2001 2000

March 31 31.12 28.74 28.46June 30 31.45 29.07 28.07September 30 31.64 29.39 27.75December 31 31.78 30.14 28.16

YUKOS Oil Company notes to consolidated financial statements(Expressed in U.S. Dollars (tabular amounts in millions))

2

00

2

Notes to ConsolidatedFinancial Statements(Expressed in U.S. Dollars (tabular amounts in millions))

Prior to 1992, RR/USD exchange rates were set by the stateand were not determined under free market conditions.Consequently, RR/USD exchange rates for those periodsmay differ from rates that might have prevailed had freemarket conditions existed. For purposes of remeasur-ing nonmonetary assets acquired prior to 1992 intoU.S. Dollars, the Company used the historic officialexchange rate of RR 110 to USD 1.00 that existed atJanuary 1, 1992.

A redenomination of the Russian Ruble was enacted on January 1, 1998. This redenomination resulted in theexchange of the then existing national currency with the new Russian Ruble at the ratio of 1,000 old RussianRubles at December 31, 1997 to one new Russian Ruble atJanuary 1, 1998.

Devaluation, inflation, and currency restrictions and con-trols. The Russian Ruble has historically been devaluingagainst the U.S. Dollar due to significant inflation in theRussian Federation as well as other factors. During 2002,for instance, the Russian Ruble devalued by 5.7 percentagainst the U.S. Dollar (2001 – 7.2 percent; 2000 – 4.3 per-cent) while official Russian Ruble inflation was 15.1 percent(2001 – 18.8 percent; 2000 – 20.2 percent). Additionally,significant currency restrictions and controls exist relatedto converting Russian Rubles into other currencies. Atpresent, the Russian Ruble is not convertible outside of theCommonwealth of Independent States and, furthermore,all transactions within the Russian Federation must be settled in Russian Rubles. At December 31, 2002, theCompany was required to sell 50 percent of its foreign cur-rency receipts within the Russian Federation to authorizedbanks for Russian Rubles; from March 1999 throughAugust 2001, the related requirement was 75 percent. Suchamounts are subject to certain deductions depending ondebt payments on certain hard currency denominated bor-rowing agreements that were entered into by the Companyprior to March 1999.

Future movements in the exchange rate between theRussian Ruble and the U.S. Dollar will affect the carryingvalues of the Company’s Russian Ruble-denominated

monetary assets and liabilities. Such movements may alsoaffect the Company’s ability to realize nonmonetary assetsrepresented in U.S. Dollars in these consolidated financialstatements. Accordingly, the remeasurement of underlyingRussian Ruble amounts to U.S. Dollars in these consoli-dated financial statements should not be construed as arepresentation that such Russian Ruble amounts havebeen, could be, or will in the future be converted into U.S. Dollars at the exchange rates shown or at any otherexchange rate.

Reclassifications. Certain reclassifications have been madeto previously reported balances to conform to the currentyear’s presentation; such reclassifications have no effecton net income or shareholders’ equity.

Note 3: Summary of Significant Accounting PoliciesPrinciples of consolidation and long-term investments. Theconsolidated financial statements include the operationsof all entities in which the Company directly or indirectlycontrols more than 50 percent of the voting stock, exceptwhere conditions exist such that the Company is not ableto exercise control of the entities’ operations. Significantjoint ventures and investments in which the Company hasvoting ownership interests between 20 and 50 percent orotherwise exercises significant influence are accounted forusing the equity method and adjusted for estimatedimpairment. Long-term investments in other unquotedcompanies are accounted for at cost and adjusted for esti-mated impairment.

Cash equivalents. Cash equivalents include all marketablesecurities with original maturities of three months or less.

Marketable securities. Substantially all marketable securi-ties with original maturities greater than three months areclassified as available-for-sale. Such securities are reportedat fair value. Realized gains and losses are included in theconsolidated statements of income. Unrealized gains andlosses, net of related income taxes, are included as a sepa-rate component of shareholders’ equity and changestherein are included in other comprehensive income.

2

00


Other short-term investments. Other short-term invest-ments represent loans receivable from Russian corpora-tions with maturities of less than one year. Such amountsare recorded at their respective face values, less any valua-tion allowances, as appropriate.

Accounts receivable. Accounts receivable are presented attheir respective face values, less any valuation allowances, asappropriate, and include value-added taxes which are payableto tax authorities upon collection of such receivables.

Inventories. Inventories are recorded at the lower of aver-age cost and net realizable value. Costs capitalized toinventory include, but are not limited to, direct and indirectlabor costs, utilities and production taxes.

Property, plant and equipment. The Company follows thesuccessful efforts method of accounting for its oil and gasproperties, whereby property acquisitions, successfulexploratory wells, all development costs (including devel-opment dry holes), and support equipment and facilitiesare capitalized. Unsuccessful exploratory wells are chargedto expense at the time the wells or other exploration activi-ties are determined to be nonproductive. Production costs,overheads and all exploration costs other than exploratorydrilling are charged to expense as incurred. Acquisitioncosts of unproved properties are evaluated periodically andany impairment assessed is charged to expense.

Depreciation, depletion and amortization of capitalizedcosts of proved oil and gas properties is calculated usingthe units-of-production method for each field based uponproved reserves for property acquisitions and proveddeveloped reserves for exploration and development costs.Estimated costs of dismantling oil and gas productionfacilities, including abandonment and site restorationcosts, are reserved using the units-of-production methodand are included as a component of depreciation, deple-tion and amortization.

Gains or losses are not recognized for normal retirementsof oil and gas properties subject to composite deprecia-tion, depletion and amortization. Gains or losses fromother retirements or sales are included in the determina-tion of net income.

Depreciation of assets not directly associated with produc-tion is calculated on a straight-line basis as follows:

Buildings and constructions 5–33 yearsMachinery and equipment 5–15 yearsComputers and telecommunications equipment 2–5 years

Long-lived assets, including proved oil and gas properties,are assessed for possible impairment in accordance withStatement of Financial Accounting Standards No. 144,Accounting for the Impairment or Disposal of Long-LivedAssets, which requires long-lived assets with recorded valuesthat are not expected to be recovered through undiscountedfuture cash flows to be written down to current fair value.

Maintenance and repairs and minor renewals are expensedas incurred. Major renewals and improvements are capital-ized and the assets replaced are retired.

In addition to its production assets, the Company alsomaintains and constructs assets for the social use of thelocal community (“social assets”). Such assets are capital-ized only to the extent that they are expected to result infuture economic benefits to the Company. Maintenanceand repairs of social assets are expensed as incurred.

Environmental liabilities. Liabilities for environmentalremediation are recorded when it is probable that obliga-tions have been incurred and the amounts can be reason-ably estimated.

Pension and post-employment benefits. The Company’smandatory contributions to the government pensionscheme are expensed when incurred. Costs associated withdiscretionary pension and other post-employment benefitsare expensed over the vesting periods associated with cov-ered employees or expensed immediately if no servicerequirement exists.

Revenue recognition. Revenues from the production andsale of crude oil and petroleum products are recognizedwhen deliveries to final customers are made, title passes tothe customer, and collectibility is reasonably assured.

2

00

2


Stock-based compensation. The Company has elected toaccount for stock-based compensation awards to employ-ees and third parties in accordance with Statement ofFinancial Accounting Standards No. 123, Accounting forStock-Based Compensation (“SFAS 123”). Under SFAS 123,the Company recognizes compensation expense equal tothe fair value of the award on the date of grant for fixedawards. For conditional stock awards, the Company followsSFAS 123 provisions for accounting for plans with perfor-mance conditions and records compensation cost over theperiod from grant date to vesting based upon the fair valueof the awards at grant date.

Deferred income tax. Deferred income tax assets and liabil-ities are recognized for future tax consequences attributa-ble to differences between the financial statement carryingamounts of existing assets and liabilities and their respec-tive tax bases. Included in this calculation are deferredincome taxes for the unremitted earnings of equity affili-ates and foreign subsidiaries on basis differences betweenthe relevant parent company financial statement carryingamounts and the respective tax bases of its investments insubsidiaries and equity affiliates. Management periodicallyassesses possible methods of remitting the earnings to theparent and adjusts this liability to the amount calculated atenacted rates corresponding to the expected method ofdistribution. Management believes that current tax legisla-tion provides a means by which unremitted earnings fromits domestic subsidiaries can be transferred to the parentcompany without tax. Accordingly, the Company does notprovide for taxes on unremitted earnings from its domesticsubsidiaries. Statement of Financial Accounting StandardsNo. 109, Accounting for Income Taxes, prohibits recognitionof a deferred tax liability or asset for differences related toassets and liabilities that, under SFAS 52, are remeasuredfrom the local currency into the functional currency usinghistorical exchange rates and that result from (1) changesin exchange rates or (2) indexing for tax purposes. De-ferred income tax assets and liabilities are measured usingenacted tax rates in the years in which temporary differ-ences are expected to reverse. Valuation allowances areprovided for deferred income tax assets when manage-ment believes that it is more likely than not that the assetswill not be realized.

Basic and diluted earnings per share. Basic earnings pershare is calculated by dividing net income by the weighted-average number of ordinary shares outstanding during the year. Diluted earnings per share reflects the potential dilution that would occur if stock compensation awardsand third-party options were exercised using the treasurystock method.

Comprehensive income. Comprehensive income includesall changes in equity (net assets) during the year fromnonowner sources and is detailed in the consolidatedstatements of changes in shareholders’ equity.

Sale and repurchase transactions with financial assets. Inaccordance with Statement of Financial Accounting StandardsNo. 140, Accounting for Transfers and Servicing of FinancialAssets, the Company accounts for qualifying sale and repur-chase transactions as secured borrowings. The Companydoes not have a policy requiring collateral on sale andrepurchase agreements involving financial assets.

Accounting changes. From January 1, 2002, the Companyadopted Statement of Financial Accounting StandardsNo. 142, Goodwill and Other Intangible Assets (“SFAS 142”).This standard requires that goodwill and intangible assetswith indefinite lives be no longer amortized and that suchgoodwill and intangible assets be tested for impairmentperiodically, but not less frequently than annually.

Recent accounting pronouncements. In June 2001, theFinancial Accounting Standards Board (“FASB”) issuedStatement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations (“SFAS 143”).This new statement is effective for fiscal years beginningafter June 15, 2002. The Company will adopt SFAS 143effective January 1, 2003. SFAS 143 addresses the account-ing and reporting for obligations associated with the retire-ment of tangible long-lived assets and the associated assetretirement costs. The adoption of this statement primarilyaffects the Company’s accounting for oil and gas produc-ing assets. SFAS 143 differs in several significant respectsfrom current accounting under Statement of FinancialAccounting Standards No. 19, Financial Accounting andReporting by Oil and Gas Producing Companies (“SFAS 19”).Under SFAS 143, the Company will recognize a liability for

2

00


the fair value of an asset retirement obligation in the periodin which it is incurred if a reasonable estimate of fair valuecan be made. If a reasonable estimate of fair value cannotbe made in the period the asset retirement obligation isincurred, the liability is recognized when a reasonable esti-mate of fair value can be made. In periods subsequent toinitial measurement, the Company recognizes period-to-period changes in the liability for an asset retirement obligation resulting from (a) the passage of time and(b) revisions to either the timing or the amount of the orig-inal estimate of undiscounted cash flows. Upon initialrecognition of a liability for an asset retirement obligation,the Company capitalizes an asset retirement cost byincreasing the carrying amount of the related long-livedasset by the same amount as the liability. Management iscurrently completing its assessment of the effect of theadoption of SFAS 143 on the Company.

In November 2002, the FASB issued Interpretation No. 45,Guarantor’s Accounting and Disclosure Requirements forGuarantees, Including Indirect Guarantees of Indebtedness ofOthers (“FIN 45”). FIN 45 requires that, upon issuance ofcertain types of guarantees, a guarantor recognize andaccount for the fair value of the guarantee as a liability. Theinitial recognition and measurement provisions of FIN 45should be applied on a prospective basis for guaranteesissued or modified after December 31, 2002. The disclo-sure requirements of FIN 45 are effective for financial state-ments of both interim and annual periods ending afterDecember 15, 2002, and are included in Note 19 to the con-solidated financial statements.

In January 2003, the FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities (“FIN 46”). FIN 46amended Accounting Research Bulletin No. 51,Consolidated Financial Statements (“ARB 51”), and estab-lished standards for determining under what circum-stances a variable interest entity (“VIE”) should beconsolidated with its primary beneficiary. FIN 46 alsorequires disclosures about VIEs that an entity is notrequired to consolidate but in which it has a significantvariable interest. The consolidation requirements ofFIN 46 apply immediately to VIEs created after January 31,2003. The consolidation requirements apply to older

entities in the first financial year or interim period begin-ning after June 15, 2003. Management does not expect thatadoption of FIN 46 will have a significant impact on thefinancial position or results of operations of the Company.

Note 4: Cash and Cash EquivalentsAt December 31, 2002 and 2001, cash and cash equivalentscomprised the following:

December 31, 2002 2001

U.S. Dollar bank deposits 1,310 925U.S. Dollar bank promissory notes – 15Russian Ruble bank deposits

(RR 10,318 million and RR 13,883 million at December 31, 2002 and 2001, respectively) 325 461

Russian Ruble certificates of deposit (RR 259 million and RR 20 million at December 31, 2002 and 2001, respectively) 8 1

Russian Ruble bank promissory notes (RR 141 million and RR 220 million at December 31, 2002 and 2001, respectively) 4 7

1,647 1,409Less: cash and cash equivalents at Trust and

Investment Bank and Bank MENATEP Saint Petersburg (665) (725)

Total cash and cash equivalents 982 684

The Company’s balances at Trust and Investment Bank(Note 16) and Bank MENATEP Saint Petersburg (Note 16)comprise a substantial portion of the banks’ total assets.At December 31, 2001, the Company’s balances comprised41 percent of Trust and Investment Bank’s total assets and26 percent of Bank MENATEP Saint Petersburg’s totalassets. At December 31, 2002, the Company reduced itsconcentration in Trust and Investment Bank to 26 per-cent of Trust and Investment Bank’s total assets, and theCompany’s balances comprised 30 percent of BankMENATEP Saint Petersburg’s total assets. At December 31,2002, the majority of the assets of Trust and InvestmentBank and Bank MENATEP Saint Petersburg were investedin securities issued by the government of the RussianFederation and in loans to Russian corporations. Becausethe Company’s deposits represent a significant portion ofthe banks’ total assets, the immediate availability of a por-tion of this amount depends upon the banks’ liquidity atany given point in time.

2

00

2


Note 5: Marketable Securities and Other Short-Term Investments

December 31, 2002 2001

Marketable securities 1,752 1,577Other short-term investments 596 459Total marketable securities and other

short-term investments 2,348 2,036

All marketable securities held by the Company are classifiedas available-for-sale. Unrealized gains and losses, net ofrelated income taxes, for available-for-sale securities areincluded as a separate component of shareholders’ equity.Realized gains and losses are included in income on a currentbasis. The Company determines cost on a last-in-first-outbasis. Details of the net carrying amount, gross unrealizedholding gains and losses, and fair value of marketable securi-ties at December 31, 2002 and 2001 are as follows:

Gross Gross

unrealized unrealized

Net carrying holding holding Fair

amount gains losses value

Bonds and other Russian government securities 1,029 113 – 1,142

Corporate debt securities 442 7 – 449Equity securities 167 20 (26) 161Total marketable

securities at December 31, 2002 1,638 140 (26) 1,752

Bonds and other Russian government securities 829 33 – 862

Corporate debt securities 661 5 – 666Equity securities 60 2 (13) 49Total marketable

securities at December 31, 2001 1,550 40 (13) 1,577

At December 31, 2002, marketable debt securities with fairvalues totaling USD 613 million mature during 2003, andwith fair values totaling USD 978 million mature between2004 and 2028.

Gross realized gains and losses on marketable securitiesfor the years ended December 31, 2002, 2001 and 2000were as follows:


Gross realized gains 63 140 168Gross realized losses (17) (12) (3)Net realized gains on

marketable securities 46 128 165

Interest income earned on cash deposits, marketable securities, and from other sources for the years endedDecember 31, 2002, 2001 and 2000 were as follows:


Interest income on marketable securities 180 172 29

Interest income on cash deposits and other interest income 153 137 103

Total interest income 333 309 132

Securities lending. The Company occasionally engages insecurities lending activities to augment its investmentreturns. At December 31, 2001, the Company had outstand-ing short-term unsecured loans of securities with marketvalues of USD 98 million to Trust and Investment Bank.These securities were recorded within marketable securi-ties in the consolidated balance sheet. At December 31,2002, the Company had no outstanding short-term unse-cured loans of securities.

Note 6: Financial InstrumentsFair values. A financial instrument is defined as cash, evi-dence of an ownership interest in an entity, or a contractthat imposes an obligation to deliver or right to receivecash or another financial instrument. The fair values offinancial instruments are determined with reference to var-ious market information and other valuation methods, asconsidered appropriate. However, considerable judgmentis required to interpret market data and to develop the esti-mates of fair value. Accordingly, the estimates presentedherein may differ from the amounts the Company couldreceive in current market exchanges.

2

00


The net carrying values of cash and cash equivalents, othershort-term investments, accounts and notes receivable,accounts and notes payable, taxes payable and accrued lia-bilities approximate their fair values because of the shortmaturities of these instruments.

Marketable securities are carried at their fair values in theconsolidated balance sheets.

Long-term investments are valued at their historical costadjusted for impairment, as appropriate. Managementbelieves that the carrying values of long-term investmentsapproximate their fair values.

The fair value of the Company’s long-term debt, includingthe current portion of long-term debt, was USD 432 mil-lion and USD 91 million, while the carrying value of suchliabilities was USD 436 million and USD 94 million as ofDecember 31, 2002 and 2001, respectively.

The fair value of the Company’s long-term liabilities wasUSD 211 million and USD 218 million, while the carry-ing value of such liabilities was USD 320 million andUSD 317 million as of December 31, 2002 and 2001, respectively.

Credit risks. A significant portion of the Company’saccounts receivable are from domestic customers and for-eign oil companies, and its other short-term investmentsrepresent loans receivable from Russian corporations.Although collection of these amounts could be influencedby economic factors affecting these entities, managementbelieves there is no significant risk of loss to the Companybeyond the provisions already recorded.

The Company has significant amounts of securities held intrust at its equity investee banks (Note 16). Managementbelieves that, under existing depositary agreements,Russian and international law, securities held in trust atsuch banks would not be subject to each bank’s creditorsin the event of bankruptcy.

Concentration risks. As discussed in Note 4, a significantportion of the Company’s cash and cash equivalents areheld by Trust and Investment Bank (Note 16) and BankMENATEP Saint Petersburg (Note 16).

Note 7: Accounts and Notes Receivable, Net

December 31, 2002 2001

Prepaid and recoverable value-added and other taxes 964 821

Trade accounts receivable (net of allowances for doubtful accounts of USD 41 million and USD 50 million at December 31, 2002 and 2001, respectively) 912 461

Advances to suppliers (net of allowances for doubtful accounts of USD 1 million and USD 4 million at December 31, 2002 and 2001, respectively) 300 172

Promissory notes receivable (net of allowances for doubtful accounts of USD nil at both December 31, 2002 and 2001) 23 27

Other receivables (net of allowances for doubtful accounts of USD 11 million and USD 22 million at December 31, 2002 and 2001, respectively) 247 425

Total accounts receivable, net 2,446 1,906

Prepaid and recoverable value-added and other taxesincludes value-added tax from purchases that will berecoverable only when the underlying accounts payablehave been settled. This amount also includes input value-added tax eligible for offset, prepayments of export duties,excise taxes at customs relating to the Company’s revenueson exports from the Russian Federation income, and otherless significant prepaid taxes.

Note 8: Inventories

December 31, 2002 2001

Crude oil and petroleum products 298 167Materials and supplies 243 223Total inventories 541 390

2

00

2


The Company’s ownership interests in Trust and Invest-ment Bank and Bank MENATEP Saint Petersburg didexceed 50 percent during part of 2000. Consequently, theCompany consolidated the banks for this short period oftime. The Company’s ownership interests in the bankswere permanently reduced to below 50 percent during2000 and they continue to be controlled by GroupMENATEP Limited (Note 16).

Losses of USD 12 million from the Company’s equity interest in Mazeikiu Nafta represent its share of the results of operations during the period from June 2002 toSeptember 2002, when the Company held a 26.85 percentinterest in Mazeikiu Nafta. Mazeikiu Nafta’s results begin-ning from the Company’s acquisition of a controlling stakein September 2002 are consolidated in the Company’s con-solidated statements of operations, of cash flows and ofshareholders’ equity.

Note 10: AcquisitionsAcquisition of Sakhaneftegas. Through a series of trans-actions during 2002, the Company purchased a 50.4 percentinterest in OAO NNGK Sakhaneftegas (“Sakhaneftegas”),an oil and gas company operating in Eastern Siberia. Thetotal purchase price of the interest was USD 50 million.

Sakhaneftegas and its subsidiaries hold a number oflicenses for exploration, development and production ofhydrocarbon reserves in Yakutia, Eastern Siberia. Theacquisition of Sakhaneftegas positions the Company forparticipation in future developments in the oil and gasindustry in Eastern Siberia.

The results of operations of Sakhaneftegas were includedin the consolidated statements of income beginningDecember 2002. No pro forma results have been providedas the acquisition does not have a material impact on theCompany’s consolidated financial statements.

Note 9: Equity Investees and Long-Term InvestmentsThe Company has several investment affiliates and joint ventures accounted for using the equity method, and long-terminvestments accounted for at cost. The nature and extent of these investments change over time. Equity investees includethose entities in which the Company has voting ownership interests between 20 and 50 percent or otherwise exercises sig-nificant influence, or entities in which the Company has voting ownership interests of more than 50 percent but does notcontrol the entity. A summary of the impact of equity investees and long-term investments on the consolidated financialstatements is as follows:

Income (loss) from equity

Ownership percentage Net book value affiliates for the year ended

at December 31, at December 31, December 31,

2002 2001 2002 2001 2002 2001 2000

Trust and Investment Bank 37.2 37.2 61 47 14 6 3Bank MENATEP Saint Petersburg 20.5 20.1 31 9 20 1 2Belgorodenergo 25.0 19.9 13 11 – – –Kubanenergo 26.3 19.9 15 12 – – –Tomskenergo 25.9 19.9 27 21 – – –Tambovenergo 25.1 – 7 – – – –Urengoil Inc. (Note 10) 100.0 50.0 – 25 – – –Transpetrol a.s. (Note 10) 49.0 – 77 – 4 – –Rospan (Note 10) 56.0 – 110 – – – –AB Mazeikiu Nafta (Note 10) 53.7 – – – (12) – –Other affiliates and joint ventures 26 9 3 – 10Long-term investments, at cost 79 70 – – –Total 446 204 29 7 15

2

00


Acquisition of stakes in AB Mazeikiu Nafta. In June 2002,the Company purchased a 26.85 percent interest inAB Mazeikiu Nafta (“MN”), a Lithuanian company thatowns a refinery, export terminal and pipeline. The Company’sinvestment included USD 75 million for the purchase of theshares and a USD 75 million loan guaranteed by theLithuanian government to MN to modernize the refinery.In addition, the Company secured an agreement to supply4.8 million metric tons (35 million barrels) of crude oilannually to the refinery for ten years, beginning inJuly 2002. In September 2002, the Company purchased anadditional 26.85 percent interest in MN for USD 85 million.In connection with this additional purchase, the Companyacquired the rights and obligations relating to a secondloan to MN of USD 75 million (also guaranteed by theLithuanian government). In addition to the share purchaseand loans, the Company secured the rights to manage MN.Other acquisition costs related to the purchase of MNtotaled USD 4 million.

The financial position and results of operations of MNwere included in the Company’s consolidated financialstatements beginning September 2002.

The table below sets forth the condensed balance sheet infor-mation of Mazeikiu Nafta at acquisition and at December 31,2002, excluding intercompany balances and following pur-chase accounting adjustments:

At December 31,

At acquisition 2002

(Unaudited)

Cash 135 109Accounts and notes receivable, net 60 91Inventories 67 84Other current assets 5 –Property, plant and equipment and

other long-term assets 699 708Total assets 966 992Accounts payable and accrued liabilities 143 91Short-term borrowings and current

portion of long-term debt 13 27Long-term debt 341 336Other long-term liabilities 41 6Total liabilities 538 460

Acquisition of OAO Arcticgas. In March 2002, theCompany purchased an 88 percent interest in OAOArcticgas (“Arcticgas”), a holder of exploration and devel-opment licenses for a number of gas and condensate fields located in Western Siberia, for USD 251.8 million. InDecember 2002, the Company acquired the remaining12 percent stake in Arcticgas for USD 22.5 million, increas-ing its ownership to 100 percent.

Acquisition of ZAO Rospan International. In 2001 and dur-ing the first half of 2002, the Company acquired, throughintermediaries, a 100 percent interest in ZAO RospanInternational (“Rospan”), a domestic natural gas producerwith assets in Western Siberia for USD 101 million. Furthertoward strengthening its position in the bankruptcyprocess, the Company also directly purchased an addi-tional 49 million of Rospan’s outstanding liabilities. TheUSD 21 million excess of purchase cost over the fair valueof the liabilities acquired was included in the Company’scost of investment in Rospan. In May 2002, 44 percent ofthe shares of Rospan were sold to Tyumen Oil Company(“TNK”) for USD 44 million. In June 2002, the Companypaid USD 20 million to terminate a purchase optiongranted at acquisition over a portion of its interest inRospan’s shares. In August 2002, the Company enteredinto a shareholders agreement with TNK whereby it wasagreed that the Company and TNK would jointly controlRospan. In December 2002, the Company and TNK agreedthat TNK would manage Rospan and, accordingly, theCompany accounts for its investment in Rospan under theequity method. Other acquisition costs related to the pur-chase of Rospan totaled USD 12 million.

Acquisition of ZAO Urengoil Inc. In two transactions inDecember 2001 and May 2002, the Company acquired a100 percent interest in ZAO Urengoil Inc., a domestic natu-ral gas producer, for USD 75 million. The shares acquired atDecember 31, 2001 are included within equity investeesand long-term investments at cost, as the Company did nothave greater than 50 percent ownership of the votingshares at that date.

The Company’s acquisitions of Arcticgas, Rospan and ZAOUrengoil were performed in accordance with its long-termstrategy to enhance its position in the Russian gas market.

2

00

2


Acquisition of additional stake in Eastern Oil Company.During 2002, the Company acquired an additional 42.3 per-cent in its subsidiary, Eastern Oil Company, through a com-bination of purchases in a public tender and on the openmarket, effectively increasing its ownership to 97.0 percentat December 31, 2002. Total acquisition costs for the pur-chases were USD 256 million. Subsequent to December 31,2002, Eastern Oil Company approved a plan to merge itsassets into the parent company. Under the plan, theCompany shall acquire the remaining 3.0 percent of out-standing shares.

Acquisition of Transpetrol a.s. In April 2002, the Companyacquired a 49 percent interest in Transpetrol a.s.(“Transpetrol”), a Slovakian state-owned oil pipeline opera-tor, for USD 74 million. The Company’s investment inTranspetrol is accounted for under the equity method.

Acquisition of Kvaerner businesses. In November 2001, theCompany acquired the Hydrocarbon and Process Technologydivisions of Kvaerner. Cash paid upon acquisition wasUSD 100 million plus the assumption of certain outstand-ing liabilities of the businesses. Subsequent to the acquisi-tion of the Hydrocarbon and Process Technology divisions,the Company renamed the businesses to the internation-ally recognized brands of John Brown HydrocarbonsLimited and Davy Process Technology Limited, respec-tively. The entities are incorporated in the United Kingdom.

Prior to this acquisition, the Company had substantial contractual relationships with the divisions of Kvaernermentioned above and, accordingly, had an interest in pre-serving the level of service it had been receiving from thosedivisions, despite Kvaerner’s financial uncertainties.

In the fourth quarter of 2002, the Company analyzed itsinvestments in John Brown Hydrocarbons Limited andwrote off the associated goodwill of USD 50 million.

Acquisition of East Siberian Oil and Gas Company. In late2000, the Company purchased 68 percent of East SiberianOil and Gas Company (“East Siberian”), an oil productioncompany located in Eastern Siberia, for USD 65 million.During 2001, the Company purchased an additional2.2 percent of East Siberian for USD 4 million.

Note 11: Property, Plant and Equipment, Net

Accumulated

depreciation,

depletion and Net

Cost amortization book value

Oil and gas properties and equipment 4,612 1,367 3,245

Refining and related equipment 1,000 276 724

Assets under construction 1,186 – 1,186Other assets 1,376 415 961Balance at December 31, 2002 8,174 2,058 6,116Oil and gas properties

and equipment 3,240 1,108 2,132Refining and

related equipment 588 295 293Assets under construction 837 – 837Other assets 844 343 501Balance at December 31, 2001 5,509 1,746 3,763

Estimated costs of dismantling oil and gas productionfacilities, including abandonment and site restorationcosts, amounted to USD 602 million and USD 532 millionat December 31, 2002 and 2001, respectively. Of theseamounts, USD 199 million and USD 164 million have beenaccrued and are included within accumulated depreciation,depletion and amortization in the consolidated balancesheets at December 31, 2002 and 2001, respectively.

The Company has estimated its liability based on currentenvironmental legislation using estimated costs at the balance sheet dates. As is further described in Note 19,environmental regulations and their enforcement are con-tinually being considered by government authorities.Consequently, the ultimate liabilities may differ from therecorded amounts.

The Company’s oil and gas fields are situated on landbelonging to government authorities. The Companyobtains licenses from such government authorities andpays certain taxes to explore and produce from these fields.These licenses expire between 2013 and 2026, with themost significant licenses expiring between 2013 and 2015,and management believes that they may be extended at theinitiative of the Company. Management intends to extend

2

00


such licenses for properties expected to produce subse-quent to their license expiry dates.

Note 12: DebtShort-term debt and current portion of long-term debtwere as follows:

December 31, 2002 2001

Short-term debt 63 22Current portion of long-term debt 58 87Total short-term debt and current

portion of long-term debt 121 109

Included in short-term debt at December 31, 2002 and 2001,were Russian Ruble denominated amounts of RR 1,333 mil-lion (USD 42 million) and RR 151 million (USD 5 million),respectively. The Company’s significant outstanding short-term borrowing agreements at December 31, 2002 bearinterest at 7.0 percent per annum.

Long-term debt was as follows:

December 31, 2002 2001

Ministry of Finance/International Bank for Reconstruction and Development 43 82

Government of the Republic of Lithuania 289 –Other long-term borrowings 104 12Less: current portion of long-term debt (58) (87)Total long-term debt 378 7

Ministry of Finance/International Bank for Reconstructionand Development. At December 31, 2002 and 2001, theCompany had outstanding obligations to the Ministry ofFinance of the Russian Federation and to the InternationalBank for Reconstruction and Development arising fromborrowing agreements entered into by two of its sub-sidiaries. At December 31, 2002, the interest rates rangedfrom 5.06 percent to 6.01 percent per annum.

The following long-term borrowings were assumed withthe Company’s acquisition of Mazeikiu Nafta (Note 10) inSeptember 2002.

Government of the Republic of Lithuania. At December 31,2002, a U.S. Dollar-denominated loan agreement totalingUSD 289 million was outstanding from the Government of

the Republic of Lithuania. The debt is payable in install-ments from October 2005 to February 2007 and bearsinterest at 10 percent per annum.

Other Mazeikiu Nafta borrowings. Other long-term bor-rowings assumed in the Mazeikiu Nafta acquisition totaledUSD 58 million. The weighted-average interest rate of other Mazeikiu Nafta borrowings was 3.3 percent atDecember 31, 2002.

Intercompany debt of Mazeikiu Nafta. As discussed inNote 10, concurrent with its acquisition of first an equitystake and then a controlling stake in Mazeikiu Nafta, theCompany provided a USD 75 million loan to MazeikiuNafta and then purchased another USD 75 million loanreceivable from Mazeikiu Nafta. While these loans areeliminated for financial reporting purposes, the Companyintends to refinance the loans through third party lenders.Such refinancing will be reflected as an increase in borrow-ings in the Company’s consolidated financial statements.

Aggregate maturities of long-term debt outstanding atDecember 31, 2002 were as follows:

For the year ended December 31,

2004 222005 1422006 1362007 20Thereafter 58Total long-term debt 378

Note 13: Other Accounts Payable and Accrued Liabilities

December 31, 2002 2001

Dividends payable 402 9Advances from customers 54 67Salaries and wages payable 64 34Other 144 209Total other accounts payable and

accrued liabilities 664 319

Note 14: TaxesDeferred income tax. Deferred income tax reflects theimpact of temporary differences between the carrying val-ues of assets and liabilities recognized for U.S. GAAPfinancial reporting purposes and such amounts recognizedfor statutory tax purposes. Deferred income tax assets andliabilities arising in different tax jurisdictions are not offset.

2

00

2


Deferred income tax assets (liabilities) were comprised ofdifferences arising between the carrying values of the fol-lowing assets and liabilities:

December 31, 2002 2001

Property, plant and equipment 76 67Accounts receivable 8 17Taxes payable 20 19Tax loss carryforwards 51 –Other 44 65Gross deferred income tax assets 199 168Unremitted earnings of subsidiaries

and equity affiliates (926) (589)Property, plant and equipment (201) (87)Accounts receivable (7) (31)Other (35) (3)Gross deferred income tax liabilities (1,169) (710)Net deferred income tax liability (970) (542)

Tax loss carryforwards expire between 2010 and 2012.Based on the current statutory results of the Company andits subsidiaries, management believes that it is likely thatall deferred tax assets will be realized. Accordingly, no valu-ation allowances have been provided against deferred taxassets at December 31, 2002 and 2001.

Deferred income tax balances were classified in the consol-idated balance sheets as follows:

December 31, 2002 2001

Current deferred income tax asset and other current assets 69 86

Noncurrent deferred income tax asset 107 71Current deferred income tax liability (25) (30)Noncurrent deferred income tax liability (1,121) (669)Net deferred income tax liability (970) (542)

Enacted changes in income tax rates. In August 2000, theFederal Law on Income Tax for Companies was amended,increasing, effective January 1, 2001, the statutory incometax rate from 30 percent to 35 percent in most jurisdictions.This increase resulted in a one-time net increase to expenserelated to the adjustment to the Company’s deferred taxasset and liability balances as of the date of enactment ofthis change in income tax rates. The net increase totaledUSD 24 million, and was included within deferred income taxexpense in the consolidated statement of income for 2000.

In August 2001, the tax code of the Russian Federation wasfurther amended. As a result, new statutory income tax

rates were in place effective from January 1, 2002. Theamended tax code reduces the income tax rate for incomereceived from ordinary types of activities from 35 to 24 per-cent, the income tax rate for dividends received fromdomestic companies from 15 to 6 percent, and the incometax rate for dividends received from foreign companiesfrom 35 to 15 percent. This reduction resulted in a one-timenet credit to expense related to the adjustment to theCompany’s deferred tax asset and liability balances as ofthe date of enactment of this change in income tax rates.The net credit totaled USD 525 million, and was includedwithin deferred income tax expense in the consolidatedstatement of income for 2001.

Reconciliation of income tax. Presented below is a recon-ciliation between total income tax expense and theoreticalincome tax expense determined by applying the Russianstatutory tax rate to income before income tax and minor-ity interest.


Income before income tax and minority interest 3,810 3,866 4,950

Theoretical income tax expense at the statutory rate of 24 percent (35 percent in 2001; 30 percent in 2000) 914 1,353 1,485

Increase (decrease) in the theoretical income tax expense due to:Income taxed at other rates (745) (828) (854)Effect on deferred taxes of change

in statutory income tax rate – (525) (24)Investment tax credits and

other rate effects (9) (80) (57)Nondeductible/nontaxable items 120 140 105Deferred tax on

unremitted earnings 782 633 669Change in estimate of taxes on

unremitted earnings (368) – –Foreign exchange effects 52 9 (117)

Total income tax expense 746 702 1,207

In the fourth quarter of 2002, the Company recorded aUSD 368 million reduction in deferred tax liabilities thatresulted from management’s revised estimate of the appli-cable tax rates associated with the expected remittance ofearnings from certain subsidiaries. In conjunction with itsongoing review of tax strategy, management believes it canreduce its effective tax rate on such remittances by 5 percent.

2

00


Taxes other than income tax. The Company is subject to anumber of taxes other than on income that are detailedbelow. Payroll-based taxes are included with salary costswithin selling, general and administrative expenses andoperating expenses, as appropriate.


Export duties 914 987 577Royalty and mineral restoration tax – 409 212Unified production tax 1,478 – –Excise and fuel sales tax 459 476 245Road users tax 128 102 98Property tax 54 47 39Tax penalties and interest 12 40 16Other 42 14 59Total taxes other than income tax 3,087 2,075 1,246

Beginning January 1, 2002, mineral restoration tax, royaltytax and excise tax on crude oil production were abolishedand replaced by the unified natural resources productiontax. Through December 31, 2004, the base rate for the uni-fied natural resources production tax is set at RR 340 permetric ton of crude oil produced, and is to be adjusteddepending on the market price of Urals blend and theRR/USD exchange rate. The tax becomes nil if the Uralsblend price falls to or below USD 8.00 per barrel. FromJanuary 1, 2005, the unified natural resources productiontax rate is set by law at 16.5 percent of crude oil revenuesrecognized by the Company’s exploration and productionsubsidiaries based on Regulations on Accounting andReporting of the Russian Federation.

Taxes payable. Taxes payable at December 31, 2002 and2001 were as follows:

December 31, 2002 2001

Value-added tax 140 132Income tax 8 95Tax penalties and interest 7 62Excise and fuel sales tax 105 91Road users tax 38 14Property tax 8 13Royalty tax – 35Mineral restoration tax – 29Unified production tax 21 –Other 65 41Taxes payable 392 512

At December 31, 2002 and 2001, USD 91 million andUSD 87 million, respectively, of value-added taxes payablerepresent deferred amounts that are due upon settlementof the related receivable balances.

Final 2002 dividend. In April 2003, the Company’s Board ofDirectors recommended for consideration at theCompany’s annual general meeting of shareholders thatdividends of nominal RR 9.89 per share be paid for theCompany’s results for the year ended December 31, 2002.The Company’s annual general meeting of shareholders isscheduled for June 2003. The recommended dividendcomprises an interim dividend of nominal RR 5.70 pershare, which was declared in the fourth quarter of 2002and paid to shareholders in the first quarter of 2003, andan additional dividend of nominal RR 4.19 per share to bepaid no later than August 2003.

Reserves available for distribution to shareholders arebased on the statutory accounting reports of YUKOS OilCompany, which are prepared in accordance with Regula-tions on Accounting and Reporting of the Russian Federationand which differ from U.S. GAAP. Russian legislation iden-tifies the basis of distribution as net income. For 2002, the current year statutory net income for YUKOS OilCompany as reported in the annual statutory accountingreports was RR 40,701 million. However, current legislationand other statutory laws and regulations dealing with distribution rights are open to legal interpretation and,consequently, actual distributable reserves may differ fromthe amount disclosed.

Note 16: Related PartiesThe Company has undertaken numerous transactionswith several of the companies within the GroupMENATEP structure. These transactions primarily con-sisted of banking and investment activities, as well asconsulting services, carried out by Trust and InvestmentBank and Bank MENATEP Saint Petersburg, and are fur-ther described in the table below. As is further describedin Note 18, the Company’s core shareholders, throughYUKOS Universal, agree to fund benefits paid under theVeteran Social Support Program. Additionally, theCompany undertook a number of transactions involvingcollection rights and installment liabilities with entitiescontrolled by Group MENATEP and Bank MENATEP as aresult of the bankruptcy proceedings of Bank MENATEPfrom 1999 to 2001 (Note 1).

2

00

2


A summary of balances and transactions with Trust andInvestment Bank and Bank MENATEP Saint Petersburg isas follows:

At and for the year ended December 31, 2002 2001 2000

BalancesCash and cash equivalents (Note 4) 665 725 1,524Undiscounted installment

liabilities and notes payable 13 17 20Collateralized loans receivable 44 – –Long-term accounts receivable 29 – –

TransactionsPurchases of marketable

securities and other short-term investments 4,267 4,354 956

Sales of marketable securities and other short-term investments 4,060 2,975 542

Interest income 51 43 9

OtherUnsecured loans of marketable

securities (Note 5) – 98 –Marketable securities held by the

banks as depositories 359 222 201Outstanding guarantees issued

in favor of third parties 41 140 23

A summary of balances and transactions with other relatedparties is as follows:

At and for the year ended December 31, 2002 2001 2000

BalancesAccounts receivable 7 4 2Long-term accounts receivable 29 – –Trade accounts payable 3 1 18Undiscounted installment liabilities

and promissory notes payable 26 34 15

TransactionsPurchases of marketable securities – – 22Sales of marketable securities – – 14Purchases of shares of Trust and

Investment Bank and Bank MENATEP Saint Petersburg – 3 22

Sales of shares of Trust and Investment Bank and Bank MENATEP Saint Petersburg – 17 128

Sales of crude oil to AB Mazeikiu Nafta from June 2002 to September 2002 220 – –

Purchases of information technology, administrative and management services 38 3 –

Insurance premiums 21 32 14Transportation fees 8 – 56Processing fees paid for refining

of crude oil – 70 84Purchases of petroleum products – – 4Interest income 2 – –

Other significant related parties with whom the Company has undertaken transactions are outlined below:

Entity Nature of relationship Nature of transactions/balances

AB Mazekiu Nafta Equity investee from July 2002 through Sales of crude oilSeptember 2002, subsidiary thereafter Purchase of transportation and logistics services

Achinsk Refinery Equity investee partly through 2000; Purchase of crude oil processing servicesconsolidated beginning in 2000

Angarsk Petrochemical Company Equity investee partly through 2000 and 2001; Purchase of crude oil processing servicessubsidiary thereafter

MENATEP IFA Common control Sale of Bank MENATEP collection rightsGroup MENATEP Common control Installment liabilitiesPecunia Universal Limited Common control Purchases and sales of marketable securitiesProgress Garant Subsidiary partly through 2000; equity investee Purchase of insurance

partly through 2000 and 2001; cost investmentthereafter, common control

Rospan Equity investee since December 2002 Long-term accounts receivableTranspetrol a.s. Equity investee since April 2002 Purchase of transportation servicesSibintek Subsidiary partly through 2001, equity investee Purchase of information technology services

thereafter, common controlVolgotanker Equity investee partly through 2000; cost Purchase of transportation services

investment thereafter

2

00


Note 17: Earnings Per ShareBasic earnings per share is computed by dividing netincome (the “numerator”) by the weighted-average num-ber of ordinary shares outstanding (the “denominator”).Diluted earnings per share is similarly computed using thetreasury stock method, except the denominator is increasedto include the dilutive effect of outstanding stock optionsand unvested shares of conditional stock (Note 18). Exer-cise of these shares for option holders is contingent upon acontinued specified service period by the grantees. Issuanceof the shares for conditional stockholders is contingent uponboth a continued specified service period and upon meetingcertain performance conditions by the grantees.

The denominator is based on the following weighted-averagenumber of ordinary shares outstanding (millions of shares):


Weighted-average shares outstanding – basic earnings per share 2,155 2,142 2,212

Add: incremental shares from assumed conversions of Stock options 4 1 –Conditional stock 4 2 –

Weighted-average sharesoutstanding – diluted earnings per share 2,163 2,145 2,212

Note 18: Stock-Based CompensationEmployee stock-based compensation. In October 2000,the Company’s Board of Directors passed a resolutionauthorizing management to develop a stock-based com-pensation plan. In April 2001, the Company’s Board ofDirectors approved the YUKOS Stock Compensation Plan(the “Stock Compensation Plan”) through 2011 and author-ized up to 85 million shares of the Company’s ordinarystock. The Stock Compensation Plan provides for thegranting of stock options and conditional stock awards tocertain management personnel and other key employees.Vesting terms and exercise price for the awards are deter-mined at the date of grant. The Company’s Chairman of theExecutive Committee of the Board of Directors is not a par-ticipant in the Stock Compensation Plan. It was manage-ment’s intention that such ordinary shares as will be issuedunder the plan will be from treasury shares.

In October 2001, the Company granted 1,556,920 non-transferable options to purchase shares of the Company’sordinary stock at USD 1.63 per share, the market price ofthe Company’s ordinary shares as of the date the Board ofDirectors authorized the development of a stock-basedcompensation plan. Options granted in October 2001 vest11 percent in each of the first three years following theirgrant, 33 percent four years following the grant, and 34 per-cent five years following the grant. The options expire tenyears following grant date.

Additionally, in October 2001, the Company granted5,349,610 nontransferable conditional stock awards to cer-tain key management personnel. Under this award, Russianparticipants will receive the designated shares of stock onOctober 19, 2007 if they are continuously employed by theCompany through October 19, 2007, and if the average market value of the Company’s stock for the six months pre-ceding October 19, 2007 is at least USD 1.20. Other partici-pants may receive their shares on an accelerated basisbased upon the terms of their employment.

In December 2002, the Company granted 6,121,665 non-transferable conditional stock awards to certain key man-agement personnel. The awards vest 20 percent eachOctober through 2007. Participants will receive the desig-nated shares of stock on each vesting date if they havebeen continuously employed by the Company and havemaintained satisfactory performance.

The Company has elected to account for employee stockcompensation in accordance with the fair value provisionsof SFAS 123. Under SFAS 123, the Company recognizescompensation expense equal to the fair value of the awardson the date of grant for fixed awards and based upon thefair value of variable awards during the vesting period.

The fair value of the Company’s stock awards is measuredas the estimated present value at grant date using theBlack-Scholes option pricing model. The followingweighted-average assumptions were used for employeegrants made during 2001: expected volatility of 68.5 per-cent, a risk-free interest rate of 4.2 percent for conditionalstock awards and 4.5 percent for stock options, expectedannual dividend yield of 2.5 percent, and an expected term

2

00

2


of six years. The weighted-average fair value of theCompany’s employee stock options granted in 2001 wasUSD 2.06 and the weighted-average fair value of condi-tional stock grants was USD 2.59.

For conditional stock grants made in December 2002, totalcompensation expense was measured equal to the marketvalue of the Company’s shares on grant date less the pres-ent value of expected dividends prior to vesting. The follow-ing weighted-average assumptions were used for theconditional stock grants made in December 2002: a risk-free interest rate of 2.0 percent and an expected annualdividend yield of 3.0 percent. The weighted-average fair value of the Company’s conditional stock granted in December 2002 was USD 8.79.

Recorded compensation expense related to conditionalstock awards and stock options issued by the Company toemployees was USD 3 million and USD 1 million for theyears ended December 31, 2002 and 2001, respectively.

Veteran Social Support Program. During 2000, theCompany established the Veteran Social Support Program(the “Program”) to provide retirement benefits and to fundthe benefits for employees of the Company with at least10 years experience as of January 1, 1999 (the “Partici-pants”). Specifically, the Program’s objective is to providepayments to Participants that would allow the Participantsto move from their current residences to a more desirablelocation. Program benefits are based upon the perfor-mance of the Company’s stock, subject to certain minimumstock performance and maximum benefit restrictions.

During 2001, certain core shareholders of the Companyestablished the Veterans’ Trust (the “Trust”) to fund bene-fits paid under the Program. The Trust was funded by theshareholders with shares of YUKOS Oil Company ordinarystock. Under the terms of the Trust, benefits under theProgram will be paid directly by the Trust beginning in2005. Until that time, benefits claimed under the Programwill be paid by the Company.

Total benefits payable under the Program are based uponthe market appreciation on a notional number of shares ofthe Company’s stock from a base of USD 1.20 per share to aceiling of USD 3.25 per share. Accordingly, at December 31,2002, maximum benefits payable under the plan wereUSD 358 million.

U.S. GAAP establishes that the substance of the Program issubstantially the same for the Company and the employeewhether the Plan is adopted by the Company or by a princi-pal shareholder. Consequently, the Company recognizes allexpenses under the Program. Any Program costs paid bythe shareholders or by the Trust will be recognized as addi-tional capital contributions to the Company in the periodsin which the Company receives such contributions fromthe shareholders or the Trust. The cost of Program benefitsis recognized as compensation expense over the Partici-pants’ remaining service lives in accordance with the provi-sions of SFAS 123.

During 2002, 2001 and 2000, the Company recognizedUSD 56 million, USD 136 million and USD 10 million,respectively, of compensation expense related to theProgram. At December 31, 2002 and 2001, accumulatedProgram benefits of USD 202 million and USD 146 million,respectively, were recorded within other long-term liabilities.

Other stock compensation. In October 2001, the Companyissued 6,153,846 options to a third party for advisory services. The options were immediately exercisable forUSD 3.25 per share.

The following weighted-average assumptions were usedfor third-party grants made during 2001: expected volatilityof 68.5 percent, a risk-free interest rate of 4.2 percent,expected annual dividend yield of 2.5 percent, and anexpected term of three years. The weighted-average fairvalue of the Company’s third-party stock options granted in2001 was USD 1.39. Recorded compensation expenserelated to third-party grants was USD 8.6 million for theyear ended December 31, 2001.

2

00


All awards outstanding at December 31, 2002 are out-lined below.

Weighted-

average

Shares exercise

under price

option (USD)

Awards outstanding at December 31, 2000 – –

Granted 13,060,376 1.73Awards outstanding at

December 31, 2001 13,060,376 1.73Granted 6,152,665 0.01Exercised (3,108,404) 3.25Canceled (34,620) 1.63Awards outstanding at

December 31, 2002 16,070,017 0.77

Weighted-

Number Weighted- average

exercisable average remaining

Shares at exercise contractual

under December 31, price life

option 2002 (USD) in years

Conditional stock awards 11,470,275 – – –

Employee stock options 1,545,896 160,369 – –

Third-party stock options 3,053,846 3,053,846 3.25 1.8

Note 19: Commitments and Contingent LiabilitiesOperating environment. While there have been improve-ments in the economic situation in the Russian Federationin recent years, it continues to display some characteris-tics of an emerging market. These characteristics include,but are not limited to, the existence of a currency that isnot freely convertible in most countries outside of theRussian Federation, restrictive currency controls, and rela-tively high inflation.

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

Guarantees. At December 31, 2002, the Company and itssubsidiaries provided guarantees, either directly or indi-rectly, of USD 41 million for notes and other contractualobligations of third parties and for performance obliga-tions as discussed below. There are no amounts being car-ried as liabilities for these guarantees as management doesnot believe that it is probable that the Company will berequired to perform under these guaranties. The Companyhas provided cash or other assets as collateral for certain ofthe guarantees as described further below.

The Company has provided loan guarantees on behalf ofthe administrations of local governments for improvementof infrastructure in areas where the Company operates. Theguarantees expire in periods from three months to sevenyears. The Company would be required to perform underthe guarantees in the event of default by the local adminis-trations. The maximum amount of potential payments isUSD 41 million. The Company has deposited cash andmarketable securities as collateral against these guaran-tees in the amount of USD 25 million.

The Company provides bid and performance-related bondsin connection with work it is required to perform under cer-tain contracts. The contracts typically have terms rangingfrom 2 month to 3 years. Any potential payments thatwould be required are related to performance under theapplicable contract. The Company has placed cash ofUSD 21 million with banks to guarantee its performance.

Taxation. Russian tax legislation is subject to varying inter-pretations and periodic changes, which may be retroactive.Further, the interpretation of tax legislation by tax authori-ties as applied to the transactions and activities of theCompany may not coincide with that of management. As aresult, certain transactions may be challenged by taxauthorities and the Company may be assessed additionaltaxes, penalties and interest. Consolidated tax returns arenot required under existing Russian tax legislation and taxaudits are performed on an individual entity basis only. Tax periods remain open to review by the tax authorities forthree years.

2

00

2


Environmental liabilities. The Company and its predeces-sor entities have operated in the Russian Federation formany years and certain environmental problems havedeveloped. Environmental regulations and their enforce-ment are continually being considered by governmentauthorities and the Company periodically evaluates its obli-gations related thereto. As obligations are determined,they are provided for over the estimated remaining lives ofthe related oil and gas reserves, or recognized immediately,depending on their nature. The existence of environmentalliabilities under proposed or any future legislation, or as aresult of stricter enforcement of existing legislation, cannotreasonably be estimated. Under existing legislation, man-agement believes there are no probable liabilities that arein excess of amounts accrued under the units-of-productionmethod in the consolidated financial statements whichwould have a material adverse effect on the financial posi-tion, operating results or liquidity of the Company.

Legal contingencies. The Company is the named defendantin a number of lawsuits as well as a named party in numer-ous other proceedings arising in the ordinary course ofbusiness. While the outcomes of such contingencies, law-suits or other proceedings cannot be determined at pres-ent, management believes that any resulting liabilities willnot have a material adverse effect on the financial position,operating results or liquidity of the Company.

Note 20: Segment InformationThe Company’s business activities are conducted predomi-nantly through two major business segments: Explorationand Production, and Refining and Marketing. These seg-ments were determined based on the way that manage-ment organizes and reports on the segments within theCompany for making operating decisions and assessingperformance and by the structure of the Company’s inter-nal organization.

Exploration and Production primarily explores for, devel-ops and extracts liquid hydrocarbons, which are thenprocessed into crude oil and natural gas liquids, primarilythrough the Company’s subsidiaries, Yuganskneftegas andTomskneft in Western Siberia, and Samaraneftegas in theSamara region of the Russian Federation.

Refining and Marketing purchases crude oil produced by ourExploration and Production entities and then refines, mar-kets and distributes crude oil and markets and distributespetroleum products for international and domestic sales. Toa limited extent, Refining and Marketing also purchasescrude oil and petroleum products produced by third parties.

Our two major business segments are dependent on eachother, with the revenues of Exploration and Productionbeing a significant part of the costs of Refining andMarketing. The prices set for Refining and Marketing’s pur-chases from Exploration and Production reflect a combina-tion of factors, including tax considerations and marketforces. Taking this into account, as well as the close inte-gration of these segments, and the relatively small size andlow liquidity of the Russian crude oil market, we believethat any estimates of the financial performance of our separate segments, including segment net income, wouldhave limited analytical value.

In addition to these two major business segments, theCorporate and Other segment consists primarily of the Company’s corporate offices, which provide treasuryoperations, business services and infrastructure support toits operating business segments, a retail grocery chain andother subsidiaries that provide procurement and logisticsservices to internal and third parties.

The accounting policies of the business segments are thesame as those described in the Summary of SignificantAccounting Policies (Note 3). Sales from the transfer ofproducts between segments are at actual sales prices.Domestic sales exclude distribution costs which, under theRussian crude oil distribution system, are charged to thepurchasers of crude oil by Transneft, the state-owned oildistribution company. Costs and other deductions excludeinternal transfers. Intersegment purchases represent theelimination of intersegment sales for the purposes of deriv-ing segment net income. Corporate administration costsand assets are not allocated to the operating segments.Segment assets do not include intercompany investmentsor intercompany receivable balances.

No individual customer comprised more than 10 percentof the Company’s sales during 2002, 2001 or 2000. Man-agement does not believe that the Company is reliant onany particular customer.

2

00


Operating segment information as at and for the year ended December 31, 2002 is presented below.

Exploration Refining Corporate Intersegment

and and and sales

production marketing other elimination Total

Sales and other operating revenuesInternational sales – crude oil 2 5,956 – – 5,958International sales – petroleum products – 2,289 – – 2,289Domestic sales – crude oil 8 78 – – 86Domestic sales – petroleum products 2 2,580 – – 2,582Other 267 126 65 – 458Intersegment sales 2,611 45 26 (2,682) –Total sales and other operating revenues 2,890 11,074 91 (2,682) 11,373

Costs and other deductionsCrude oil and petroleum products purchased 18 322 – – 340Operating expenses 993 527 76 (117) 1,479Distribution expenses 1 1,513 – – 1,514Selling, general and administrative expenses 250 259 326 – 835Depletion, depreciation and amortization 408 27 24 – 459Taxes other than income tax 1,577 1,507 3 – 3,087Exploration expenses 87 – – – 87Other 60 12 17 – 89Intersegment purchases 42 2,518 5 (2,565) –Total costs and other deductions 3,436 6,685 451 (2,682) 7,890Interest income 3 – 330 – 333Interest expense (17) – (47) – (64)Exchange gain (loss), net 18 (87) (49) – (118)Other income, net – – 176 – 176Total other income (loss) 4 (87) 410 – 327Total income tax expense (benefit) (88) 366 468 – 746Minority interest 10 (4) (12) – (6)Segment net income (loss) (444) 3,932 (430) – 3,058Additions to property, plant and equipment 932 268 82 – 1,282Total assets 5,264 3,589 5,541 – 14,394

2

00

2




and and and sales


Sales and other operating revenuesInternational sales – crude oil – 4,942 – – 4,942International sales – petroleum products – 1,692 – – 1,692Domestic sales – crude oil 5 50 – – 55Domestic sales – petroleum products 6 2,504 – – 2,510Other 171 85 6 – 262Intersegment sales 2,368 55 1 (2,424) –Total sales and other operating revenues 2,550 9,328 7 (2,424) 9,461

Costs and other deductionsCrude oil and petroleum products purchased – 481 – – 481Operating expenses 834 348 – – 1,182Distribution expenses – 1,048 – – 1,048Selling, general and administrative expenses 168 204 299 – 671Depletion, depreciation and amortization 240 22 8 – 270Taxes other than income tax 646 1,428 1 – 2,075Exploration expenses 52 – – – 52Other 21 2 25 – 48Intersegment purchases 53 2,366 5 (2,424) –Total costs and other deductions 2,014 5,899 338 (2,424) 5,827Interest income 1 – 308 – 309Interest expense (6) – (39) – (45)Exchange gain (loss), net (14) (130) (26) – (170)Other income, net – – 138 – 138Total other income (loss) (19) (130) 381 – 232Total income tax expense (benefit) 175 548 (21) – 702Minority interest (16) 8 – – (8)Segment net income 326 2,759 71 – 3,156Additions to property, plant and equipment 759 98 36 – 893Total assets 3,331 2,188 4,983 – 10,502

2

00




and and and sales


Sales and other operating revenuesInternational sales – crude oil – 4,639 – – 4,639International sales – petroleum products – 1,448 – – 1,448Domestic sales – crude oil – 142 – – 142Domestic sales – petroleum products 14 2,497 – – 2,511Other 176 108 8 – 292Intersegment sales 1,382 29 6 (1,417) –Total sales and other operating revenues 1,572 8,863 14 (1,417) 9,032

Costs and other deductionsCrude oil and petroleum products purchased – 662 – – 662Operating expenses 623 249 – – 872Distribution expenses – 697 – – 697Selling, general and administrative expenses 170 269 123 – 562Depletion, depreciation and amortization 187 26 5 – 218Taxes other than income tax 443 801 2 – 1,246Exploration expenses 35 – – – 35Other 41 2 9 – 52Intersegment purchases 29 1,382 6 (1,417) –Total costs and other deductions 1,528 4,088 145 (1,417) 4,344Interest income 2 – 130 – 132Interest expense (33) – (127) – (160)Exchange gain (loss), net 41 (22) 24 – 43Other income, net – – 247 – 247Total other income (loss) 10 (22) 274 – 262Total income tax expense (benefit) (68) 649 626 – 1,207Minority interest (17) (2) – – (19)Segment net income (loss) 105 4,102 (483) – 3,724Additions to property, plant and equipment 466 65 30 – 561Total assets 2,868 1,952 3,708 – 8,528

Note 21: Subsequent EventIn April 2003, the Company reached a definitive agreementwith the major shareholders of Sibneft Oil Company(“Sibneft”), under which the Company will acquire 20 per-cent less one share of the outstanding shares of Sibneft fora total cash consideration of USD 3 billion and an additionalstake of up to 72 percent plus one share for up to 26.01 per-cent of the fully diluted share capital of the newYUKOSSibneft. The Company expects that the shares to be

exchanged will come from existing treasury shares, addi-tional shares purchased on the market and/or from a newissuance of shares. Each party to the agreement is subjectto a termination clause requiring a payment of USD 1 billionin the event that it terminates the arrangement withoutcause. The Company believes the merger will strengthen itscompetitive advantages by combining with one of its princi-pal domestic competitors to provide a larger productionand reserve base and serve as a platform for further growth.

2

00

2

In accordance with Statement of Financial AccountingStandards No. 69, Disclosures about Oil and Gas ProducingActivities (“SFAS 69”), this section provides supplemen-tal information on oil and gas exploration and produc-tion activities.

The Company’s production activities are almost exclusivelywithin the Russian Federation; therefore, substantially allof the information provided in this section pertains to thisregion. The Company operates directly and through vari-ous production subsidiaries.

Oil and Gas Exploration and Development CostsThe following tables set forth information regarding oil andgas exploration and development costs. The amountsreported as costs incurred include both capitalized costsand costs charged to expense during the year.


Costs incurred in exploration and development activities

Development costs 787 647 419Property acquisition costs 406 – 65Exploration costs 85 102 54Total costs incurred in exploration

and development activities 1,278 749 538


Capitalized costs of oil and gas properties

Producing assets 1,554 1,320 1,225Support facilities and equipment 3,058 1,920 1,605Incomplete construction 836 638 327Total capitalized costs of oil and

gas properties 5,448 3,878 3,157Accumulated depreciation,

depletion and amortization (1,367) (1,108) (875)Net capitalized costs of oil and

gas properties 4,081 2,770 2,282

Results of Operations for Oil and Gas Producing ActivitiesThe Company’s results of operations for oil and gas pro-ducing activities are shown below. Natural gas productiondoes not represent a material portion of the Company’stotal oil and gas production.

In accordance with SFAS 69, results of operations for oiland gas producing activities do not include general corpo-rate overhead and monetary effects, nor their associated taxeffects. Income tax is based on statutory rates for the yearadjusted for tax deductions, tax credits and allowances.


Revenues from net productionSales 5,131 4,524 4,350Transfers(1) 1,525 1,678 2,205

6,656 6,202 6,555Operating expenses 771 774 568Taxes other than income tax 2,267 1,333 900Depreciation, depletion

and amortization 381 159 149Exploration expenses 87 52 35Related income tax expense 267 576 695Results of operations for oil and

gas producing activities 2,883 3,308 4,208

(1) Transfers represent oil transferred to affiliated enterprises for processing. Such transfers are

valued at average domestic market prices for crude oil, as required under SFAS 69.

Proved Oil and Gas Reserve QuantitiesAs determined by the Company’s independent reservoirengineers, DeGolyer and MacNaughton, the followinginformation presents the quantities of proved oil and gasreserves and changes thereto as at and for the years endedDecember 31, 2002, 2001 and 2000. The definitions usedare in accordance with applicable United States Securitiesand Exchange Commission (“SEC”) regulations.

YUKOS Oil Company supplemental oil and gas information (unaudited) (Expressed in U.S. Dollars (tabular amounts in millions))

2

00


Proved reserves are defined as the estimated quantities of oiland gas which geological and engineering data demonstratewith reasonable certainty to be recoverable in future yearsfrom known reservoirs under existing economic conditions.In some cases, substantial new investment in additionalwells and related support facilities and equipment will berequired to recover such proved reserves. Due to the inher-ent uncertainties and the limited nature of reservoir data,estimates of underground reserves are subject to changeover time as additional information becomes available.

Management believes that proved reserves should includequantities which are expected to be produced after theexpiry dates of the Company's production licenses. Theselicenses expire between 2013 and 2026, with the most sig-nificant licenses expiring between 2013 and 2015. Manage-ment believes the licenses may be extended at the initiativeof the Company and management intends to extend suchlicenses for properties expected to produce subsequent totheir license expiry dates. The Company has disclosedinformation on proved oil and gas reserve quantities andstandardized measure of discounted future net cash flowsfor periods up to and past the license expiry dates separately.

Proved developed reserves are those reserves which areexpected to be recovered through existing wells with exist-ing equipment and operating methods. Undevelopedreserves are those reserves which are expected to be

recovered as a result of future investments to drill newwells, to recomplete existing wells and/or install facilitiesto collect and deliver the production.

“Net” reserves exclude quantities due to others when produced.

The below reserve quantities include 100 percent of the netreserve quantities attributable to the Company’s consoli-dated subsidiaries.

A portion of the Company’s total proved reserves are classi-fied as either developed nonproducing or undeveloped. Ofthe nonproducing reserves, a portion represents existingwells which are to be returned to production at a future date.

The prices used in the forecast of future net revenues arethe year-end weighted-average of the prices received for salesdomestically, for exports to CIS countries and for exports tonon-CIS countries. Due to the absence of a developed mar-ket for crude oil in Russia, the Company employs a “net-back” method to estimate a domestic price for crude oil.

Net proved reserves of crude oil, condensate and naturalgas liquids and natural gas are presented below. For con-venience, volumes of both crude oil, condensate and natu-ral gas liquids and volumes of natural gas are providedboth in English units and in metric units.

2

00

2

Supplemental Oil and GasInformation (Unaudited)(Expressed in U.S. Dollars (tabular amounts in millions))

The tables below represents reserve quantities attributable to the Company’s consolidated subsidiaries.

Net proved reserved of crude oil, condensate and natural gas liquids are presented below.

Net proved reserves of crude Net proved reserves of

oil, condensate and natural crude oil, condensate and Total net proved reserves

gas liquids recoverable up natural gas liquids recoverable of crude oil, condensate

to license expiry dates past license expiry dates and natural gas liquids

Millions of Millions of Millions of Millions of Millions of Millions of

barrels metric tons barrels metric tons barrels metric tons

Reserves at December 31, 1999 5,050 690 4,503 613 9,553 1,303Changes attributable to:

Revisions 292 40 (95) (12) 197 28Extensions and discoveries 158 22 33 4 191 26Acquisitions 51 7 2 – 53 7Production (366) (50) – – (366) (50)


Revisions 196 27 (22) (4) 174 23Extensions and discoveries 130 18 41 6 171 24Production (421) (58) – – (421) (58)


Revisions 591 86 (73) (7) 518 79Extensions and discoveries 614 83 154 23 768 106Acquisitions 107 16 15 3 122 19Production (507) (69) – – (507) (69)

Reserves at December 31, 2002 5,895 812 4,558 626 10,453 1,438Net proved developed reserves

(included above)At December 31, 1999 3,990 545 3,460 472 7,450 1,017At December 31, 2000 4,092 559 3,407 465 7,499 1,024At December 31, 2001 4,072 557 3,386 462 7,458 1,019At December 31, 2002 3,966 543 3,474 475 7,440 1,018

2

00


Net proved reserves of natural gas are presented below.

Net proved reserves of Net proved reserves of

natural gas recoverable natural gas recoverable Total net proved

up to license expiry dates past license expiry dates reserves of natural gas

Billions of Billions of Billions of Billions of Billions of Billions of

cubic feet cubic meters cubic feet cubic meters cubic feet cubic meters

Reserves at December 31, 1999 1,193 34 1,077 30 2,270 64Changes attributable to:

Revisions 89 3 (28) (2) 61 1Extensions and discoveries 47 1 10 1 57 2Acquisitions 160 5 3 – 163 5Production (103) (3) – – (103) (3)


Revisions 80 2 (7) – 73 2Extensions and discoveries 38 1 12 – 50 1Production (117) (3) – – (117) (3)


Revisions (562) (17) (113) (1) (675) (18)Extensions and discoveries 7 – 2 – 9 –Acquisitions 2,532 72 344 9 2,876 81Production (85) (2) – – (85) (2)

Reserves at December 31, 2002 3,279 93 1,300 37 4,579 130

Net proved developed reserves (included above)At December 31, 1999 927 26 790 23 1,717 49At December 31, 2000 978 28 782 22 1,760 50At December 31, 2001 991 28 778 22 1,769 50At December 31, 2002 1,675 47 814 23 2,489 70

The table below represents reserve quantities attributable to the Company’s net interest in equity affiliate, Rospan:

Net proved reserves of crude oil, Net proved reserves

condensate and natural gas liquids of natural gas

Millions of Millions of Billion of Billions of

barrels metric tons cubic feet cubic meters

Reserves at December 31, 2002 48 6 990 28

Net proved developed reserves (included above)At December 31, 2002 9 1 203 6

2

00

2

Supplemental Oil and GasInformation (Unaudited)(Expressed in U.S. Dollars (tabular amounts in millions))

Future cash flows Future cash flows Future cash flows

attributable to net proved attributable to net proved attributable to

reserves recoverable reserves recoverable total recoverable

December 31, 2002 up to license expiry dates past license expiry dates net proved reserves

Future cash inflows from production 96,718 75,207 171,925Future development and production costs (35,254) (27,687) (62,941)Future income tax expense (12,459) (11,063) (23,522)Undiscounted future net cash flows 49,005 36,457 85,462Ten percent annual discount (19,620) (32,390) (52,010)Standardized measure of discounted

future net cash flows 29,385 4,067 33,452













Standardized Measure of Discounted Future Net Cash FlowsThe standardized measure of discounted future net cashflows is calculated in accordance with SFAS 69. SFAS 69requires measurement of future net cash flows by applyingyear-end prices and costs and a discount factor of ten per-cent to year-end quantities of estimated net proved reservesusing a standardized formula. The calculation assumescontinuation of year-end economic and political conditionsand requires extensive judgment in estimating the timing offuture production of reserves. Moreover, probable and pos-sible reserves, which may become proved in the future, are

excluded from the calculation as are discounted future netcash flows from equity affiliates. As a result, future cashflows calculated under SFAS 69 are not necessarily indica-tive of the Company’s future cash flows, nor the fair value ofits oil and gas reserves; other assumptions of equal validitycould give rise to materially different results.

As described in the previous section, the Company hasdisclosed standardized measure of discounted future netcash flows for periods up to and past the license expirydates separately.

2

00


Changes in Standardized Measure of Discounted Future Net Cash Flows




Year ended December 31, 2002 up to license expiry dates past license expiry dates net proved reserves

Standardized measure of discounted future net cash flows at beginning of year 15,456 2,529 17,985

Sales and transfers of oil and gas produced (3,150) – (3,150)Accretion of discount 1,917 369 2,286Net change in sales prices and in production (lifting)

costs related to future production 10,631 4,056 14,687Net change due to revisions in quantity estimates 4,189 (1,687) 2,502Changes in estimated future development costs (1,501) 80 (1,421)Net change due to purchases and sales of minerals in place 718 35 753Net change due to extensions, discoveries and improved recovery 4,092 (735) 3,357Net change in income tax expense (3,754) (580) (4,334)Development costs incurred 787 – 787Net change for the year 13,929 1,538 15,467Standardized measure of discounted

future net cash flows at end of year 29,385 4,067 33,452







costs related to future production (2,265) 990 (1,275)Net change due to revisions in quantity estimates 823 (383) 440Changes in estimated future development costs (400) (12) (412)Net change due to extensions, discoveries and improved recovery 549 (90) 459Net change in income tax expense (507) (805) (1,312)Development costs incurred 647 – 647Net change for the year (2,926) (11) (2,937)Standardized measure of discounted








costs related to future production (4,467) (13) (4,480)Net change due to revisions in quantity estimates 1,345 (775) 570Changes in estimated future development costs (351) 19 (332)Net change due to purchases and sales of minerals in place 97 – 97Net change due to extensions, discoveries and improved recovery 740 (211) 529Net change in income tax expense 446 141 587Development costs incurred 419 – 419Net change for the year (4,107) (487) (4,594)Standardized measure of discounted


2

00

2

References to “YUKOS,” “Company,” “Group,” “we,” “our” or“us” are references to YUKOS Oil Company and its consolidatedsubsidiaries and associates.

The discussion and analysis of YUKOS’ financial condition andresults of operations should be read in conjunction withYUKOS’ consolidated financial statements.

This report includes forward-looking statements. You can iden-tify our forward-looking statements by the words “expects,”“intends,” “plans,” “projects,” “believes,” “estimates” andsimilar expressions. We have based the forward-looking state-ments relating to our operations on our current expectationsand on estimates and projections about YUKOS and the petro-leum industry in general. We caution you that these state-ments are not guarantees of future performance and involverisks, uncertainties and assumptions that we cannot predictwith certainty. Accordingly, our actual outcomes and resultsmay differ materially from what we have expressed or fore-casted in the forward-looking statements. Any differencescould result from a variety of factors including, but not limitedto, the following:

• fluctuations in crude oil and petroleum product prices;• changes in tax and other laws applicable to our business;• changes in regulations governing access to export

infrastructure;• changes in tariffs charged by monopolies;

• international monetary conditions and exchange controls;• liability for remedial actions under environmental regulations;• inherent uncertainties in predicting oil and gas reserves and

oil and gas reservoir performance;• unsuccessful exploratory drilling activities;• unexpected cost increases or technical difficulties in con-

structing or modifying our company manufacturing andrefining facilities;

• potential disruption or interruption of our production facili-ties due to accidents or political events;

• liability resulting from litigation;• general domestic and international economic and politi-

cal conditions.

Tabular amounts are rounded. However, percentage changesare calculated using actual amounts.

For financial reporting purposes, we convert metric tons ofcrude oil to barrels of crude oil using a conversion factor of 7.31.This factor represents a blend of varying conversion factors spe-cific to each of our fields. Because the proportion of actual pro-duction by field varies from period to period, total productionvolumes for the Company in barrels converted from metrictons using the blended rate may differ from total productioncalculated on a field by field basis. Accordingly, the total pro-duction figures discussed in this Management’s Discussion andAnalysis differ insignificantly from those disclosed elsewhere.

YUKOS Oil Company management’s discussion and analysis (Expressed in U.S. Dollars (tabular amounts in millions) except as indicated otherwise)

2

00


OverviewWe are a vertically integrated oil company primarily engagedin the exploration, development and production of crudeoil, the refining of crude oil into petroleum products and themarketing and distribution of crude oil and petroleum prod-ucts. As of December 31, 2002, we were the second largestoil company in Russia in terms of proved oil reserves. In2002, we were the second largest oil company in Russia interms of crude oil production and the second largest refinerof crude oil and wholesale marketer of petroleum productsin Russia. In the fourth quarter of 2002, we were the largestoil company in Russia in terms of crude oil production.

In April 2003, we reached a definitive agreement with themajor shareholders of Sibneft Oil Company (“Sibneft”),under which we will acquire 20 percent less one share ofSibneft for a total cash consideration of USD 3 billion andan additional stake of up to 72 percent plus one share forup to 26.01 percent of the fully diluted share capital of thenew YUKOSSibneft. We expect that the shares to beexchanged will come from existing treasury shares, addi-tional shares purchased on the market and/or from a newissuance of shares. Each party to the agreement is subjectto a termination clause requiring a payment of USD 1 billionin the event that it terminates the arrangement withoutcause. We believe the merger will strengthen our competi-tive advantages by combining with one of our principaldomestic competitors to provide a larger production andreserve base and serve as a platform for further growth.

In the years ended December 31, 2002, 2001 and 2000, wehad revenues of USD 11,373 million, USD 9,461 million and USD 9,032 million, respectively, and net income of approximately USD 3,058 million, USD 3,156 million andUSD 3,724 million, respectively. As of December 31, 2002, wehad total assets of USD 14,394 million and a cash and mar-ketable securities position, net of debt, of USD 3,496 million.

Our business activities are conducted primarily throughtwo major business segments – Exploration and Production,which explores for, develops and extracts hydrocarbons,which it then treats to produce crude oil and natural gas,and Refining and Marketing, which refines, markets andsells crude oil and markets and sells petroleum products.In addition to these principal business segments, we alsohave a Corporate and Other segment, consisting primarilyof our corporate offices, which provide management,financial services, business services and infrastructuresupport to our operating businesses, and our other busi-nesses that are not related to oil and gas activities.

Our two major business segments are dependent on eachother, with the revenues of Exploration and Production beinga significant part of the costs of Refining and Marketing.Refining and Marketing purchases crude oil produced byour Exploration and Production entities. To a limitedextent, Refining and Marketing also purchases crude oiland petroleum products produced by third parties. Theprices set for Refining and Marketing’s purchases fromExploration and Production reflect a combination of fac-tors, including tax considerations and market forces.Taking these factors into account, as well as the close inte-gration of these segments, and the relatively small size andlow liquidity of the domestic Russian crude oil market, webelieve that any separate discussion of the financial per-formance of our two major segments, including segmentnet income, would have limited analytical value and is notnecessary to the understanding of our business as a whole.For this reason, we generally do not analyze either of ourmain segments separately in the discussion that followsexcept where trends for the segments differ in a given itemand such distinctions assist in explaining fluctuations. Wedo present certain financial data for each segment in Note 20to the consolidated financial statements.

Basis of Presentation and Critical Accounting PoliciesThe preparation of consolidated financial statements inconformity with U.S. GAAP requires estimates and assump-tions that affect the reported amounts of assets, liabilities,revenues and expenses and the disclosure of contingentassets and liabilities. Actual amounts may differ from theseestimates. The following critical accounting policies requiresignificant judgments, assumptions and estimates and youshould read them in conjunction with our consolidatedfinancial statements.

Successful efforts method of oil and gas accounting. Wefollow the successful efforts method of accounting for ouroil and gas properties, whereby property acquisitions, suc-cessful exploratory wells, all development costs (includingdevelopment dry holes) and support equipment and facili-ties are capitalized. We expense exploratory well costs if wecannot determine whether proved reserves can be foundwithin a reasonable amount of time following completionof drilling. We expense all other exploratory costs. We cal-culate depreciation, depletion and amortization of capital-ized costs of proved oil and gas properties using theunits-of-production method for each field based upon esti-mates of proved and proved developed reserves.

2

00

2

Management’s Discussionand Analysis(Expressed in U.S. Dollars (tabular amountsin millions) except as indicated otherwise)

The process of estimating reserves is inherently judgmen-tal. Proved oil and gas reserves are estimated quantities ofcrude oil and natural gas which geological and engineeringdata demonstrate with reasonable certainty to be recover-able in future years from known reservoirs under existingeconomic and operating conditions (i.e., prices and costsas of the date that the estimate is made). Prices includeconsideration of changes in existing prices provided onlyby contractual arrangements, but not on escalations basedupon judgments about future conditions. Actual prices andcosts are subject to change due, in significant part, to fac-tors beyond our control. These factors include world oilprices, energy costs and increases or decreases of oil fieldservice costs.

We accrue estimated costs of dismantling oil and gas pro-duction facilities, including abandonment and site restora-tion costs, using the units-of-production method and weinclude these costs as a component of depreciation, deple-tion and amortization. These estimates are based on currentlyavailable technology and current environmental regula-tions and their interpretation. If these technologies or regu-lations or their interpretation change in the future, actualresults could differ from our estimates.

Allowance for doubtful accounts. Our allowance for doubt-ful accounts is based on our assessment of the collectibilityof specific customer accounts. If there is a deterioration ofa major customer’s creditworthiness or actual defaults arehigher than our estimates, the actual results could differfrom these estimates.

Environmental remediation. We record liabilities for envi-ronmental remediation when it is probable that obligationshave been incurred and the amounts can be reasonablyestimated. Liabilities for environmental remediation aresubject to change because of matters such as changes inlaws and regulations and their interpretation, the determi-nation of additional information on the extent and natureof site contamination and improvements in technology.

Income tax accounting. The computation of our currentand deferred provisions for income taxes requires the inter-pretation of complex tax laws in multiple jurisdictions bothwithin the Russian Federation and internationally. Uncer-tainty related to Russian tax laws exposes us to enforce-ment measures and the risk of significant fines despite ourbest efforts at compliance and could result in a greaterthan expected tax burden.

AcquisitionsPrincipal production and refining subsidiariesAs discussed in more detail below, since January 1, 2002,we either initiated, continued, or completed the acquisitionof controlling interests in several of our principal produc-tion and refining subsidiaries. We continue to review vari-ous potential acquisitions involving both upstream anddownstream operations and we are prepared to takeadvantage of appropriate acquisition opportunities.

OAO NNGK Sakhaneftegas. Through a series of trans-actions during 2002, we purchased a 50.4 percent inter-est in OAO NNGK Sakhaneftegas (“Sakhaneftegas”), an oil and gas company operating in Eastern Siberia for USD 50 million. Sakhaneftegas and its subsidiaries hold anumber of licenses for exploration, development and pro-duction of hydrocarbon reserves in Yakutia, EasternSiberia. Acquisition of Sakhaneftegas positions theCompany for participation in future development of the oiland gas industry in Eastern Siberia.

OAO Arcticgas. In March 2002, we purchased an 88 per-cent interest in OAO Arcticgas (“Arcticgas”), a holder ofexploration and development licenses for a number of gasand condensate fields located in Western Siberia forUSD 251.8 million. In December 2002, we acquired the remain-ing 12 percent interest in Arcticgas for USD 22.5 million.

ZAO Urengoil Inc. In two transactions in December 2001and May 2002, through an intermediary, we acquired a100 percent interest in ZAO Urengoil Inc. (“Urengoil”), adomestic natural gas company with assets in WesternSiberia, for USD 75 million.

Eastern Oil Company. During 2002, we acquired an addi-tional 42.3 percent in our subsidiary, Eastern Oil Company,through a combination of purchases in a public tender andon the open market, effectively increasing our ownership to97.0 percent at December 31, 2002. Total acquisition costsfor the purchases were USD 256 million. Subsequent toDecember 31, 2002, Eastern Oil Company approved a planto merge its assets into the parent company. Under theplan, we shall acquire the remaining 3.0 percent of out-standing shares.

AB Mazeikiu Nafta. In June 2002, we purchased a 26.85 per-cent interest in AB Mazeikiu Nafta, a Lithuanian companywhose principal assets are a refinery, a pipeline network and amarine crude oil terminal located in Butinge, Lithuania on theBaltic Sea. Our investment consisted of USD 75 million for

2

00


the purchase of the shares and a USD 75 million loan tomodernize Mazeikiu Nafta’s refinery, which was guaranteedby the Lithuanian government. We secured an agreement tosupply 4.8 million metric tons (35 million barrels) of crudeoil annually, or an average of 96,000 barrels per day, to therefinery for 10 years beginning in July 2002, at prices estab-lished on the basis of market price formulas which areapplied to each individual shipment. In September 2002,we purchased an additional 26.85 percent interest inMazeikiu Nafta from Williams International Company andsecured the rights to manage Mazeikiu Nafta for USD 85million. In connection with this transaction, we also pur-chased from Williams International Company a USD 75 mil-lion loan from Williams International Company to MazeikiuNafta for USD 75 million plus accrued interest. This loan isalso guaranteed by the Lithuanian government. Otheracquisition costs related to the purchase of Mazeikiu Naftatotaled USD 4 million. Mazeikiu Nafta’s results wereincluded in our financial statements using the equity methodof accounting from June 2002 to September 2002 and havebeen fully consolidated in our financial statements sinceSeptember 2002.

The following table sets forth the condensed balance sheetinformation of Mazeikiu Nafta at acquisition and at

December 31, 2002, excluding intercompany balances andfollowing purchase accounting adjustments:

At December 31,

At acquisition 2002

(Unaudited)

Cash 135 109Accounts and notes receivable, net 60 91Inventories 67 84Other current assets 5 –Property, plant and equipment and

other long-term assets 699 708Total assets 966 992

Accounts payable and accrued liabilities 143 91Short-term borrowings and current portion

of long-term debt 13 27Long-term debt 341 336Other long-term liabilities 41 6Total liabilities 538 460

At acquisition, Mazeikiu Nafta had total outstanding debt(excluding debt to our company) of USD 354 million, ofwhich USD 56 million is guaranteed by the Lithuanian gov-ernment and USD 289 million is payable to the Lithuaniangovernment. Mazeikiu Nafta’s debt bears interest at ratesranging from 2.6 percent to 12.0 percent and is payablebetween 2003 and 2009.

The table below shows the increase in our ownership of our principal production and refining subsidiaries for the periods indicated.

(In millions of U.S. Dollars, except for percentage data)

At Year ended At Year ended At

December 31, December 31, December 31, December 31, December 31,

1999 2000 2000 2001 2001

Ownership Cost of Percentage Ownership Cost of Percentage Ownership

Subsidiaries Percentage Purchases Acquired Percentage Purchases Acquired Percentage

Yuganskneftegas 80.6% 31 11.1% 91.7% 49 8.3% 100.0%Samaraneftegas 85.8% 7 9.0% 94.8% 11 5.2% 100.0%Kuibyshev refinery 46.3% 4 48.9% 95.2% 3 4.8% 100.0%Novokuibyshevsk refinery 46.8% 6 44.6% 91.4% 4 8.6% 100.0%Syzran refinery 38.0% 3 56.0% 94.0% 4 6.0% 100.0%Tomskneft:

Direct acquisitions 43.5% 10 10.7% 54.2% 17 2.8% 57.0%Through Eastern Oil 20.3% – 0.5% 20.8% – 2.7% 23.5%Total 63.8% 10 11.2% 75.0% 17 5.5% 80.5%

Achinsk refinery: Direct acquisitions – 2 22.0% 22.0% 25 25.4% 47.4%Through Eastern Oil 20.3% – 0.5% 20.8% – 8.0% 28.8%Total 20.3% 2 22.5% 42.8% 25 33.4% 76.2%

Angarsk Petrochemical Company – 32 19.1% 19.1% 74 80.9% 100.0%East Siberian Oil and Gas Company – 65 68.0% 68.0% 4 2.2% 70.2%Urengoil – – – – 25 50.0% 50.0%Arcticgas – – – – – – –Mazeikiu Nafta – – – – – – –Sakhaneftegas – – – – – – –

2

00

2


Other significant acquisitionsIn addition to the acquisitions of our principal productionand refining subsidiaries described above, we also initi-ated, continued or completed the following significantacquisitions since January 1, 2000.

John Brown Hydrocarbons and Davy Process Technology.In November 2001, we acquired the Hydrocarbons andProcess Technology divisions of Kvaerner, an internationalgroup of engineering and construction companies, forUSD 100 million plus the assumption of certain outstand-ing liabilities of the businesses acquired. Prior to thisacquisition, our Company had substantial contractual rela-tionships with the Hydrocarbons division and, accordingly,had an interest in preserving the level of service it had beenreceiving, despite Kvaerner’s financial uncertainties.Following our acquisition of these divisions, we renamedthe businesses John Brown Hydrocarbons and DavyProcess Technology, which had been their original names.As a result of these acquisitions, we recognized total good-will of USD 128 million. In 2002, we determined thatUSD 50 million of the goodwill associated with John Brown

Hydrocarbons was impaired, and wrote it off to our consol-idated statement of income.

Transpetrol a.s. In April 2002, we acquired a 49 percent inter-est in Transpetrol a.s. (“Transpetrol”), a Slovakian oil pipelineoperator, for USD 74 million. The Slovakian governmentowns the remaining 51 percent interest in Transpetrol. If theSlovakian government decides to sell its interest, we have anoption to acquire an additional 2 percent interest, whichwould give us a majority interest in the company. We accountfor our investment in Transpetrol under the equity method.

ZAO Rospan International. In 2001 and during the first halfof 2002, we acquired, through intermediaries, a 100 per-cent interest in ZAO Rospan International (“Rospan”), adomestic natural gas producer with assets in WesternSiberia for USD 101 million. Further toward strengtheningour position in the bankruptcy process, we also directlypurchased an additional 49 million of Rospan’s outstand-ing liabilities. The excess USD 21 million of purchase costover the fair value of the liabilities acquired was included inour cost of investment in Rospan. In May 2002, 44 percent


Year ended December 31, At December 31,

2002 2002

Cost of Percentage Ownership Date First

Subsidiaries Purchases Acquired Percentage Consolidated(1)

Yuganskneftegas – – 100.0% April 1993 Samaraneftegas – – 100.0% January 1996 Kuibyshev refinery – – 100.0% April 1993Novokuibyshevsk refinery – – 100.0% April 1993 Syzran refinery – – 100.0% April 1993 Tomskneft:

Direct acquisitions – – 57.0%Through Eastern Oil 246 18.2% 41.7%Total 246 18.2% 98.7% July 1999

Achinsk refinery: Direct acquisitions – – 47.4%Through Eastern Oil 10 22.2% 51.0%Total 10 22.2% 98.4% July 2000

Angarsk Petrochemical Company – – 100.0% July 2001 East Siberian Oil and Gas Company – – 70.2% December 2000Urengoil 50 50.0% 100.0% May 2002Arcticgas 274 100.0% 100.0% March 2002 Mazeikiu Nafta 164 53.7% 53.7% September 2002Sakhaneftegas 50 50.4% 50.4% December 2002

(1) We consolidate entities for purposes of U.S. GAAP when we directly or indirectly control more than 50 percent of the entity’s voting shares. In certain cases, our ownership of voting shares dif-

fers from our ownership percentage of total outstanding shares indicated in the table above.

2

00


The following table shows some of the average crude oil and major petroleum products prices that affected our Companyduring the periods indicated:

For the year ended December 31, 2002 2001 Change 2001 2000 Change

International:(1)

(In U.S. Dollars per barrel, except for percentage data)

Brent crude oil 24.98 24.46 2.1% 24.46 28.39 (13.8)%Urals crude oil (CIF Mediterranean)(2) 23.68 22.99 3.0% 22.99 26.53 (13.3)%(In U.S. Dollars per metric ton, except for percentage data)

Fuel oil 128.89 110.93 16.2% 110.93 133.50 (16.9)%Diesel fuel 208.84 219.30 (4.8)% 219.30 257.22 (14.7)%High octane gasoline 243.62 247.09 (1.4)% 247.09 290.27 (14.8)%

Domestic:(3)

Fuel oil 69.53 54.01 28.7% 54.01 71.34 (24.3)%Diesel fuel 191.20 219.32 (12.8)% 219.32 210.52 4.2%Low octane gasoline 202.13 218.99 (7.7)% 218.99 226.22 (3.2)%High octane gasoline 317.41 308.04 3.0% 308.04 289.90 6.3%

(1) Fuel oil, diesel fuel and high octane gasoline data based on Northwest Europe averages.

(2) CIF prices for crude oil include the cost of insurance and freight charges.

(3) Based on Central Russia averages.

Sources: Estimates based on Platts and Kortes.

of the shares of Rospan were sold to Tyumen Oil Company(“TNK”) for USD 44 million. In June 2002, we paid USD 20million to terminate a purchase option granted at acquisi-tion over a portion of its interest in Rospan’s shares. InAugust 2002, we entered into a shareholders agreementwith TNK whereby it was agreed that we and TNK wouldjointly control Rospan. In December 2002, we and TNKagreed that TNK would manage Rospan and, accordingly,we account for our investment in Rospan under the equitymethod. Other acquisition costs related to the purchase ofRospan totaled USD 12 million.

Certain Factors Affecting Our Results of OperationsOur results of operations and the period-to-period changestherein have been and will continue to be affected by vari-ous factors outlined below.

Crude oil and petroleum product pricesOur operations are significantly affected by changes in crude oil and petroleum product prices, both in

international markets and in Russia. These prices areaffected by external factors over which we have no control,such as global economic conditions, demand growth,inventory levels, weather, competing fuel prices and globaland domestic supply.

International prices for crude oil and petroleum productshave been highly volatile, depending on the balance betweensupply and demand and on OPEC production levels.

Historically, crude oil prices in the Russian market havebeen substantially below prices in the international market.Moreover, there is no independent or uniform market pricefor crude oil in Russia primarily because nearly all crude oildestined for sale in Russia is produced by vertically inte-grated Russian oil companies and is refined by the samevertically integrated companies. Crude oil that is notexported from Russia, refined by the producer or otherwisesold is offered for sale in the domestic market at pricesdetermined on a transaction-by-transaction basis.

2

00

2


The crude oil that we sell in international markets has his-torically been traded at a discount to dated Brent. Most ofthe crude oil that we sell in international markets is trans-ported through the Transneft pipeline system in which it isblended with other crude oil of varying qualities to producean export blend commonly referred to as Urals. The crudeoil that we sell in international markets other than throughthe Transneft pipeline system is also of lower quality thanBrent and trades at a discount to the Brent price.

Constraints on the international sale of crude oil and petroleum productsWe transport the crude oil and petroleum products that wesell in international markets by pipeline, rail and sea. Weseek to sell our crude oil in international markets when, asis often the case, market conditions make internationalsales of crude oil more profitable than international salesof petroleum products. The reason for this is that the mar-gins on our petroleum products often do not justify thehigher transportation costs as compared to crude oil.

We transport a substantial portion of the crude oil that we sell in international markets through trunk pipelines in Russia that are controlled by Transneft, which is a state-controlled company. The Russian government isexpected to retain control over Transneft for the foresee-able future. Since September 2001, the Russian govern-ment has allocated pipeline capacity among Russian oilproducers and their parent companies in proportion to thevolumes of oil produced and delivered to the Transneftpipeline system, and not merely in proportion to oil pro-duction levels, as was the case in the past.

Although pipeline capacity in Russia has increased inrecent years, the capacity of the pipeline network still actsas a constraint on exports and indirectly on oil productionin Russia. Currently, there are government-sponsored andprivate programs to improve pipeline capacity.

We also use the Russian rail network to transport the crudeoil and petroleum products that we sell internationally.However, the Russian rail network also has limited capac-ity, and the Russian government may allocate use of theRussian railway system on a preferential basis to domestic

deliveries. Moreover, the system is subject to disruption asa result of its declining physical condition, a shortage ofrailcars, the limited capacity of border stations, spills,including those due to poorly maintained tank cars. Toaddress these concerns, we have been acquiring our ownfleet of railcars which we believe will allow us to transportby rail more of our international crude oil and petroleumproducts sales volumes without encountering some ofthese difficulties.

A significant proportion of crude oil and petroleum prod-ucts transported by pipeline and rail is delivered to marineterminals for onward transportation. There are significantconstraints present in Russia’s oil shipment terminals dueto geographic location, weather conditions and port capac-ity limitations. However, government-sponsored and pri-vate programs are seeking to improve port facilities.

In addition, our ability to sell crude oil internationally maybe constrained by the Russian government and its agen-cies, which need to ensure the availability of sufficient sup-plies of crude oil and petroleum products on the domesticmarket. Although Russia is not a member of OPEC, theRussian government agreed with OPEC to reduce exportsof crude oil through the Transneft pipeline by 150,000 bar-rels per day from the levels in the fourth quarter of 2001through most of the first half of 2002. This voluntary reduc-tion of crude oil exported through the Transneft pipelinewas not extended.

We believe that physical constraints, and constraintsimposed by the Russian government, on our internationalsales of crude oil and petroleum products may continue inthe future.

Transportation costsWe incur transportation costs for the delivery of our crudeoil to our refineries and for the delivery of crude oil andpetroleum products to customers. Transportation costsinclude pipeline, freight, railroad and river tariffs, loadingcosts and port charges. We bear the cost of transportationtariffs to bring our crude oil and petroleum products tomarket. Almost 100 percent of the crude oil that we pro-duce is delivered to the Transneft pipeline system and then

2

00


delivered to customers or to our refineries either solely bythe means of this pipeline system or in combination withtransportation by railway, river, sea or other pipeline.Transneft collects, on prepayment terms, a Ruble tariff ondomestic crude oil shipments and a combined Ruble andhard currency tariff on exports. A significant amount ofpetroleum products are transported using the Transnefte-produkt pipeline system. However, the Transnefteproduktsystem is not as extensive as the Transneft system fortransporting crude oil.

Transportation costs incurred in the delivery of our crudeoil to customers are included as a component of distribu-tion expenses in our consolidated statements of income.Transportation costs incurred in the delivery of our crudeoil to our refineries for processing into petroleum productsare included within operating expenses in our consolidatedstatements of income.

The Russian Federal Energy Commission periodicallyreviews and sets the tariff rates for each segment of theTransneft pipeline and the Transnefteprodukt pipeline. Inaddition, we are subject to tariffs for crude oil and petro-leum products that we transport by railway. Railway tariffsare set by the Russian Federal Energy Commission and theMinistry of Railways. We are also subject to fluctuations incosts for freight delivered by sea for a portion of our inter-national sales. These costs are largely dictated by the shipping markets from which we sell our crude oil andpetroleum products.

Due to pipeline capacity constraints, in 2003 we expect toincrease our usage of railway and sea transportation inorder to meet our expected increase in international sales.This will result in an increase in our average cost of trans-portation, as the cost of transporting crude oil by railwayand sea is significantly higher than through pipelines.Increases in our transportation costs have affected, andpossible future increases could further affect, our results of operations.

Foreign currency exchange rate fluctuations and inflationMost of our revenues are derived from international sales ofcrude oil, which are denominated in U.S. Dollars, and inter-national sales of petroleum products, which are denomi-nated in both U.S. Dollars and Euros. Our operating costsare denominated in U.S. Dollars, Euros, and Rubles.

Accordingly, the relative movements of Ruble inflation andRuble/U.S. Dollar exchange rates can significantly affectour results of operations. In particular, operating marginsare generally adversely affected by a real appreciation of theRuble against the U.S. Dollar (i.e., by an inflation rate thatis higher than the rate at which the Ruble is devaluingagainst the U.S. Dollar) because this will generally causeour costs to increase relative to our revenues. We have nothistorically used financial instruments to hedge againstforeign currency exchange rate fluctuations, as theseinstruments have not been readily available to companiesoperating in Russia.

In addition, because we report in U.S. Dollars, our Ruble-denominated revenues and costs (including, for example,revenues from domestic petroleum product sales) arereported at increased amounts relative to U.S. Dollar-denominated revenues and costs during periods of a realappreciation of the Ruble.

The following table shows the rates of inflation in Russia,the period-end and average Ruble/U.S. Dollar exchangerates, the rates of nominal devaluation of the Ruble againstthe U.S. Dollar, and the rates of real change in the value ofthe Ruble against the U.S. Dollar for the periods indicated.


Ruble inflation 15.1% 18.8% 20.2%U.S. Dollar period-end

exchange rate 31.78 30.14 28.16Average U.S. Dollar

exchange rate 31.35 29.17 28.12Nominal devaluation

of the Ruble 5.4% 7.0% 4.3%Real Ruble appreciation 9.2% 11.0% 15.2%

Sources: Goskomstat and Central Bank of Russia

At present, the Ruble is not a convertible currency outsidethe CIS. Exchange restrictions and controls exist related toconverting Rubles into other currencies. For instance,beginning from the second half of August 2001, we havebeen required to sell 50 percent of our hard currency export proceeds to authorized banks for Rubles. BetweenMarch 1999 and the first half of August 2001, the relatedrequirement was 75 percent. These amounts historicallyhave been subject to certain reductions, such as export andtransportation fees.

2

00

2


The table below sets forth the average tax rates that our Russian subsidiaries were subject to for the years endedDecember 31, 2002 and 2001:

Year ended December 31,

Tax 2002 2001 Change Taxable base

a. Crude oil export duty, average(1) USD 18.6 EUR 29.2 (38.9)%(2) Metric ton exportedb. Petroleum products export duty, average:

Light distilled products (gasoline products) EUR 30.0 EUR 38.7 (22.5)% Metric ton exportedMid distilled products (diesel fuel) EUR 30.0 EUR 38.7 (22.5)% Metric ton exportedFuel oil EUR 15.1 EUR 24.4 (38.1)% Metric ton exported

c. Crude oil excise tax(3) – RR 66 (100.0)% Metric ton produced and soldd. Petroleum products excise tax:

High octane gasoline RR 2,072 RR 1,850 12.0% Metric ton produced and sold domesticallyLow octane gasoline RR 1,512 RR 1,350 12.0% Metric ton produced and sold domesticallyDiesel fuel RR 616 RR 550 12.0% Metric ton produced and sold domesticallyMotor oil RR 1,680 RR 1,500 12.0% Metric ton produced and sold domestically

e. Mineral restoration tax(3) – 10% (100.0)% Sales revenues(4)

f. Royalty tax(3) – 6–16% (100.0)% Sales revenues(4)

g. Unified production tax(3) RR 668 – 100.0% Metric ton produced (crude oil)h. VAT 20% 20% – Added valuei. Road users tax 1% 1% – Net revenuesj. Profit tax (corporate) – maximum rate 24% 35% (31.4)% Taxable income

(1) Beginning January 1, 2002, crude oil export duty rates began to be denominated in U.S. Dollars. Prior to January 1, 2002, crude oil export duty rates were denominated in Euros.

(2) Calculated using the Euro/U.S. Dollar exchange rate as of December 31, 2002.

(3) The crude oil excise tax, mineral restoration tax and royalty tax were replaced on January 1, 2002 by the unified production tax. 6 –16 percent represents the minimum and maximum

rates applicable.

TaxationWe are subject to numerous taxes that have had a signifi-cant effect on our results of operations. Russian tax legisla-tion is and has been subject to varying interpretations andfrequent changes.

Through December 31, 2000, we were subject to income taxat a maximum statutory rate of 30 percent. In August 2000,the Federal Law on Income Tax for Companies was amended,establishing the maximum statutory income tax rate of 35 percent in most jurisdictions effective January 1, 2001.

In August 2001, the Russian Tax Code was amended. As aresult of this amendment, which became effective onJanuary 1, 2002, two new chapters of the Russian Tax Codewere introduced that affected our results of operations.Under the first of these chapters, the maximum income taxrate for income received from ordinary activities wasreduced from 35 percent to 24 percent, the tax rate for divi-dends received from domestic companies was reduced

from 15 percent to 6 percent and the tax rate for dividendsreceived from foreign companies was reduced from 35 per-cent to 15 percent. However, investment tax credits thatcould be used to reduce income tax by up to 50 percenthave been abolished.

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

• a unified natural resources production tax;• export duties;• excise taxes on petroleum products;• road users taxes;• property taxes; • other local taxes and levies; and• tax penalties and interest.

These taxes are reflected in taxes other than income tax inour consolidated statements of income. In addition, we aresubject to payroll-based taxes, which are included as salarycosts within selling, general and administrative expensesor operating expenses, as appropriate.

2

00


Prior to January 1, 2002, we were subject to mineral restora-tion and royalty taxes at average effective rates of approxi-mately 6 percent and 8 percent, respectively, of oil and gasrevenues recognized under Russian accounting regula-tions by our production subsidiaries and excise taxes oncrude oil production of approximately USD 0.30 per barrelat the December 31, 2001 exchange rate. Under the secondchapter of the Russian Tax Code, the mineral restorationtax, royalty tax and excise tax on crude oil production wereabolished and replaced by the unified production tax. Inthe year ended December 31, 2002, our unified productiontax expense was USD 1,478 million. Total mineral restora-tion tax, royalty tax and excise taxes on crude oil for the yearended December 31, 2001 were USD 537 million. ThroughDecember 31, 2004, the base rate for the unified produc-tion tax is set at 340 Rubles per metric ton of crude oil pro-duced (USD 1.46 per barrel at the December 31, 2002exchange rate) and is to be adjusted depending on the

market price of Urals blend and the Ruble exchange rate.The tax becomes zero if the Urals blend price falls to orbelow USD 8.00 per barrel. For the year ended December 31,2002, the average rate for the unified production tax, basedon the Urals blend market price and Ruble exchange rates,was 668 Rubles per metric ton of crude oil produced. AtDecember 31, 2002, the effective statutory rate for the uni-fied production tax was 753 Rubles per metric ton. FromJanuary 1, 2005, the unified production tax rate is set by lawat 16.5 percent of crude oil revenues recognized by theexploration and production companies in our Group basedon Russian accounting regulations.

Maximum rates of export duties for crude oil were estab-lished by Russian Federal Law #126-FZ dated August 8,2001 and have been effective since February 1, 2002. Themaximum rates depend on lagged average Urals blendprices. The rates start at zero when the lagged Urals blend

The table below sets forth the average tax rates that our Russian subsidiaries were subject to for the years endedDecember 31, 2001 and 2000:

Year ended December 31,

Tax 2001 2000 Change Taxable base

a. Crude oil export duty, average EUR 29.2 EUR 22.7 28.6% Metric ton exportedb. Petroleum products export duty, average:

Light distilled products (gasoline products) EUR 38.7 EUR 22.3 73.5% Metric ton exportedMid distilled products (diesel fuel) EUR 38.7 EUR 17.4 122.4% Metric ton exportedFuel oil EUR 24.4 EUR 16.2 50.6% Metric ton exported

c. Crude oil excise tax(1) RR 66 RR 55 20.0% Metric ton produced and soldd. Petroleum products excise tax:

High octane gasoline RR 1,850 RR 585 216.2% Metric ton produced and sold domesticallyLow octane gasoline RR 1,350 RR 455 196.7% Metric ton produced and sold domesticallyDiesel fuel RR 550 – 100.0% Metric ton produced and sold domesticallyMotor oil RR 1,500 – 100.0% Metric ton produced and sold domestically

e. Mineral restoration tax(1) 10% 10% – Sales revenues(2)

f. Royalty tax(1) 6–16% 6–16% – Sales revenues(2)

g. VAT 20% 20% – Added valueh. Fuel tax – 25% (100.0)% Net revenues of gasoline, diesel fuel and

some other productsi. Road users tax 1% 2.5% (60.0)% Net revenuesj. Profit tax (corporate) – maximum rate 35% 30% 16.7% Taxable incomek. Housing tax – 1.5% (100.0)% Net revenues

(1) The crude oil excise tax, mineral restoration tax and royalty tax were replaced on January 1, 2002 by the unified production tax. 6 –16 percent 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.

2

00

2


price is at or below USD 15.00 per barrel. They thenincrease by USD 0.35 per barrel for each USD 1.00 increasein the lagged Urals blend price when the lagged Uralsblend price is between USD 15.00 and USD 25.00 per bar-rel, and by USD 0.40 per barrel for each USD 1.00 increasein the lagged Urals blend price when the lagged Uralsblend price is above USD 25.00 per barrel.

Recent amendments to the Russian export legislation pro-vide that, effective from January 1, 2003, export duties onpetroleum products are limited to 90 percent of the exportduties on crude oil.

Prior to January 1, 2001, we were subject to fuel tax equal to25 percent of net revenues from gasoline and diesel fuelsales. Beginning January 1, 2001, the excise tax on gasolinewas increased and we were subject to excise tax on diesel fuel, motor oil and lubricants. Commencing on January 1, 2002, the effective excise tax rates were 1,512 Rubles per metric ton for gasoline with octane ratings of 80 or lower,2,072 Rubles per metric ton for gasoline with octane rat-ings above 80, 616 Rubles per metric ton for diesel fuel and1,680 Rubles per metric ton for motor oil. Commencing on January 1, 2003, the effective excise tax rates are2,190 Rubles per metric ton for gasoline with octane ratingsof 80 or lower, 3,000 Rubles per metric ton for gasoline withoctane ratings above 80, 890 Rubles per metric ton fordiesel fuel and 2,440 Rubles per metric ton for motor oil.

We also are subject to value added tax, or VAT, of 20 percenton most of our purchases. These taxes are recoverableagainst VAT received on domestic sales. Export sales, otherthan to some CIS countries, are subject to 0 percent VAT.Input VAT related to export sales is recoverable from theRussian government. Our results of operations exclude theimpact of VAT.

We provide for taxes on unremitted earnings of our foreignsubsidiaries that are payable upon distribution to the par-ent company through our existing legal structure if theretained earnings of our foreign subsidiaries are not con-sidered permanently invested. We continuously assess

possible methods of transferring the earnings to YUKOSOil Company and adjust this provision accordingly. Suchtaxes are recognized at enacted rates corresponding to themethod we intend to utilize to distribute or transfer theunremitted earnings to YUKOS Oil Company. In the fourthquarter of 2002, we recorded a USD 368 million reductionin deferred tax liabilities that resulted from our revised estimate of the applicable tax rates associated with theexpected remittances of earnings from certain subsidiaries.In conjunction with with our ongoing review of tax strategywe believe that we can reduce the Company’s effective taxrate on such remittances by 5 percent.

The maximum enacted statutory profits or income tax ratesin Russia during the years ended December 31, 2002, 2001and 2000 were 24 percent, 35 percent and 30 percent,respectively. Our effective tax rate is affected significantlyby enacted rates in the several tax jurisdictions both withinRussia and internationally where we have operations. Manyof the companies in our consolidated Group are resident intax jurisdictions in Russia and internationally where statu-tory tax rates are lower than the statutory maximum inRussia or where we benefit from regional tax incentives. Asa result of these lower tax rates and incentives, our incometaxes were reduced by USD 745 million, USD 828 millionand USD 854 million for the years ended December 31,2002, 2001 and 2000, respectively, compared to the statu-tory maximum in Russia. In addition, several other factorshave had a significant impact in reducing our effective taxrate during these years, including the investment tax credit.Factors that have increased our effective tax rate for theyears ended December 31, 2002, 2001 and 2000 includeddeferred taxes provided for unremitted earnings of consoli-dated subsidiaries and expenses that were not deductiblefor Russian tax purposes.

The availability in Russia of the lower statutory tax ratesand regional tax incentives varies by jurisdiction. For exam-ple, regional and local profit tax concessions granted tosome of the companies in our consolidated Group will bephased out by mid-2006. We are unable to estimate thelikelihood of extension of these benefits. In addition, effec-tive January 1, 2002, the investment tax credit has been

2

00




USD % USD % USD %

Consolidated Statement of Income

Sales and other operating revenues 11,373 100.0 9,461 100.0 9,032 100.0Operating costs and other deductions Crude oil and petroleum products purchased 340 3.0 481 5.1 662 7.3Operating expenses 1,479 13.0 1,182 12.5 872 9.7Distribution expenses 1,514 13.3 1,048 11.1 697 7.7Selling, general and administrative expenses 835 7.3 671 7.1 562 6.2Depreciation, depletion and amortization 459 4.0 270 2.9 218 2.4Taxes other than income tax 3,087 27.1 2,075 21.9 1,246 13.8Write-offs of property and investments 39 0.3 48 0.5 52 0.6Goodwill impairment 50 0.4 – – – –Exploration expenses 87 0.8 52 0.5 35 0.4Total operating costs and other deductions 7,890 69.4 5,827 61.6 4,344 48.1Other income (expenses)Realized gains on marketable securities, net 46 0.4 128 1.4 165 1.8Income from equity affiliates 29 0.3 7 0.1 15 0.2Other income, net 101 0.9 3 0.0 67 0.7Interest income 333 2.9 309 3.3 132 1.5Interest expense (64) (0.6) (45) (0.5) (160) (1.8)Exchange gains (losses), net (118) (1.0) (170) (1.8) 43 0.5Total other income, net 327 2.9 232 2.5 262 2.9Income before income tax and minority interest 3,810 33.5 3,866 40.9 4,950 54.8Income taxCurrent income tax expense 490 4.3 598 6.3 612 6.8Deferred income tax expense 256 2.3 104 1.1 595 6.6Total income tax expense 746 6.6 702 7.4 1,207 13.4Income before minority interest 3,064 26.9 3,164 33.5 3,743 41.4Minority interest (6) (0.0) (8) (0.1) (19) (0.2)Net income 3,058 26.9 3,156 33.4 3,724 41.2

abolished. If we do not find other ways of reducing oureffective income tax rate, our effective income tax rate onour domestic earnings will approach the statutory maxi-mum in the future, although the tax rate has now beenreduced to 24 percent. In addition, any changes in tax lawsin foreign countries where we have subsidiaries will affectour tax efficiency.

In the context of the significant regulatory changes relatedto Russia’s transition from a centrally planned to a marketeconomy over the past 10 years and the general instabilityof the new market institutions introduced in connectionwith this transition, taxes, tax rates and implementation oftaxation 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 the financial per-formance of our Company. In addition, uncertainty relatedto Russian tax laws exposes us to enforcement measuresand the risk of significant fines and could result in a greaterthan expected tax burden.

Results of OperationsThe following table shows certain consolidated state-ment of income data for the periods indicated, and alsoin each case as a percentage of our sales and other oper-ating revenues.

Certain reclassifications have been made to amounts previ-ously reported in our condensed consolidated interimfinancial statements. There was no impact on net incomeas a result of these reclassifications.

2

00

2


EBITDA is net income before income tax expense, interestexpense and depreciation, depletion and amortizationexpense, as shown in the following table.


Net income 3,058 3,156 3,724Income tax expense 746 702 1,207Interest expense 64 45 160Interest income (333) (309) (132)Depreciation, depletion and

amortization expense 459 270 218EBITDA 3,994 3,864 5,177

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001Crude oil productionOur crude oil production increased by 19.3 percent to69.5 million metric tons (508 million barrels) in 2002 from58.2 million metric tons (426 million barrels) in 2001. Ourgas production increased by 40.0 percent to 2,388 millioncubic meters in 2002 from 1,706 million cubic meters in2001. The primary reason for the production growth is con-tinuing exploration and development activities in our prin-cipal production subsidiaries, with an insignificant part ofthis growth attributed to the production of subsidiariesacquired during 2002.

RefiningWe increased refining throughput by 14.3 percent to32.9 million metric tons (241 million barrels) in 2002 from28.8 million metric tons (211 million barrels) in 2001. The

light product yield at our refineries was 58.79 percent in2002 compared to 58.10 percent in 2001. Approximately1.8 million metric tons (13 million barrels) of the increase inrefining throughput and the increase in light product yieldis attributable to the refining throughput of Mazeikiu Naftafor the fourth quarter of 2002.

RevenuesOur total sales and other operating revenues wereUSD 11,373 million in 2002, an increase of 20.2 percentfrom USD 9,461 million in 2001. The change resulted froma combination of higher production and higher prices, off-set slightly by lower third party purchases. Total sales vol-umes of crude oil and petroleum products increased by20.0 percent and 15.9 percent, respectively, compared to 2001.

The following table shows our average realized crude oiland petroleum products prices for 2002 and 2001. Theseprices can differ from quoted crude oil and petroleumproducts prices reported by information agencies due to anumber of factors, including:

• the effects of uneven volume distributions during the period;• different sales and delivery terms compared to quoted

benchmarks;• different conditions in local markets; • discounts or premiums related to quality, volume and

time frame; and • other terms and conditions of individual sales contracts

compared to standard terms.

The following table shows certain key business and financial indicators.

Year ended December 31, 2002 2001 Change 2001 2000 Change

Crude oil production (Millions of metric tons) 69.5 58.2 19.3% 58.2 49.5 17.5%Crude oil production (Millions of barrels) 508 426 19.3% 426 362 17.5%Refining throughput (Millions of metric tons)(1) 32.9 28.8 14.3% 28.8 26.7 8.1%Refining throughput (Millions of barrels)(1) 241 211 14.3% 211 195 8.1%EBITDA (see below) 3,994 3,864 3.4% 3,864 5,177 (25.4)%Net profit margin 26.9% 33.4% (19.4)% 33.4% 41.2% (19.1)%Operating cash flow 2,967 3,114 (4.7)% 3,114 3,310 (5.9)%Basic earnings per share (U.S. Dollars per share) 1.42 1.47 (3.4)% 1.47 1.68 (12.5)%Diluted earnings per share (U.S. Dollars per share) 1.41 1.47 (4.1)% 1.47 1.68 (12.5)%

(1) The results of operations of Angarsk Petrochemical Company were included in our consolidated financial statements starting from July 2001, and the results of operations of Achinsk refinery

were included in our consolidated financial statements since July 2000. Volumes of our crude oil refined by these companies on processing terms in 2001 and 2000 were included in our total

refinery throughputs.

2

00


(U.S. Dollars per barrel)

Year ended December 31, 2002 2001 Change

International sales – crude oil 22.98 22.43 2.5%Non-CIS 23.69 22.60 4.8%CIS 12.11 13.99 (13.4)%

Domestic sales – crude oil 6.73 8.79 (23.4)%

(U.S. Dollars per metric ton)

International sales – petroleum products 186.64 171.34 8.9%

Domestic sales – petroleum products 138.29 149.31 (7.4)%

The following table shows the volumes of crude oil andpetroleum products that we sold in 2002 and 2001.

(In millions of barrels)


International sales – crude oil 259.3 220.3 17.7%Non-CIS 243.3 215.9 12.7%CIS 16.0 4.4 261.2%

Domestic sales – crude oil 12.7 6.3 103.7%Total 272.0 226.6 20.0%

(In thousands of metric tons)

International sales – petroleum products 12,266 9,875 24.2%

Domestic sales – petroleum products 18,670 16,811 11.1%

Total 30,936 26,686 15.9%

The following table shows our revenues from sales of crudeoil and petroleum products in 2002 and 2001.

(In millions of U.S. Dollars)


International sales – crude oil 5,958 4,942 20.6%Non-CIS 5,765 4,880 18.1%CIS 193 62 212.7%

Domestic sales – crude oil 86 55 56.1%Total 6,044 4,997 21.0%International sales –

petroleum products 2,289 1,692 35.3%Domestic sales –

petroleum products 2,582 2,510 2.9%Total 4,871 4,202 15.9%

We produced substantially all of the crude oil and petroleumproducts that we sold in 2002 and 2001, but we also sold asmall amount of crude oil and petroleum products that we purchased from third parties. In 2002, we purchased14.1 million barrels of crude oil and 0.6 million metric tons

of petroleum products, and in 2001, we purchased 20.5 mil-lion barrels of crude oil and 1 million metric tons of petro-leum products. See “Operating costs and other deduc-tions – Crude oil and petroleum products purchased.”

International sales of crude oil – non-CIS countries.Revenues from international sales of crude oil to non-CIScountries were USD 5,765 million in 2002 compared toUSD 4,880 million in 2001, an increase of USD 885 million,or 18.1 percent. This increase reflects an increase in aver-age realized prices of 4.8 percent combined with anincrease in volumes of 12.7 percent when compared to2001. The increase in our average realized price by 4.8 per-cent was mainly driven by increase in world oil marketprices, such as the increase in Urals (CIF Mediterranean)crude oil prices by 3.0 percent. The increase in interna-tional crude oil sales volumes was supported by increasedproduction of 19.3 percent and by increased utilisation ofcrude oil railway transportation.

International sales of crude oil – CIS countries. Revenuesfrom international sales of crude oil to CIS countries wereUSD 193 million in 2002 compared to USD 62 million in2001, an increase of USD 131 million, or 212.7 percent. Thisincrease was primarily due to a 261.2 percent increase insales volume, which was partially offset by a 13.4 percentdecrease in average realized prices. The Russian govern-ment’s restriction on crude oil exports during the first halfof 2002 was not extended to exports to CIS countries.Consequently, we sold a portion of our crude oil to CIS coun-tries that we otherwise would have sold to non-CIS countries. This increased supply of crude oil to CIS coun-tries led to a decrease in crude oil market prices in thesecountries and, consequently, to a decrease in our averagerealized prices on such sales.

Domestic sales of crude oil. We generally seek to sell crudeoil in international markets or refine crude oil and to sellrelatively small quantities of crude oil in Russia. Revenuesfrom domestic crude oil sales were USD 86 million in 2002compared to USD 55 million in 2001, an increase of USD 31million, or 56.1 percent. This increase was primarily due toconstraints imposed in the first half of 2002 by the Russiangovernment on crude oil exports outside of the CISthrough the Transneft pipeline system in response toOPEC demands and higher crude oil production volumesin this period.

2

00

2


International sales of petroleum products. Revenues from international sales of petroleum products wereUSD 2,289 million in 2002 compared to USD 1,692 millionin 2001, an increase of USD 597 million, or 35.3 percent,driven primarily by a 24.2 percent increase in internationalpetroleum products sales volumes. In addition, averagerealized prices increased by 8.9 percent, primarily as a resultof higher prices on fuel oil, partially offset by lower prices ondiesel fuel.

Domestic sales of petroleum products. Revenues fromdomestic sales of petroleum products were USD 2,582 mil-lion in 2002 compared to USD 2,510 million in 2001, anincrease of USD 72 million, or 2.9 percent. This increase ofsales was due to an increase in sales volumes by 11.1 per-cent, which was partially offset by a decrease in averagerealized prices by 7.4 percent. Both the increase in salesvolumes and the decrease in average realized prices werethe result of the Russian government’s restriction on crudeoil exports during the first half of 2002.

Operating costs and other deductionsCrude oil and petroleum products purchased. Purchases ofcrude oil and petroleum products were USD 340 million in2002 compared to USD 481 million in 2001, a decrease ofUSD 141 million or 29.3 percent. Purchases of crude oil andpetroleum products are variable based upon marketdemands and our available supply in a given geographicarea. While a portion of this decrease can be explained byour increased production, this amount has varied and willcontinue to vary based upon regional market forces.

Operating expenses. Operating expenses consist primarilyof direct operating costs associated with crude oil extrac-tion and the refining of crude oil into petroleum products.Operating expenses also include costs of crude oil trans-portation to our refineries for processing as well as costsassociated with other operating revenues. Operatingexpenses were USD 1,479 million in 2002 compared toUSD 1,182 million in 2001, an increase of USD 297 million,or 25.1 percent.

Operating expenses of our Exploration and Production seg-ment increased by USD 159 million or by 19.1 percent toUSD 993 million in 2002 from USD 834 million in 2001. Thisincrease was primarily due to the acquisitions of John Brown

Hydrocarbons and Davy Process Technology (October 2001)and Arcticgas (March 2002), which together contributedapproximately USD 94 million to the increase. The remain-ing increase of USD 65 million or 7.8 percent was mainly theresult of our increase in production by 19.3 percent, offset byimprovements in production efficiency.

Operating expenses of our Refining and Marketing seg-ment increased by USD 179 million or by 51.4 percent toUSD 527 million from USD 348 million. This increase wasprimarily due to a USD 89 million increase in the costs oftransportation of crude oil to our refineries. Transportationcosts increased due to increases in Transneft tariffs ondomestic deliveries, increases in the refining throughput ofour Russian refineries, and costs of transportation of crudeoil to our Mazeikiu Nafta refinery during the fourth quarterof 2002. In addition, operating costs at Mazeikiu Nafta forthe fourth quarter of 2002 contributed USD 24 million to the increased operating expenses. The remainingUSD 66 million was due to increases in certain refiningcosts, such as electricity and salary expenses, andincreased throughput at our Russian refineries.

Operating expenses of our Corporate and Other segmentincreased to USD 76 million in 2002 from nil in 2001. This increase was due to the acquisition of Kopeika inMay 2002.

Distribution expenses. We incur transportation costs forthe delivery of our crude oil to our refineries and for thedelivery of crude oil and petroleum products to final cus-tomers. Transportation costs includes pipeline, freight,railroad and river tariffs, loading costs and port charges. Asdiscussed above, transportation costs incurred in the deliv-ery of our crude oil to our refineries for processing intopetroleum products are included within operatingexpenses in our consolidated statements of income. Othertransportation costs are included within distributionexpenses in our consolidated statements of income.Transportation costs, whether they are included in operat-ing expenses or in distribution expenses, are wholly attrib-uted to our Refining and Marketing segment.

Distribution expenses were USD 1,514 million in 2002 compared to USD 1,048 million in 2001, an increase ofUSD 466 million, or 44.5 percent. During 2002, we

2

00


increased our usage of railways to sell our crude oil produc-tion in international markets, partially to overcome restric-tions on sales of crude oil outside of CIS countries throughTransneft and partially to develop new markets. Thisresulted in an increase in our average cost of transpor-tation, as the costs of transporting crude oil by railway aresignificantly higher than through pipelines. Our increasedrailway usage increased our distribution costs by approxi-mately 17 percent in 2002 compared to 2001. This factor,combined with an increase in production volumes by19.3 percent and tariff increases for petroleum productstransport through the trunk pipeline of Transnefteprodukt, astate owned company, caused the increases in our distribu-tion expenses.

Selling, general and administrative expenses. Selling, gen-eral and administrative expenses increased by USD 164million or by 24.4 percent to USD 835 million in 2002 fromUSD 671 million in 2001.

Selling, general and administrative expenses of the Explora-tion and Production segment increased by USD 82 millionor by 48.8 percent to USD 250 million in 2002 fromUSD 168 million in 2001. Selling, general and administra-tive expenses of John Brown Hydrocarbons (October 2001),Davy Process Technology (October 2001), and Arcticgas(March 2002) contributed USD 36 million to this increase.The remaining increase was primarily due to a number ofnon-cash charges such as inventory and bad debt provi-sions, and the increase in production levels, partly offset bya credit due to a reduction in the reserve for legal liabilities.

Selling, general and administrative expenses of the Refiningand Marketing segment increased by USD 55 million or by 27.0 percent to USD 259 million in 2002 fromUSD 204 million in 2001. Selling, general and administra-tive expenses of recently acquired companies, such as theAngarsk refinery (July 2001) and Mazeikiu Nafta(September 2002), contributed USD 40 million to thisincrease. The remaining increase was primarily due to thesignificant growth of our retail network of gas stations.

Selling, general and administrative expenses of the Cor-porate and Other segment increased by USD 27 million or

by 9.0 percent to USD 326 million in 2002 from USD 299million in 2001. Selling, general and administrativeexpenses for 2001 included USD 68 million of expenserelated to retired, fully vested beneficiaries under theVeteran Social Support Program, for which there are noexpenses recognized during 2002 as they were fullyaccrued during 2001. Excluding the expenses under theVeteran Social Support Program, selling, general andadministrative expenses of the Corporate and Other segmentincreased by USD 95 million. Selling, general and adminis-trative expenses of recently acquired companies, such asKopeika (May 2002), contributed USD 8 million to thisincrease. Non-cash write-offs of certain balances deter-mined to be impaired contributed approximately USD 41million to the increase. Significant increases in selling, gen-eral and administrative expenses in 2002 include increasein salaries and performance bonuses, consulting and legalfees, and expenses for the investigation of internationaland domestic acquisitions and strategic investments.

Certain elements of selling, general and administrativeexpenses, such as expenses related to our acquisition activityand performance bonuses, are either activity based or highlyvariable and have, and will continue to have varying impactson our overall selling, general and administrative expenses.

Depreciation, depletion and amortization. Depreciation,depletion and amortization expense in 2002 was USD 459million compared to USD 270 million in 2001, an increaseof USD 189 million, or 70.0 percent. During 2002 and2001, we invested USD 1,282 million and USD 893 million,respectively, in property, plant and equipment, excludingacquisitions. These additional investments, combined withacquisitions and higher production volumes, contributedto the increase of depreciation, depletion and amortizationexpense in 2002 compared to 2001.

Our Exploration and Production depreciation, depletionand amortization was USD 408 million in 2002 comparedto USD 240 million in 2001, an increase of USD 168 mil-lion, or 70.0 percent. This increase was primarily due toadditions of new assets and higher production, whichresulted in a higher depletion rate.

2

00

2


Our Refining and Marketing depreciation, depletion andamortization was USD 27 million in 2002 compared toUSD 22 million in the same period of 2001. This increase ofUSD 5 million or 22.7 percent was primarily a result of theacquisition of Mazeikiu Nafta in September 2002.

Taxes other than income tax. Taxes other than income tax were USD 3,087 mill ion in 2002 compared toUSD 2,075 million in 2001, an increase of USD 1,012 mil-lion, or 48.8 percent. This increase was primarily due to theintroduction of the unified production tax, which replacedroyalty taxes, mineral restoration tax and excise taxes oncrude oil production. In the year ended December 31, 2002,our unified production tax expense was USD 1,478 million.Total mineral restoration tax, royalty tax and excise taxes on crude oil for the year ended December 31, 2001 wereUSD 537 million.

Other incomeRealized gains on marketable securities, net. Net realizedgains on marketable securities were USD 46 million in2002 compared to USD 128 million in 2001, a decrease ofUSD 82 million or 64.1 percent. The amount of realizedgains and losses on marketable securities depends to alarge extent on the timing and volume of marketable secu-rities disposals, as well as on specific market conditions atthe times that transactions are effected. Accordingly, ourrealized gains and losses on marketable securities varyfrom period to period and we expect to continue to seesuch variances in the future.

Interest income (expense). Interest income increased toUSD 333 million in 2002 compared to USD 309 million in2001, primarily as a result of higher cash balances held in2002, partially offset by the disposal of certain high yieldinvestments. Interest expense increased to USD 64 millionin 2002 compared to USD 45 million in the 2001, mainly asa result of interest accrued on debt of Mazeikiu Nafta dur-ing the fourth quarter of 2002, expense on accretion of dis-count on certain tax and other long-term liabilities, andinterest on issued trade notes.

Income taxesOur total income tax expense was USD 746 million in 2002compared to USD 702 million in 2001, an increase ofUSD 44 million, or 6.3 percent, while our income beforeincome tax and minority interest decreased to USD 3,810mill ion in 2002 from USD 3,866 mill ion in 2001.Reconciliation of our theoretical tax expense to actual taxexpense is provided in Note 14 to the consolidated finan-cial statements.

We provide for taxes on unremitted earnings of our foreignsubsidiaries that are payable upon distribution to the parentcompany through our existing legal structure if the retainedearnings of our subsidiaries are not considered perma-nently invested. Such provisions are adjusted from time totime based upon changes in our legal structure, changes intax rates or changes in intended methods of remitting theearnings available to us under enacted tax legislation. In thefourth quarter of 2002, we recorded a USD 368 millionreduction in deferred tax liabilities, which resulted from ourrevised estimate of the applicable tax rates associated withthe expected remittance of earnings from certain sub-sidiaries. In conjunction with our ongoing review of taxstrategy we believe that we can reduce the Company’s effec-tive tax rate on such remittances by 5 percent.

Our effective income tax rate in 2002 was 19.6 percent.This rate is lower than the statutory maximum rate for theRussian Federation primarily because of the lower tax ratesfor certain subsidiaries in several tax jurisdictions bothwithin Russia and internationally and the reduction indeferred tax liabilities discussed above, offset by deferredtaxes on unremitted earnings of our subsidiaries.

Our effective income tax rate in 2001 was 18.2 percent. In2001, we recognized a USD 525 million deferred tax credit resulting from a change in the tax code of the RussianFederation. This change, combined with the lower tax ratesfor certain subsidiaries and offset by deferred taxes onunremitted earnings contributed to the variance from thestatutory maximum rate.

2

00


Cost per barrel Below is an analysis of our production and refining costsper barrel.



Production:Lifting expenses(1) 1.47 1.78 (17.4)%General and administrative

expenses(1) 0.38 0.33 15.2%Total taxes other than

income tax 3.01 1.48 103.4% Depreciation, depletion

and amortization 0.78 0.55 41.8% Total cost per barrel – production 5.64 4.14 36.2%

Refining: Operating expenses 1.11 0.98 13.3%Total taxes other than

income tax 2.00 1.73 15.6%Depreciation, depletion

and amortization 0.12 0.08 50.0% Total cost per barrel – refining 3.23 2.79 15.8%

(1) Lifting and general and administrative expenses directly related to oil and gas production and

incurred by our oil and gas producing subsidiaries (including compensation expenses

incurred as a result of the Veteran Social Support Program); lifting expenses are consistent

with the information disclosed in the results of oil and gas operations section of the

Supplemental Oil and Gas Information disclosure in the consolidated financial statements,

and exclude costs incurred in conjunction with services rendered to third parties, goods pro-

duced or purchased and then subsequently sold and other auxiliary activities of our

Exploration and Production segment unrelated to the extraction or treatment of our oil and

gas reserves.

Our direct operating costs for crude oil extraction averagedUSD 1.47 per barrel in 2002 compared to USD 1.78 per bar-rel in 2001, representing a 17.4 percent decrease. Thedecline of lifting costs in 2002 compared to 2001 occurredprimarily as a result of improved production efficiency dueto production growth, reduction of the number of activewells, improvement of water cut through sophisticatedreservoir management, headcount reduction, improve-ment of procurement and other efficiency improvements.

The increase in total taxes other than income tax per barrelof produced oil was primarily the result of the introductionof the unified production tax, which replaced royalty taxes,mineral restoration tax and excise taxes on crude oil pro-duction. In 2002, the effective unified production tax ratewas USD 21.31 per metric ton, or USD 2.92 per barrel. Theeffective aggregate tax rate for royalty, mineral restorationand excise on production was USD 9.29 per metric ton, orUSD 1.27 per barrel, in 2001.

The increase in the depreciation expense per barrel of pro-duced crude oil was primarily the result of continued signif-icant investments in the development of oil fields.

Our operating expenses for crude oil refining increaseddue to increases in certain production costs of our Russianrefineries, such as electricity and salary expenses. Ouracquisition of Mazeikiu Nafta in September 2002 also con-tributed approximately USD 0.04 to the increase in operat-ing expenses per barrel because the cost structure ofMazeikiu Nafta is significantly higher than that of ourRussian refineries.

The increase in our taxes other than income taxes per bar-rel of refined crude oil was also primarily due to the acquisi-tion of Mazeikiu Nafta, which is subject to higher excise taxrates than our Russian refineries. The increase in ourdepreciation per barrel of refined crude oil was also primar-ily due to the acquisition of Mazeikiu Nafta, which hashigher carrying value of property, plant and equipmentthan our Russian refineries.

Year Ended December 31, 2001 Compared to Year EndedDecember 31, 2000RevenuesOur total sales and other operating revenues were USD 9,461million in 2001, an increase of 4.7 percent from USD 9,032million reported in 2000. The change was primarily due to anincrease in crude oil and petroleum products sales volumessupported by an increase in production, partially offset by adecrease in world oil prices. During 2001, our total sales vol-umes of crude oil and petroleum products increased 19.2 per-cent and 9.1 percent, respectively, compared to 2000. Theseincreases were primarily due to increased production.

The following table shows our average realized crude oiland petroleum products prices for 2001 and 2000.



International sales – crude oil 22.43 26.05 (13.9)%Non-CIS 22.60 26.17 (13.6)%CIS 13.99 19.22 (27.2)%

Domestic sales – crude oil 8.79 11.83 (25.7)%

(U.S. Dollars per metric ton)

International sales – petroleum products 171.34 192.94 (11.2)%

Domestic sales – petroleum products 149.31 148.03 0.9%

2

00

2


The following table shows the volumes of crude oil andpetroleum products that we sold in 2001 and 2000.

(In millions of barrels)


International sales – crude oil 220.3 178.1 23.7%Non-CIS 215.9 175.0 23.4%CIS 4.4 3.1 44.0%

Domestic sales – crude oil 6.3 12.0 (47.5)%Total 226.6 190.1 19.2%

(In thousands of metric tons)


Domestic sales – petroleum products 16,811 16,963 (0.9)%

Total 26,686 24,468 9.1%

The following table shows our revenues from sales of crudeoil and petroleum products in 2001 and 2000.



International sales – crude oil 4,942 4,639 6.5%Non-CIS 4,880 4,580 6.6%CIS 62 59 4.9%

Domestic sales – crude oil 55 142 (61.3)%Total 4,997 4,781 4.5%


Domestic sales – petroleum products 2,510 2,511 0.0%

Total 4,202 3,959 6.1%

We produced substantially all of the crude oil and petro-leum products that we sold in 2001 and 2000, but we alsosold crude oil and petroleum products that we purchasedfrom third parties. In 2001, we purchased 20.5 million bar-rels of crude oil and 1 million metric tons of petroleumproducts, and in 2000, we purchased 26.3 million barrelsof crude oil and 0.9 million metric tons of petroleum prod-ucts. See “Operating costs and other deductions – Crudeoil and petroleum products purchased.”

International sales of crude oil – non-CIS countries.Revenues from international sales of crude oil to non-CIScountries were USD 4,880 million in 2001 compared toUSD 4,580 million in 2000, an increase of USD 300 mil-lion, or 6.6 percent. This increase was primarily due to a23.4 percent increase in our international crude oil sales

volumes, offset by a 13.6 percent decrease in crude oilprices. The increase in the volume of crude oil sold to non-CIS countries was primarily due to an increase in our salesto Europe (by 30 million barrels) and to Asia (by 7 millionbarrels), primarily China.

International sales of crude oil – CIS countries. Revenuesfrom international sales of crude oil to CIS countries wereUSD 62 million in 2001 compared to USD 59 million in2000, an increase of USD 3 million, or 4.9 percent. Thisincrease was primarily due to a 44.0 percent increase incrude oil sales volumes, which was largely offset by a27.2 percent decrease in crude oil prices.

Domestic sales of crude oil. Domestic crude oil sales wereUSD 55 million in 2001 compared to USD 142 million in2000, a decrease of USD 87 million, or 61.3 percent. Thisdecrease was primarily due to a 47.5 percent decrease inthe volume of crude oil sold in Russia and a 25.7 percentdecrease in domestic crude oil prices.

International sales of petroleum products. Revenues from international sales of petroleum products wereUSD 1,692 million in 2001 compared to USD 1,448 millionin 2000, an increase of USD 244 million, or 16.9 percent.This increase was primarily due to a 31.6 percent increasein our international petroleum products sales volumes,offset in significant part by a 11.2 percent decrease in theprice of the petroleum products that we sold in interna-tional markets. The increase in our international petro-leum products sales volumes was primarily due to anincrease in sales from the Angarsk refinery to Asia byapproximately 1.0 million metric tons.

Domestic sales of petroleum products. Revenues fromdomestic sales of petroleum products remained almostunchanged at USD 2,510 million in 2001 compared toUSD 2,511 million in 2000. A slight increase in domesticmarket prices was offset by a slight decrease in the volumeof petroleum products sold in Russia.

Operating costs and other deductionsCrude oil and petroleum products purchased. Purchases ofcrude oil and petroleum products were USD 481 million in2001 compared to USD 662 million in 2000, a decrease ofUSD 181 million or 27.3 percent. This decrease was primarily

2

00


due to a combination of lower market prices and a reducedneed to purchase crude oil on the domestic market as aresult of increases in our own production during 2001.

Operating expenses. Operating expenses were USD 1,182million in 2001 compared to USD 872 million in 2000, anincrease of USD 310 million, or 35.6 percent. This increase,which related primarily to higher production levels, alsoresulted from an increase in the number of well workovers,increased energy costs and salary increases. In addition,USD 68 million of the increase related to accruals for activeemployees participating in the Veteran Social SupportProgram. Benefits under the Veteran Social SupportProgram, to the extent they relate to active employees, are accrued over the estimated remaining service life of suchemployees. The Veterans Social Support Program isdescribed in more detail in Note 18 to our consolidatedfinancial statements.

Distribution expenses. Distribution expenses wereUSD 1,048 million in 2001 compared to USD 697 million in2000, an increase of USD 351 million, or 50.4 percent. Thisincrease was primarily due to an increase in both volumestransported and transport tariffs for crude oil and petro-leum products. During 2001, we increased the volumes ofcrude oil and petroleum products transported by rail by244 percent, which was due in significant part to theincrease in sales to China. This resulted in an increase inour average cost of transportation, as the costs of trans-porting crude oil by railway are significantly higher thanthrough pipelines.

Selling, general and administrative expenses. Selling, gen-eral and administrative expenses were USD 671 million in2001 compared to USD 562 million in 2000, an increase ofUSD 109 million, or 19.4 percent. This increase was prima-rily due to USD 68 million in one-time increases in accruedliabilities for fully vested participants in the Veteran SocialSupport Program. Benefits under the Veteran Social SupportProgram increase in parallel with the increase in the marketvalue of our stock up to a limit of USD 3.25 per share.During 2001, our share price increased from USD 1.71 pershare at the beginning of the year to USD 5.20 per share at year end.

Depreciation, depletion and amortization. Depreciation,depletion and amortization expenses were USD 270 millionin 2001 compared to USD 218 million in 2000, an increaseof USD 52 million, or 23.9 percent. This increase was prima-rily due to the combined result of increased production anddevelopment expenditures offset by purchase accountingadjustments that reduced the net book value of property,plant and equipment by USD 128 million during 2001.

Taxes other than income tax. Taxes other than income tax were USD 2,075 million in 2001 compared to USD 1,246million in 2000, an increase of USD 829 million, or66.5 percent. This increase was primarily due to increasesin export duties, excise taxes and royalty and mineralrestoration taxes. In 2001, the weighted average exportduty on crude oil increased 29 percent compared to 2000and the weighted average export duty on internationalsales of fuel oil and diesel fuel, the two principal petroleumproducts that we sell in international markets, increased by51 percent and 122 percent, respectively. These increases,combined with the increase in our international crude oiland petroleum products sales volumes, generated a higherexport duty expense. Excise tax rates also increased in 2001compared to 2000 from 55 Rubles per metric ton to66 Rubles per metric ton on crude oil and from a range ofzero to 585 Rubles per metric ton to a range of 550 Rublesto 1,850 Rubles per metric ton on certain petroleum prod-ucts. The increase in royalty and mineral restoration taxesprimarily resulted from higher sales recorded by our pro-duction subsidiaries.

Other incomeRealized gains on marketable securities, net. Net realizedgains on marketable securities were USD 128 million in2001, a decrease of USD 37 million from USD 165 million in 2000. Included in 2000 realized gains was USD 116 mil-lion from the sale of shares of ONAKO and Orenburgneft,a Russian oil holding company and its principal produc-tion subsidiary, which we had purchased during 2000. Excluding these sales, our realized gains increased byUSD 79 million compared to 2000 as we benefited fromthe improvement in the market value of Russian govern-ment securities, which constituted the largest portion ofour marketable securities holdings during 2001.

2

00

2


Interest income (expense). Interest income continued togrow during 2001, totaling USD 309 million compared withUSD 132 million in 2000, and reflecting our significantincrease in holdings of interest-bearing securities andother investments. Interest expense declined significantlyas we continued to pay down our total borrowings fromUSD 423 million at December 31, 2000 to USD 116 millionat December 31, 2001.

Income taxesTotal income tax expense was USD 702 million in 2001compared to USD 1,207 million in 2000, a decrease of41.8 percent. This decrease was primarily due to a netcredit of USD 525 million to income related to the adjust-ment to our deferred tax asset and liability balances dis-cussed below.

Current income tax decreased slightly as a result of higherlevels of investment tax credits from our developmentexpenditures. Effective January 1, 2002, the investment taxcredit was abolished.

The net deferred tax benefit that we recognized in 2001 wassubstantially attributable to the change in the Russian taxcode during the third quarter of 2001. Under the newRussian tax code, which became effective on January 1,2002, maximum statutory income tax rate for incomereceived from ordinary activities was reduced from 35 per-cent to 24 percent, the tax rate for dividends received fromdomestic companies was reduced from 15 percent to 6 per-cent and the tax rate for dividends received from foreigncompanies was reduced from 35 percent to 15 percent.These reductions resulted in a net credit of USD 525 millionto income related to the adjustment to our deferred taxasset and liability balances.

Liquidity and Capital ResourcesThe following table summarizes our statements of cashflows for the periods indicated.



Net cash provided by operating activities 2,967 3,114 3,310

Net cash used for investing activities (2,349) (2,962) (1,633)

Net cash used for financing activities (360) (639) (217)

Net cash provided by operating activitiesIn 2002, our net cash provided by operating activitiesdecreased by 4.7 percent to USD 2,967 million comparedto USD 3,114 million in 2001. This decrease was due to acombination of slightly lower net income and to changes inour working capital, primarily increases in trade accountsreceivable (after excluding the effects of foreign exchange),and reductions in taxes payable.

During 2001 and 2000, we generated cash from operationsof USD 3,114 million and USD 3,310 million, respectively.Cash from operations decreased by only USD 196 million,despite the decrease in net income of USD 568 million, pri-marily due to working capital changes.

Net cash used for investing activities During 2002, our net investing activity was USD 2,349 mil-lion compared to USD 2,962 million in 2001. However, thefocus of our investments shifted from the acquisition ofmarketable securities (primarily Russian government securities) to strategic acquisitions and investment indevelopment of our existing production base. In 2002, ourcash expenditures for acquisitions, including advances to intermediaries were USD 1,032 million compared toUSD 653 million in 2001. This increase primarily related to our acquisition of an additional interest in Eastern Oil Company, acquisitions of equity interests in Transpetroland Rospan, and the acquisitions of Arcticgas, Urengoil,Sakhaneftegas and Mazeikiu Nafta. In 2002, our capitalexpenditures increased from USD 954 million in 2001 to USD 1,263 million as we invested heavily in our explo-ration and production development activities, refineryupgrades to enhance light product output and on renova-tions of gas stations.

During 2001, our net cash used for investing activities wasUSD 2,962 million, compared to USD 1,633 million in2000. Of the net cash used for investing activities in 2001,USD 954 million (2000: USD 589 million) was used forcapital expenditures, primarily oil and gas development, toincrease production volumes and improve the operationalefficiency of our refineries. We made net purchases of mar-ketable securities, primarily U.S. Dollar-denominated Russiangovernment and corporate debt, of USD 678 million

2

00


(2000: USD 509 million). In addition, USD 653 million(2000: USD 368 million) was used to acquire or increaseour ownership in various subsidiaries and equity investees,including Angarsk Petrochemical Company and a numberof marketing companies in Eastern Siberia, two of Kvaerner’sbusinesses and Urengoil.

Net cash used for financing activitiesDuring 2002, our net cash used for financing activities wasUSD 360 million compared to USD 639 million in 2001. In2002, we returned USD 60 million in share subscriptionsto other shareholders of our subsidiary, East Siberian OilCompany, after a planned share issuance was cancelled.We repaid, net, USD 36 million of our long-term debt in2002 and USD 256 million in 2001. Dividend payments of USD 280 million and USD 473 million were made in 2002 and 2001, respectively. Shareholder approval of our interim dividend for 2002 was delayed until the end ofDecember 2002 as changes to the Law on Joint StockCompanies during 2002 originally permitted only annualdividends. Subsequent changes to the law which came intoeffect in late 2002 allowed us to obtain shareholderapproval of our interim dividend on December 31, 2002.

During 2001, we made net repayments of USD 256 million(2000: USD 399 million) of long-term debt, including our borrowings under our facility syndicated by CreditLyonnais, Goldman Sachs and Merrill Lynch and our

borrowings under our agreements with the Ministry ofFinance of the Russian Federation and the InternationalBank for Reconstruction and Development. In 2001, wemade dividend payments of USD 473 million, representinginterim and final dividends for 2000 results and an interimdividend for 2001 that our board of directors declared inOctober 2001. In 2000, our dividend payments totalledUSD 103 million, representing dividends for 1999 results.

Capital expendituresOur business requires a significant amount of capital expen-ditures. We have established procedures in place to evalu-ate all potential projects involving capital expenditures.The following table sets forth our capital expenditures for2002 and our current approved capital budget for 2003,exclusive of any amounts for strategic acquisitions andadditional capital expenditures relating to such acquisi-tions. The capital expenditures for 2003 set forth in thetable below are only estimates and are subject to changedepending upon changes in factors such as crude oilprices, the economy, the general business environment,competition and management approval of new projects.The primary funding source for our capital expenditures in2002 has been, and for 2003 is expected to be, internallygenerated funds. Our 2003 capital expenditure estimatesare based upon a forecasted Brent price of USD 22.00 perbarrel and may need to be revised should Brent fall toUSD 15.00 per barrel or less.


2002 Estimated 2003

Capital Capital

Segment Expenditures % Expenditures %

Exploration and Production 932 72.7% 1,436 78.1%Refining and Marketing 268 20.9% 335 18.2%Corporate and Other 82 6.4% 67 3.7%Total 1,282 100.0% 1,838 100.0%

2

00

2


Related Party TransactionsWe have entered into transactions with related parties andaffiliates. See Note 16 “Related Parties” of the consolidatedfinancial statements.

Recent Accounting PronouncementsIn June 2001, the Financial Accounting Standards Board(“FASB”) issued Statement of Financial Accounting StandardsNo. 143, Accounting for Asset Retirement Obligations(“SFAS 143”). This new statement is effective for fiscal yearsbeginning after June 15, 2002. The Company will adoptSFAS 143 effective January 1, 2003. SFAS 143 addresses theaccounting and reporting for obligations associated withthe retirement of tangible long-lived assets and the associ-ated asset retirement costs. The adoption of this statementprimarily affects the Company’s accounting for oil and gasproducing assets. SFAS 143 differs in several significantrespects from current accounting under Statement of FinancialAccounting Standards No. 19, Financial Accounting andReporting by Oil and Gas Producing Companies (“SFAS 19”).Under SFAS 143, the Company will recognize a liability forthe fair value of an asset retirement obligation in the periodin which it is incurred if a reasonable estimate of fair valuecan be made. If a reasonable estimate of fair value cannotbe made in the period the asset retirement obligation isincurred, the liability is recognized when a reasonable esti-mate of fair value can be made. In periods subsequent toinitial measurement, the Company recognizes period-to-period changes in the liability for an asset retirement obliga-tion resulting from (a) the passage of time and (b) revisionsto either the timing or the amount of the original estimate ofundiscounted cash flows. Upon initial recognition of a liabil-ity for an asset retirement obligation, the Company capital-izes an asset retirement cost by increasing the carryingamount of the related long-lived asset by the same amountas the liability. Management is currently completing itsassessment of the effect of the adoption of SFAS 143 onthe Company.

In November 2002, the FASB issued Interpretation No. 45,Guarantor’s Accounting and Disclosure Requirements forGuarantees, Including Indirect Guarantees of Indebtedness ofOthers (“FIN 45”). FIN 45 requires that upon issuance ofcertain types of guarantees, a guarantor recognize and

account for the fair value of the guarantee as a liability. Theinitial recognition and measurement provisions of FIN 45should be applied on a prospective basis for guaranteesissued or modified after December 31, 2002. The disclo-sure requirements of FIN 45 are effective for financial state-ments of both interim and annual periods ending afterDecember 15, 2002, and are included in Note 19 to the con-solidated financial statements.

In January 2003, the FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities (“FIN 46”). FIN 46amended Accounting Research Bulletin No. 51,Consolidated Financial Statements (“ARB 51”), and estab-lished standards for determining under what circumstancesa variable interest entity (“VIE”) should be consolidatedwith its primary beneficiary. FIN 46 also requires disclo-sures about VIEs that an entity is not required to consoli-date but in which it has a significant variable interest. Theconsolidation requirements of FIN 46 apply immediatelyto VIEs created after January 31, 2003. The consolidationrequirements apply to older entities in the first financialyear or interim period beginning after June 15, 2003.Management does not expect that adoption of FIN 46 willhave a significant impact on the financial position orresults of operations of the Company.

Qualitative and Quantitative Disclosures About Market RiskIn the normal course of business, we are exposed to anumber of external factors and market risks. We areexposed to market risk from changes in foreign currencyexchange rates relating to our continuing operations aswell as security price risk relating to our portfolio of mar-ketable securities. We are not currently engaged in hedgingactivities or other derivative trading to manage oil price riskor to hedge against foreign currency exchange fluctuations.

We are exposed to movements in the Russian Ruble toU.S. Dollar exchange rate with respect to our Ruble-denominated monetary assets and liabilities. Generally, as the value of the Ruble declines, a net Ruble monetary lia-bility position results in currency exchange gains and a net Ruble monetary asset position results in currencyexchange losses.

2

00

2

Share Price

YUKOS shares are traded on the Moscow Interbank CurrencyExchange (MICEX), the Russian Trading System (RTS), and the Moscow Stock Exchange (MSE). YUKOS Level 1American Depositary Receipts (ADRs) are traded in theUnited States, Great Britain and continental Europe. Shareprice information is published in most Russian businessnewspapers and is available on the corporate website.

Quarterly share price range(RTS closing price), 2002

U.S. Dollars per share

High Low

1st quarter 8.37 5.232nd quarter 11.38 8.283rd quarter 10.63 8.454th quarter 9.75 8.45

Dividend Information

Dividend for indicated fiscal year

Russian Rubles per share

2002 2001 2000 1999

Interim 5.70(1) 2.64 1.26 –Final (2) 4.19(3) 4.18 2.58 1.34Total 9.89(3) 6.82 3.84 1.34

(1) For 9 month(2) Final dividend is the total dividend for the year less interim dividend or dividend for

9 month.(3) Proposed by the Board of Directors April 24, 2003, subject to AGM approval.

Dividend payment notification, with payment proceduredetails, is sent out separately to each shareholder.

Annual General Meeting

YUKOS’ Annual General Meeting of Shareholders will beheld on June 18, 2003, at 11:00 am (Registration starts at9:30 am). Address: Moscow, 6, Ilyinka Street (CongressCenter of the Russian Chamber of Commerce).

Stock Administration

RegistrarM-ReestrUl. Vavilova, 23Moscow 117312 RussiaTelephone: + 7 095 719 0945Facsimile: + 7 095 719 0937

ADR Program AdministrationDeutsche Bank:Moscow: + 7 095 797 5035London: + 44 207 547 65 00New York: + 1 212 250 8500

AuditorPricewaterhouseCoopers52 Kosmodamianskaya Embankment, Building 5Moscow 115054 RussiaTelephone: + 7 095 967 6000Facsimile: + 7 095 967 6001

Contact Information

Company Headquarters31a Dubininskaya StreetMoscow 115054 RussiaTelephone: + 7 095 232 3161Facsimile: + 7 095 232 3160e-mail: [email protected]

Legal AddressUl. Lenina, 26NefteyuganskKhanty-Mansiysk Autonomous District628309 Russia

Investor Relations(for inquiries by institutional investors)

Alexander GladyshevTelephone: + 7 095 788 0033e-mail: [email protected]

Corporate Websites

www. yukos.com (English)www.yukos.ru (Russian)www.yukos.sk (Slovak)www. yukos.lt (Lithuanian)www.yukos.pl (Polish)www.yukos.hu (Hungarian) D

esig

n by

Add

ison

ww

w.a

ddis

on.c

om

Shareholder Information

yukos annual report 2002

Documents