Documentof The World Bank

fOR OFFI(IAL. l SE ONLY Public Disclosure Authorized ReportNo. 12943-RU

STAFF APPRAISAL REPORT

RUSSIAN FEDERATION Public Disclosure Authorized

SECOND OIL REHABILITATION PROJECT

JUNE 13, 1994 Public Disclosure Authorized

*2;4 k?

lLer~~rt !.c i V A :- .

Infrastructure, Energy and Environment Division

Public Disclosure Authorized Country Department III Europe and Central Asia Region

This documenthas a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bsnk authorzation. CURRENCY EQUIVALENTS

Unit of Currency = Ruble Rubles per US Dollar Moscow Inter-Bank Foreign Currencv Exchange/Foreign Exchange Auction Market (VEB) rate

Period Average End of Period 1990 19 23 1991 62 169 1992 I Quarter 177 160 11 Quarter 134 144 III Quarter 178 254 IV Quarter 396 415 1993 I Quarter 580 684 II Quarter 801 934 III Quarter 1000 1000 IV Quarter 1200 1200 1994 I Quarter 1591 1753 II Quarter 1843 1928 (as of June 6,1994)

WEIGHTS AND MEASURES bbl = US barrel (42 US gallons) mmbbl = million barrels bcm = billion cubic meters MMSCFD = million standard cubic feet per day bpd = barrels per day ton = metric ton (1,000 kilogram) mbbl = thousand barrels tpd = tons per day

ACRONYMS AND ABBREVIATIONS

API American Petroleum Institute CIS Commonwealth of Independent States CPI Consumer Price Index EBRD European Bank for Reconstruction and Development EIA Enviromnental Impact Assessment FSU Former Soviet Union GAAP Generally Accepted Accounting Principles GAAS Generally Accepted Auditing Standards ICB International Competitive Bidding LIB Limited Internati nal Bidding MNG Megionneftegas Joint Stock Company (Producer Association) NGDU Oil and Gas Production Unit within Producer Associations NGL Natural Gas Liquids NGO Nongovernmental organization OVOS Russian acronym for Industrial Activity Environmental Impact Assessment PA Producer Association PIU Project Implementation Unit PPF Project Preparation Facility SCL Single Currency Loan (IBRD) TN Tomskneft Joint Stock Company (Producer Association) YNG YuganskneftegasJoint Stock Company(Producer Association)

FISCAL YEAR

January 1 - December 31 FOR OFFICIAL USE ONLY RUSSIAN FEDERATION SECOND OIl REHABILITATION PROJECT

fable of Contents

Page No. LOAN AND PROJECT SUMMARY ...... v

I. THE MACROECONOMIC SETTING. I

II. THE ENERGY SECTOR ...... I

A. Energy Consumption .1 B. Energy Resources, Production and Exports . .2 C. Energy and the Environment ...... 3 D. Energy Prices, Taxes and Subsidies ...... 3 E. Organization of the Energy Sector and Strdctural Reform. 3 F. Foreign Direct Investment ...... 5 G. Bank's Role in the Energy Sector ...... 5

III. THE OIL SUBSECTOR .. 6 A. Oil Consumption, Refming and Distribution .. 6 B. Oil Resources, Production, and Exports .. 7 C. Oil and the Environment ...... 9 D. Crude Oil and Petroleum Product Pricing .. 9 E. Oil Taxation l.. F. Legal Framework for Oil Operations ...... 13 G. Organization of the Oil Sector .. 14 H. Foreign Direct Investment in the Oil Sector .. 16 I. Russian Oil Sector Reform Program ...... 18

IV. THE BANK'S PETROLEUM LENDING EXPERIENCE ...... 19 A. Petroleum Lending Experience Outside Russia ...... 19 B. First Oil Rehabilitation Project ...... 19 C. The Bank's Future Lending Strategy in the Russian Oil Sector ...... 20

This report is based on the findings of Preappraisal (Oct/Dec 1993) and Appraisal (March 1994) Missions led by Task Manager Charles McPherson and Deputy Task Manager Douglas McKay. The report was prepared by Charles McPherson and Douglas McKay (EC3IV), with contributions from Suzanne Barnes (EC31V); Peter Pease (OPRPR); Ahmed Jehani (LEGEC); Viren Sirohi and Stan Peabody (EMTEN); Christopher Brierley, Vince Connelly and Miguel Montes (Consultants). Marc Blanc (EC3DR) provided operational guidance. The Division Chief and Department Director are Jonathan C. Brown and Russell J. Cheetham.

i doument has a nsticted distrbution and may be usedby recipientsonly in the perfman f heir ocia duie Its contentm nototberMw bedislosed withoutWorld Ban auhoizaon | Page No.

V. BORROWERS AND BENEFICLARIES ...... 21 A. Organization and Management ...... 21 B. Legal Status ...... 22 C. Mineral and Land Rights ...... 22 D. Relationship with Subunits ...... 23 E. Accounting Systems ...... 23 F. External and Internal Audits ...... 25 G. Financial Situation and Prospects ...... 26

VI. THE PROJECT ...... 28 A. Project Objectives ...... 28 B. Project Description ...... 28 C. Project Cost Estimates ...... 31 D. Financing Plan ...... 34 E. Inurance ...... 35 F. Implementation Arrangements ...... 35 G. Reporting Arrangements ...... 37 H. Procurement ...... 37 1. Disbursement ...... 40 J. Technical Assistance ...... 41 K. Environment ...... 41

VII. ECONOMIC JUSTICATION AND RISKS .. 44 A. Project Justification and Benefits ...... 44 B. Economic Sensitivity Analyses and Project Risks ...... 46

VIII. FINANCIAL EVALUATION ...... 46 A. Projected Profitability and Risks ...... 46 B. Financial Covenants ...... 48

IX. AGREEMENTS REACHED AND RECOMMENDATIONS ...... 48 ANNXES

Annex 2-1 Russia: Primary Energy Supply Annex 3-1 Organization of the Russian Upsream Oil Sector Annex 3-2 Russian Federation Oil Sector Reform Annex 5-1 Legal Characteristics of the Participating Producer Associations Annex 5-2 Organizational Structures of the Producer Associations Annex 5-3 Financial Status of the Producer Associations Annex 6-1 Technical Overview of the Producer Associations Annex 6-2 Technical Recommendations Annex 6-3 Field Opfimization Study: Recommended Scope of Work Annex 6-4 ImplementationSchedule and Project Expenditures Annex 6-5 LendingArrangements, Tegal Documents and Flow of Funds Annex 6-6 Project Implementation Unit: Organization Chart Annex 6-7 Draft Terms of Reference for the PIU Specialists Annex 6-8 Project Supervision Plan Annex 6-9 Procurement Arrangements Annex 6-10 Environmental Assessment Summary Annex 7-1 Economic Analysis Annex 8-1 Financial Analysis Annex 9-1 Russian GovernmenitLetter of Policy Intent Annex 9-2 Selected Documents and Data Available in the Project File

MAPS

IBRD 24146R1 Russia: Main Petroleum Basins and Crude Oil Trunk Lines IBRD 24145R1 Main Petroleum Producer Associationsof Western Siberia RUSSIAN FEDERATION SECOND OIL REHABILITATIONPROJECT

LOAN AND PROJECT SUMMARY

Borrower Thz Russian Federation

Guarantor The Russian Federation

Beneficiaries Three Oil Producer Associations in Western Siberia:

- MegionneftegasOTJSC - Tomskneft OTJSC - YuganskneftegasOTJSC

Note: OTJSC = Open Type Joint Stock Company.

Amount US$500 million equivalent

Terms Currency Pool Loan for 17 years, including 5 years grace, at the Bank's stndard variable interest rate.

Onlending The proceeds of the loan would be on-lent to the Beneficiaries. Maximum maturity periods under the on-lending arrangements are 10 years including 2 years grace. Funds on-lent would carry an interest rate equal to the Bank's lending rate plus a premium of 75 basis points.

Project The proposed Project's principal objectives are to: (i) slow the rate of oil Objectives production decline in Western Siberia and thus strengthen the Russian Federation's ability to earn foreign exchange in the near term; (ii) transfer international technical, environmentaland managerial practice to the operation of oil fields in Western Siberia; (iii) promote a more efficient and environmentallysustainable use of Russia's petroleum resources; and (iv) through policy consultations, continue past support to sector reforms conducive to attiacting the equity and loan finance and international participation necessary to reverse the oil production decline.

Project The most effective investment in the petroleum sector, in terms of early economic Description benefits, is the provision of essential inputs to support existing oil production operations. Russian oil production is concentrated largely in the region of Western Siberia and the proposed Project focuses on three Producer Associations in this region. The Project would contain the following broad categories of components: (i) rehabilitation of idle wells and facilities where warranted; (ii) systematic reconstrucion of existing field infrastructure for a limited number of fields; (iii) in-fill drilling in existing fields; (iv) technical assistance for project implementationand for preparation of field optimizationplans and (v) equipment and services to help mitigate the effects of oil operations on the environment. During Negotiationsfor the First Oil RehabilitationLoan, the Bank established a procedure of regular consultation with the Government on all key oil sector policy topics. This dialogue will continue through implementationof the proposed Project.

Rationale Bank involvementin this Project is justified on the following grounds: (i) an expected early positive impact on oil production, the fiscal deficit and foreign exchange earnings; (ii) a favorable demonstration effect; and (iii) support to petroleum policy reforms conducive to private sector investment which should ultimately become the primary source of capital for petroleum operations.

Environment Past oil production practice in Russia has not conformed to international standards and has often resulted in alarming damage to the environment. As required under OD 4.01, this Project has been assigned Category A, which calls for the preparation of a comprehensiveEnvironmental Impact Assessment (EIA). A craft EIA was circulated to the Executive Directors on March 17, 1994. Based on this EIA, the Government has determined that, on environmental grounds, there are no objections to implementationof the Project. In fact, a key component of the Project involves replacement of oil gathering pipelines to reduce the occurrence of oil leakages. The Project also provides training in environmental management, equipment and training for pilot clean-up programs, support for the development of adequate emergency oil spill response capabilities in the Associations and assistance in planning programs to safeguard the interests of national minorities in or near Project areas.

Economic At peak production the Project would provide 8.3 million tons per year (160,000 Benefits bpd) of incremental oil, representing a 2.5 percent increase in national output that would generate additional gross revenues of approximately US$900 million per year. Economic rates of return for each component of the Project would exceed 50 percent and the benefit-cost ratio for the aggregate Project is estimated at over 2.0 at a real discount rate of 15 percent.

Economic While it is expected that all project components would generate strong economic Risks returns, uncertainty in expected well production due to the state of the reservoirs, potential downhole problems, or unreliable well records presents some risk for well workovers and rehabilitation. This risk is acceptable given the large number of idle wells potentially to be rehabilitated (over 3,000 in the three Associations) and can be managed through careful well screening and review during Project implementation. The risk of improper drilling of horizontal wells will be managed through contracting these services to specializedfirms and flexibility in the program during implementation.

Lower internationaloil prices would reduce project returns, but the overall Project is still economic at international oil prices (Brent North Sea) as low as US$70 per ton (US$10 per barrel). Since a high proportion of both Project costs and revenues are in foreign exchange, the Project is relatively well insulated from adverse macro-economicdevelopments such as high inflation. Project costs do not pose a significant risk. The uncertainty surrounding local cost components due to changing economic conditionsin Russia is minimized due to the small share of local costs in the overall Project cost. Delays in implementationduring the Project life should not significantly affect overall Project returns, due to the fact that the Project is made up of a series of self-contained and rapidly completed components.

Financial Under the current investment regime and reasonable oil price assumptions, the Benefits Project would generate acceptable financial returns to the Producer Associations and, over the Project life, would provide aggregate net present values of approximately US$300 million in after-tax cash flow to the Associations and roughly US$1,200 million in taxes and payments to the Russian Government.

Financial Any withdrawal or diminution of tax and export incentives provided to the Risks upstream oil industry would seriously affect Project returns, as would any re- imposition of price controls.

At recent low international oil prices of US$98 per ton ($13.50 per barrel), the ove:all Project is financiallyviable but returns are insufficient for many components. These prices are regarded as abnormally low and price levels have since recovered to US$120 per ton (US$16.50 per barrel). In any event, the Project is structured to absorb adverse price developments through adjustment of both Project components and timing.

Economic Rate of Reunm Greaterthan 50 percent for all Project components.

Financial Rate of Return Greater than 40 percent real after-tax for the aggregate Project. Estimated Project Cost (US$million equivalenw)

Project Component Local Foreign Total I/ Foreign Component as % as % of Total of Total Well WorkoverslRehabilitation 58 191 249 77% 42% In-Fill New Wells 22 179 201 89% 34% Surface FacilityReplacement (km) 7 59 67 89% 12% EnvironmentalManagement - 15 15 100% 3% Field OptimizationStudies 19 19 100% 3%

UnallocatedRig Costs and Misc. - 25 25 100% 4% ImplementationTA - 12 12 100% 2% Sub-Total2/ 87 500 587 85% 100% ImportDuties 53 - 53 0% Interest DuringConstr. & Fees - 38 38 100% Total Financing Required 141 538 678 79%

Notes: 1/ Costs include6% physicalcontingencies plus average price contingenciesof 2%. 2/ Numbers may not add duc to rounding.

financing Pln (US$million equivalent)

FinancingSource Local Foreign Total/1 % of Total

IBRD - 500 500 74% Producer Associations 141 38 178 26% Total /1 141 538 678 100% % of Total 21% 79% 100% 11/ Numb,ersmay not add due to rounding. Disbursement Schedule (US$ millionequivalent)

Bank Fiscal Year (endingJune 30) 1995 1996 1997 Annual 248 223 29 Cumulative 248 471 S00 RUSSIAN FEDERATION

SECOND OIL REHABILITATION PROJECT

I. THE MACROECONOMlC SETTING

1.1 The macroeconomic setting for the proposed Project is contained in the Bank's Country Assistance Strategy (CAS) for Russia. The most recent discussion of the CAS was on May 19, 1994 in the context of the Financial Institutions Development Project. At that time, the Bank recommended an Intermediate Case lending program, on the order of US$1-$1.5 billion annually, not including adjustment lending. The program would be composed of a core set of relatively straightforward projects, largely in infrastructure and the social sectors, and an additional set of projects that would go forward only when the Government satisfied key conditions for sectoral reforms. The proposed Project is included in the latter group of projects, and it is intended to advance the Bank's continuing policy dialogue in the petroleum sub-sector. As indicated in the recent CAS, the energy sector is expected to be a major focus of Bank lending over the next several years, accounting for roughly 40 percent of new conunitments during the FY93-97 period. In particular, the CAS recognizes that developmentsin the energy sector, especially the petroleum sub- sector, are critical for Russia's export prospects over the next several years and therefore the viability of the external financing program. The proposed Project is fully consistent with the Bank's policy objectives in the CAS and represents a priority use of Bank resources in assisting the transformation of the Russian economy.

II. THE ENERGY SECTOR

2.1 The CAS makes clear the importance of macroeconomicreform to the recovery of individual sectors of the Russian economy. In turn, certain key sectors will have a direct impact on success at the macroeconomic level. Energy is one such sector, and within energy, the oil subsector is critical.

2.2 Energy is estimated to account for 15% of Russia's GDP, 11% of industrial production, and 49% of its convertible foreign exchange earnings. Rapid stabilization of the overall economy is unlikely to occur unless macroeconomic reforms are paralleled by energy sector reform and recovery.

A. Energy Consumption

2.3 Inefficient energy use is characteristic of the Russian economy. In 1992, Russia's energy use per unit of GDP was 14 times that of Japan, 8 times that of the UK, and 5 times that of the US. This problem has worsened in the recent past, with further decreases in economic output and modest decreases in energy consumption. Russia's inefficient energy use stems from a combination of factors including an emphasis on energy-intensiveindustrial users, widespread use of inefficientand 2 outdated equipment, and prices that discourage conservation. The root problem is that energy use has for years been dictated by central planning rather than by market forces.

2.4 The potential for economic rationalizationof energy consumptionin Russia is enormous. The Goverrnent has initiated a program of reforms to address this prospect encompassing: (i) energy price policies that have increased oil, coal and natural gas prices to about 50% of market levels by December 1993; (ii) draft legislationon energy conservation;and, (iii) the establishmentof a Russian Energy Conservation Fund (RECF) to encourage energy conservation investments. Some results have already been observed as a result of the pricing reforms. Energy consumption in Russia has decreased by 11% since 1990, with the largest declines in the coal sector (20%) and petroleum products (19%). Gas consumptionhas remained relativelyconstant until the first half of 1993, when a decline of 4% took place.

2.5 Data on Russian energy consumptionsince 1985 by type are included in Annex 2-1. In 1993, natural gas accounted for about 50% of domesticprimary consumption,oil about 27% and coal 18%. The remaining 5% is split amoi-g nuclear, hydroelectric and other fuels. Coal was the main fuel through the 1960s, replaced by o;' prMw%tsin the 1970s and natural gas by the late 1980s.

B. Energy Resources, Production and Exports

2.6 It is estimated that Russia has 10%l,of the world's oil reserves, 40% of natural gas reserves, 10% of hard coal reserves, and 20-; of the world's brown coal reserves. Its electric power generating capacity ranks second in the world. Russia is the second largest energy producer in the world, accounting for about 14% of total commercial energy production. Notwithstandingthe fact that Russia is one of the most energy intensive economies, it has been able to export over 25% of its total production, making it the world's largest exporter of energy. Energy exports, primarily of oil and gas, represent almost 50% of Russia's current exports to non-CIS countries and provide a critical volume of foreign exchange.

2.7 Russia's productive capacity in energy cannot be maintained and its unexploited reserves cannot be commercializedwithout massive annual investments. Annual capital requirements for oil and gas alone, merely to stabilize existing production levels, are probably in the range of US$6 to $7 billion each. Funds are no longer available to meet these requirements, however, and the future of the sector and the overall economy is being placed in serious jeopardy. Output of energy is now falling in all energy subsectors. Crude oil output is down 40% from its 1988 peak, and is declining at an amnualrate approaching 15%. This must be viewed as catastrophic if sustained for another year or two. Exports of crude oil are also falling sharply, as a consequence of the drop in production. Currently oil exports, which are dominatedby crude oil, are running at about 45% of their 1988 peak. Natural gas production, which had steadily increased over the past several years, has registered its first decline in 1992, falling 3% compared to 1991. There has been a further 4% drop in 1993. Gas exports have also declined by 7% in 1992 and 9% in 1993. Production of coal was declining at an approximate rate of 10% by late summer of 1993 indicating a deepening crisis in this subsector as well. Finally, Russia has become increasingly short of electricity generating capacity since the late 1980s, reflected in severe shortages of power in certain regions. Electric power output in 1993 declined roughly 5% from 1992 levels. 3 2.8 The erosion of Russia's productive capacity in energy began several years ago. The massive funding required to correct this situation will depend crucially on rapid implementationof policy reforms. Data on Russia's energy production and exports 1985-1993are contained in Annex 2-1.

C. Energy and the Environment

2.9 Russia's environmentalproblems are serious and widespread. There are many reasons for the current situation including: past policies that set performance targets in quantitative terms and treated the environment as a free good; lack of environmental legislation, poor implementation standards and enforcement at both the govermnentaland enterprise levels; and pricing policies that undervalued natural resources. Russia's energy inefficiency in both production and end-use represents not only an alarming waste of economic resources, but also a prime cause of high atmospheric pollution and of natural resource degradation. Price reform, coupled with investment in more efficient technologies, would lead to major improvements. Future energy policies in the public sector are expected to incorporate principles of demand management and incentive-based regulations, which are becoming standard in the OECD countries. There is also an important need to address the requirements of indigenouspeople whose traditionalways of life have been negatively impacted by energy resource development.

ID. Energy Prices, Taxes and Subsidies

2.10 Relative energy prices have been graduallycorrected over the past two years. Prior to 1992, energy prices were less than 10% of estimated market levels. By year-end 1993, they had reached about 50% of estimated market levels. The only exception to this is the price of energy products to households, which have risen at a more gradual rate, reflecting the limited ability to pay as a result of the slow adjustment in labor prices and the failure to establish an effective safety net.

2.11 On the production side, until recently, energy prices and taxes left little or no room for suppliers to recover capital costs or even, in some cases, operating costs, a high percetage of which, certainly for oil and gas, are for importedmaterials and equipment. This resulted in financial losses at producing enterprises, sharply curtailed investmentand necessitated subsidiesto producers through either direct budget transfers, as is the case for coal, or subsidized credit, as has recently been extended to the oil and gas subsectors. Energy taxes have caused problems not only because they have been high, but also because they have been based on revenues rather than profit, i.e. they have been insensitive to the distressed condition of energy producers.

2.12 While there has bee )rogress over the past 12 to 18 months, there remains a pressing need to continue to rationalize energy prices and reform taxes, and doing so can be expected to have far- reaching macroeconomic and structural implications.

E. Organization of the Energy Sector and Structural Reform

2.13 Structural reform of Russia's energy sector is underway. Goals of the reform package includereduced state intervenion, promotionof compeutionand a strong, independentprivate sector. Over the past 12 to 24 months, there has been progress under each of these headings, but it has been uneven and considerable work remains to be done. 4 2.14 Prior to 1990, energy was fully integrated into the (then) Soviet Union's national plan. The sector was managed by central Moscow ministries and by subsector or branch ministries. This concentration of authority in the center, together with the fact that central ministries with authority over energy subsectors rarely coordinated their approaches, stifled commercial and operational initiativesin the sector. Pressure from the energy enterprises, notably oil enterprises, over the past three years has led to substantialdecentralization of this authority.

2.15 As a result, branch miristries were converted to giant state concerns during 1991, with the intent that commercial and operational matters for each subsector would be the responsibility of the concerns, while policy matters would remain with the ministries. The state concerns included: Rosneftegas for crude oil production; Glavtransneftfor crude oil transport; Rosnefteproduct for oil product transport and distribution; GasProm for non-associatedgas production, transmission and storage; Rosstroigasifikazia for gas distribution; Ugol Rossii for coal; and Rosenergo for electric power. While distanced from the ministries, these state or national concerns were still formally answerable to them and wholly owned by the state. Selectedactivities camneunder newly established committeesrather than state concerns, for example, oil refimingunder the Refining Committeewithin the Ministry of Fuel and Power, and oil exploration under the State Committee on Geology (former Ministry of Geology).

2.16 Following the creation of the state concerns, a period of further informal decentralization of control over the sector began. This was favored by certain parts of the reform movement in Government on the ground of fostering competition. Others regarded it as potentially disruptive, during a time when stability in energy supplies was vital, and argued for a halt to the decentralization process, at least for the time being. Except in the oil sector, the Government has by and large acceded to these latter arguments. Its latest position is defmed in a series of Presidential Decrees issued in October and November 1992, covering the oil, gas and electricity subsectors.

2.17 The transformation of all energy sector enterprises into joint stock companies commenced in late 1992 and is now well-advanced. This is beneficial in that it sets the stage for corporatization of the enterprises along commerciallines and looks to their ultimate privatization. At the same time, the Decrees provide for a controlling interest in each enterprise to be retained by the state and place responsibility for administrationof the state's shareholdings in the hands of a very few centralized holding companies which are themselveseither wholly owned or effectively controlled by the state. Except in the oil sector, where three new enterprises were established, the centralized holding companies were formed out of the pre-existing state concerns. The Government is now drafting contracts that will set out in detail the relationship between holding companies and the enterprises whose shares they hold in trust. It is expected that these contracts will preserve for the state, through the holding companies, significant control over management of the enterprises during a transition period.

2.18 The risk inherent in current arrangementsis that they will not prove transitional, i.e. that te giantholding companies will be reluctant to devolve control to subsector enterprises and will use the tansitional period to consolidate rather than transfer their authority. This would be unfortnate, as dtere is considerable potential in all subsectors for a much greater degree of beneficial competition basedon a large number of independententerprises. The scale of Russia's energy sector is such that even a substantial fragmentationwould result in enterprises that are hlrge by world standards. While S siieable naturalmonopolies may persist for some tine in a few functionalareas, for example,oil, gas and power transmission,the advantagesof competitioncan be introducedeven here through carefullydesigned and implementedregulation.

2.19 Duringthe reformprocess it willbe of paramountimportance to provideclear definitionof and consistencyin the responsibilidesof key governmentministries and committees,both at the level of the center and at regionalor locallevels. Whilesome key conflictsor ambiguitiesappear to have been resolved,for examplewith respectto oil licensing,other areas of uncertaintyhave yet to be satisfactorilyresolved, for example,the relationshipbetween parent ministries, holding companies, and operatingenterprises.

F. Foreign DirectInvestment

2.20 Foreigndirect investment in Russia'senergy sector can makea criticaldifference: in funding; in transferringmanagerial skldls appropriate to a marketeconomy; in technologytransfer; and in promotinga competitiveenvironment. To date, however,the energy sectorhas fared little better thanthe overalleconomy in attractingforeign investment. While foreign interest remains high and a growing numberof servicecontracts and joint ventureshave been establishedover the past 18 months,no significantinvestment has beenmade or committed.This has been ascribedby investors to the absenceof an accommodatinglegal and fiscalframework, to institutionaluncertainties and to Understandableconfusions during a periodof majortransition. One importantqualitative factor often menioned by potentialinvestors in the energysector are the conflictingsignals they receivefrom the Russianside: investorsare not persuadedthat their investmentsare in the end welcomedby Russia.

G. Bank's Role In the EnergySector

2.21 The Bank's energystrategy in Russiahas been to supportsector reform and sectorrecovery through:(i) direct assistanceto Russianauthorities in the designof their reformprogram; and (ii) developmentof a focusedprogram of energylending.

2.22 The Bank assignedhigh priority to support of the oil and gas subsectorsdue to: (i) the potentialfor these subsectorsto attract significantinflow of foreign investmentcapital; (ii) their potentialto generateforeign exchange through export; and (iii) the potentialpositive impact on the fiscal deficit through adjustent of domesticprices and rationalizationof taxes. An additional importantconsideration is the apparentRussian capability to implementeffectively projects in the oil and gas subsectors.

2.23 Technicalcooperation between Russia and the Bank on sector reforms began under the TechnicalCooperation Project signed between Russia and the Bank in November1991. Areas of particular focus included:(i) prices and exports; (ii) axation; (iii) legislation;(iv) enterprise restrucuring; (v) oil transport; and (vi) oil projecttendering. The regular policy consultations establishedunder the First Oil RehabilitationProject have emphasized the same topicsand resulted in the defmitionof a policyframework for lendingto the petroleumsector (see ChaptersHI and IX below). 6 2.24 Identification of suitable projects for lending has proceeded in parallel with technical cooperation on policy issues. The US$1 billion First Oil RehabilitationProject supporting urgently required oil production rehabilitation in Western Siberia is under implementationand procurement is advancing favorably. The Second Oil RehabilitationProject is the subject of this report. Other potential project areas in the oil subsector have been identified including: (i) joint venture development of new fields; (ii) refinery rehabilitation and modernization; and (iii) oil transport debottleneckingand system expansion. These are discussed further in Chapter IV below. In the gas subsector, Gazprom has been able to attact fnancing for gas transiission and major projects from other sources. As a result, the Bank has focussed its efforts on gas distribution and energy efficiency investnents. Finally, a gas injection demonstration project is in preparation which could have a positive impact on petroleum sector earnings and exports and on the environment through reduced gas flaring, and increased recovery of oil from the reservoir.

2.25 The Bank has broadened its dialogue with Government in the energy sector to include other subsectors, for example, power and coal (a small portion of the Bank's first loan to Russia, approved by the Bank's Board of Directors in August 1992 was allocated to coal). Lending to the energy sector could range between US$500 million and US$1 billion annually for the next several years. In all cases, the highest priority will be assigned to designing a lending program that will act as a catalyst to private sector investment. Once the macroeconomic framework stabilizes and an acceptable investnent framework has been established, the Bank's relative role in Russia's energy sector should decline significantly, giving way to private funds.

2.26 The role the Bank has defined for itself in Russia's energy sector is expected to be fully consistent with the most recent CAS.

ULUTH8E OIL SUBSECTOR

3.1 Russia's oil subsector is representativeof both the opportunitiesand ills of the energy sector as a whole. Resources have been misallocated in both consumption and production; consumption is excessive by international standards; resources are substantial but infrastructure is deteriorating and production capacity is declining rapidly; the legal and institutionalbases for transformation to a market economy are sfill under development;and, notwithstandingits potential, the subsector so far has failed to attact significant foreign investrnent. Implementationof a very substantialprogram of sector reform is urgently required, not only for a continued trnaround of the sector, but for overall macroeconomicstabilization. Russia has already embarked on such a program. The highest priority should be assigned to continued rapid progress in this area.

A. Oil Consumption, Refining and Distribution

3.2 Russia's high energy use compared to other industrialized countries is in good part attributable to its intensive and inefficient consumption of oil products. Oil accounts for approximately 27% of Russia's primary energy consumption. Total consumption of oil (including losses) was about 225 million tons in 1992, down somewhat from previous years but still high, especially given the decline in overall economic activity. The first significant drop in consumption 7 was registered last year: 1993 consumption is estimated at 204 million tons. Data on apparent consumption of oil products from 1985 through 1993 are shown in Annex 2-1.

3.3 Forty percent of Russia's oil is exported. The remainder goes to the domestic refining sector. Refining capacity to meet Russia's demand for oil products is in desperate need of rehabilitationand, equally important, of re-configuration. Russia's refineries typicallyproduce a mix of 50% heavy products and 50% light products. In contrast, the typical European mix is 25% heavy and 75% light. The failure of the Russian refineries to meet the needs of a modern economy has contributed to the overall malaise in Russia's industrial sector. Russia's attempt to address the problem ot emerging slioirages of lighter products by increasing crude oil runs has diverted crude oil from export markets and resulted in an excess supply of heavier residual oil that the domestic economy cannot absorb and which must be exported at a significant discount to crude oil prices. Reforming the refinery subsector will require realignment and upward adjustment of product prices, and re-orientation of present policies which support across-the-board refinery rehabilitation towards more selective regional rationalization of capacity. Substantial near term benefits, estimated in excess of $15 billion, could be achieved with a relatively modest investment, on the order of $1.5 billion. To date, however, domestic funds for modernizationof the refining sector have been very limited and there has been little or no commitnent of foreign capital.

3.4 Russia's product distribution system is also in need of reform to reflect costs and market conditions. Product distribution is accomplished primarily by rail and river transport. Less than 20% of the Russian pipeline system is designed to handle products.

B. Oil Resources, Production, and Exports

3.5 As noted above, Russia has very substantial oil reserves, estimated at 100 billion tons or approximately 10% of the world's proven reserves. Many large discovered fields remain undeveloped, some 35 in Western Siberia alone, and vast unexplored areas have the potential for substantial new additions to reserves.

3.6 As recently as 1987, this reserve base was able to support production at up to 570 million tons per year, making Russia the world's leading oil producer. Since then, however, production has dropped by 40% and is now declining at a 10%-15% annual rate, as shown in Figure 3.1 below. Oil production in the Western Siberian province of Tyumen, Russia's main oil producing area, has been particularly hard hit. This dramatic decline is the result of a number of factors, including: (i) rapid natural production decline in the old fields which have accounted for the bulk of Russia's production to date; (ii) subopfimal technology and reservoir management; (iii) management and coordination difficulties; (iv) breakdown in traditional equipment supply arrangements (e.g., from Azerbaijan and the Ukraine); and (v) lack of finance to perform required maintenance and well workover operations and/or develop new oil fields. Lack of equipment and fmance in good part accounts for a halving in the rate of drilling since 1988 and a drop in the number of new fields commissionedfor development from 30 to 2 per year. 8 Figure 3.1: Annual Crude Oil Production

600

~8-^200-_ l 8

1987 1988 1989 1990 1991 1992 1993 1994est. Year

MsWest S1berZa MlOfthr

3.7 During 1992, as a result of relatively modest cutbacks in domestic oil consumption, oil production declines fell almost exclusively on export markets. Total oil exports during 1992 were down one-half from their 1988 peak, from 280 million tons to 140 million tons. This represented lost foreign exchange earnings of almost US$17 billion per year relative to the 1988 peak. While oil consumptionfinally fell in 1993, by over 10%, production losses were greater in absolute terms and total exports fell to 128 million tons. Hard currency export earnings, however, increased as a greater portion of crude oil exports were channelled to hard currency markets.

3.8 Without rapid remedial actions these already alarming trends will continue to worsen. Arresting Russia's oil production declines will require government commitment to major policy reforms and truly massive investments, up to US$7 billion per annum through the year 2000 just to stabilize production. Given the state of the Russian economy and the limited availability of multilateral and bilateral development capital, a substantialpart of the investmentrequired over the next several years will have to come from private international sources. To date, however, the volume of foreign private equity or loan capital committedto the Russianoil sector remains relatively small. This is attributable to the as yet inadequate legal and fiscal framework and political uncernes. As price and tax reforms are implemented,the domestic industry will increasingly be able to self-finance but, given the escalating problems of arrears in the sector, it will be some time before programs on the scale required can be funded by the domestic industry. These considerations have highlighted the near term importance of multilateral and bilateral development finance. Developmentfinance can make an importantdirect contributionto oil production rehabilitation during the period of transition to a more acceptable investment climate and, in the case of the Bank, significantly influence the pace of oil sector policy reform. 9 C. Oil and the En} ironment

3.9 As already noted, Russia's high energy inefficiency has been a prime cause of its high atmospheric pollution intensity. Oil consumption is a major contributor to this pollution. Oil production in Russia has also been conducted with little regard for environmental concerns or the needs of indigenous peoples. Past oil production practice has largely ignored international enviro-mental standards, often resulting in alarming cases of damage to the environment. The primary sources of historic damage are from unconstrainedflaring of associated natural gas and from oil spills attributable to environmentally unacceptable drilling practices and to leaks in, and other malfunctioning of, the oil pipeline gathering and transportation systems. At the same tin.,e, oil production activities have often caused serious disruption to traditionalpatterns of life for indigenous people.

3.10 Correcting this situation will require pricing reform, strengthening and enforcement of environmental legislation, incentive-basedregulation and new investmentsin both the oil consuming and producing subsectors. While policies are now being adopted to safeguard the interests of indigenous peoples, much more needs to be done in this area.

I). Crude Oil and Petroleum Product Pricing

3.11 The Russian Government is fully cognizant of the need for, and benefits to be expected of, energy price rationalization. However, out of concern that the economy would not be able to withstand the shock of an immediate increase in energy prices to world levels, the Government chose not to include energy prices in the general liberalization of prices announced in the first quarter of 1992. Instead, the Government issued a series of special decrees on oil prices, in January, May and September of 1992. While stopping well short of achieving world price parity, these decrees demonstrated a significantcommitment to market liberaliation and increased prices.

3.12 The Govermnent's September 1992 Decree introduceda very important qualitativefactor into the crude oil market, namely free negotiation of prices between producers and consumers in the domestic vnaket, subject to a limit on price levels of 1.5 times production cost, and an end to allocated sales. In September 1993, the Government did away with the 1.5 limit.

3.13 Crude oil prices at the refinery gate (excluding VAT) advanced from under 1% of world levels in December 1991 to 30% of world levels in September 1992, and reached 50% or more by December 1993 as shown in the Figure 3.2 below. Currently prices are approaching 60% of world levels. While part of these recent gains can be traced to declines in world oil prices and to a real appreciation in the value of the ruble, a good part is also attributable to the Government's policies of price liberalizationin the domestic market. l0 Figure 3.2: Russian Domestic Crude Oil Prices as a Percent of International Price

100% ~ ~

I I l

60%r

60%-4

w8~~0402- X%

Jan.92 Feb.92 May92 Sept92 Jan.93 June93 Jan.94 June94

3.14 Russia's experience with respect to petroleum product prices has been similar to its crude oil price experience. Over the past 12 months wholesale prices have increased to over 50% of internationallevels, with significant increases occurring in recent months. Retail prices, measured by motor gasoline prices, are approximately60% of comparable retail prices in the United States.

3.15 The Russian Government recognizes that future progress on oil prices depends on trade liberalization and export tariff policies. Action on both fronts is now pending.

3.16 Oil exports have been subject to strict quota limitations and cumbersome licensing procedures. Quotas have been increasing,however. Crude oil exports to non-FSU countries in 1993 increased by approximately 20 percent over 1992 levels, from 66 million tons to an estimated 80 million tons. Early this year the Government set quotas for 1994 which would further expand non- FSU exports to approximately 90 million tons. Then, on May 23, 1994, the Government issued a Presidential Decree which from July 1, 1994 abolishes all quotas and licenses for exports of goods and services, except those which are exported in compliance with the international commitments of the Russian Federation. Liberalization of access to the export market will put further upward pressure on domestic crude oil and product prices.

3.17 This process will be helped by Governmentplans to reduce the oil export tariff by 50 percent from 30 Ecu per ton (approximatelyUS$5.00 per barrel) to 15 Ecu per ton ($2.50 per barrel) in the near future and to rapidly phase out the tariff altogether. The Government has also assigned a high priority to establishing an acceptable regulatory framework for oil pipeline transportation. This is relevant to domestic prices because, without such a framework, the oil transport system, which is a state monopoly, would be in a position to act arbitrarily in granting access to the export market it and to extract the equivalent of an export tax from the domestic industry with the effect of restraining domestic price increases. The principles to be applied in establishing a regulatory framework for oil transport, including non-discriminatory access and transparent economic tariffs are contained in draft legislation submitted by the Government to Parliament in April 1994.

E. Oil Taxation

3.18 The Russian oil taxation system presents two serious difficulties to the existing and/or potential investor: (i) the level of tax "take' is too high; and (ii) the system depends excessively on revenue-based rather than profit-based taxes.

3.19 The Government is well aware of these difficulties and, especially over the last 12 to 18 months, has worked to address them.

3.20 As shown in Figure 3.3 below, taxes combined with consumer subsidies (price controls), resulted in a level of take through early 1993 which was in excess of 100% of the operating margin available to the average producer on flowing production. By June of last year, at the time of presentations of the Bank's First Cil RehabilitationLoan to the Board, taxes had been reduced and prices increased sufficiently to allow the average producer to break even or earn a small profit on flowing production. By that time too, the Government had introduced a number of tax incentives, not reflected in Figure 3.3, for investmentin new production, i.e. in oil production rehabilitation and new oilfield development. Average take has contiued to decline over the past year and is now in the range of 80% to 90% on flowing production and 65% to 75% on new production.

Figure 3.3: Distibution of Operating Margin

A~ 125%. I

0 25%

-25% Jan.92 jan. 93 June93 Jan.94 June94

m consumr subsiltes - Taxes and Fees

125%

}-25% Jan.92 Jan.93 June93 Jan.94 June94 7 5%

I. -- I _-___ 12

3.21 While tax reform in the oil sector implies significant reductions in tax rates, the negative impact of such rate reduction on government tax receipts is expected to be more than offset by an expansion of the tax base through incremental production.

3.22 Over the same period, there have been changes in the structure as well as level of the Government's tax take, as reflected in Figure 3.4. Because simple revenue taxes are insensitive to profitability, they distort investmnentdecisions, discriminateagainst higher cost projects and reduce the overall range of projects undertaken. At the beginning of 1992, the Russian Government's take in the oil production subsector was composed almost entirely of revenue taxes. A corporate profits tax was in place, but was never applied since the burden of revenue taxes left producers with no taxable income. Later in the year, the Government began to reduce the revenue tax burden and to restructure a significant portion of the revenue taxes, in particular the excise tax, so as to be more sensitive to the underlying profitability of a project or Producer Association. This was done by 'tailoring" the excise tax charged to expected operating and capital costs in each Producing Association or project area. By June 1993, the share of revenue taxes in total tax take was still abnormally high, but the situationwas improving. As Figure 3.4 shows, it has continuedto improve over the past year. These improvementsrelate to the taxationof establishedproduction from existing license areas. In December 1993, the Government issued a Presidential Decree (Decree No. 2285) which would dramatically simplifyoil taxation and shift its structure towards profit-based taxes for new licenses structured as production sharing agreements. Under the new Decree only three taxes would be payable: (i) the corporate profits tax (currently 38%); (ii) a mining royalty (6% to 16% depending on the production license); and (iii) a variable production or profit share negotiable in each license. The Government is now actively preparing a series of normative acts or regulations to give effect to the new Decree. A number of major new projects, involving capital investments estimated in excess of US$ 35 billion and corresponding increases in production, would come under the new tax system. International as well as domestic oil companies would be affected. Among the international companies are Amoco, Elf, Exxon, Marathon, Mobil, Shell, Texaco and Total.

Figure 3.4: Structure of Oil Production Taxation

120%

100%

I- O*L_. I

40.F 1r/ 20%

0% Jan.92 Jan.93 June93 Jan.94 June94 Deree#2285 Date I RevenueTaxes cm ProntSenslUve Taxes 13 3.23 Other significant concerns raised by the Russian oil taxation system include: (i) its complexity; and (ii) the lack of effective assurances of tax stability. As to complexity, the Government has deleted some taxes over the past year (e.g. the complicated Price Regulation Fund) and intends to phase out others (e.g. the GeologicalFund). Its major initiative in this area, however, is Decree 2285 which would reduce the number of applicable taxes from eight to three. With respect to stability, the Government has provided assurances of its intent to maintain or deepen existing tax incentives (see Annex 9-1) and recently issued an important Decree to restore export tax incentives to international joint ventures. Onct again, Decree 2285 provides a model and contains attractive language stabilizing fiscal arrangements.

3.24 Finally, as part of its oil tax reform program, the Goverrnent has taken steps to simplify tax administration and increase the likelihood of compliance. By a Government Resolution issued in April 1994, the percentage ad valorem excise tax was converted to an equivalent ruble per ton tax. It is worth noting that care was taken in introducing this reform to avoid any increase in the statutory burden of the tax and to maintain its variable, profit-sensitive, character.

F. Legal Framework for Oil Operations

3.25 A comprehensive, clear and stable legal framework for petroleum licensing and operations is essential for successful future development of the Russian petroleum industry by Russian and by international enterprises under market economy conditions. To date, such a framework, although well progressed, is not fully in place and the investmentsrequired for rehabilitation of the industry have been consequentlywithheld.

3.26 The Russian Government quickly identified the need for a legal framework and Russian experts have completed a substantial amount of work in this area over the past 24 months. The enactment of the Law on the Subsoil (May 1992) and the related Licensing Statute (July 1992), together with the issuance of Regulations for its implementation,are significant achievements and have been used successfully to launch an expanding program of tendering and licensing oil exploration and production projects. Experts recognized, however, that these initial laws and regulations, not being specific to petroleum, needed to be complementedand possibly in some areas amended or replaced by special petroleum legislation.

3.27 Follow-on work on amendments to the Law on the Subsoil, a new draft Law on Oil and Gas and a draft Law on Concessions and Contracts was well advanced by June 1993, but subsequent legislative processing of these drafts was seriously disrupted by the political events of September/October 1993 and new Parliamentaryelections in December 1993. Fortunately, progress resumed in 1994.

3.28 A comprehensive legal framework for petroleum is now expected to be in place by year-end 1994 or early 1995. The draft amendments to the Law on the Subsoil and the draft Law on Oil and Gas have gone to Parliament for a first reading. Additional complementary legislation will be submitted in the coming months. In December of last year, as noted above, (para 3.22) a Presidential Decree was issued which would establish a new and attractive legal as well as fiscal regime for agreements structured as production sharing agreements. Drafts of more detailed 14 legislation and regulations necessary to make this Decree effective are expected by July 1994. Industry response to this initiative has been positive.

3.29 During the legal and contractual drafting process, the Government and Parliament have maintainedan extensive dialogue with both the domestic and internationalpetroleum industry. This consultation will continue through the period of legislativedebate. The Bank has actively supported this process.

G. Organizationof the Oil Sector 2

3.30 Satisfactory clarification of the organization and legal status of the oil enterprises, of their relationship to Government and of institutionalresponsibilities for petroleum within Government are all very nmportantto the efficient functioning of Russia's oil sector and to attracting fmance and investment.

3.31 The key institutions in Russia's oil sector are as follows:

(a) Mintstry of Fuel and Power. The Ministry is responsible for oversight of the energy sector and for policy development and regulation. The Ministry holds controlling interests in national concerns such as Rosneft and over oil producing and refining associations. The organization of the Ministry is described in Annex 3-1;

(b) State Committeeon Geology (Roskomnedra). The Committee has the same status as a Ministry and is responsible for minerals and for oil exploration. Under the July 1992 Law on the Subsoil, the Committee is responsible jointly with regional authorities for licensing of oil exploration and development;

(c) Ministry of EnvironmentalProtection and Natural Resources. This Ministry has an oversight role with respect to the environmental impact of all oil operations. Any significant oil project requires clearance by the State Committee of Mineral Resources, within the Ministry, on environmentalgrounds;

(d) Regional Governments. Regional governmentsexercise a great deal of authority over oil operations in their areas on matters which range from the purely operational to legal and fiscal. Local infrastructure requirements in relation to oil operations are of particular concern.

(e) Scientific Institutes. In the past the Russian oil sector depended heavily on major scientific institutes such as the Institate for the Study of Complex Fuel and Energy Problems (VNOEIING), the Siberian Petroleum Institute and the Geological Institute for advice on economic and technicaltopics. These institutes, formerly branches of the key energy ministries, are now quasi-independent. They still exert considerable influence; 15 (f) Holding Companies. The Government is in the process of establishing a number of holding companies to administer its shareholdings in oil enterprises. This is described more fully below,

(g) Oil Enterprises. Actual operations in the oil sector are carried out by a large number of oil exploration, producing, refining and transport enterprises or associations. In the past, annual budgets, programs of work, anl production targets were provided to the association by appropriate federal ministries. Today, the enterprises have greater autonomy and are expected to be self-financing. Oil producing associations usually have a number of sub-units(or NGDUs) which are responsible for individual field operations.

3.32 The Russian oil sector is going through a period of rapid structural transformation. A large number of uncertainties remain, but the outlines of the new sector are becoming clearer. Under a Presidential Decree issued in November 1992, virtually all existing oil enterprises or amalgamations thereof were to be corporatized, i.e. established as joint stock companies, before December 31, 1992. This deadline was not met, but the process is well advancedand, for most enterprises, already completed. For a limited time period, the state will hold a controlling interest in each of these enterprises either directly or indirectly through one or another of six newly created companies: Rosneft, a large state enterprise, formed out of the previous state oil concern, Rosneftegas; four vertically integrated joint stock companies, Lukoil, Yukos, Surgutneft and the very recently formed Sidanco; and two transportationjoint stock companies, Transneft for crude oil and Transneftprodukt for oil products. A schematic diagramnof the new sector organization is contained in Annex 3-1.

3.33 Rosneft, a 100% state owned enterprise, is responsible for managingthe state's shareholding in a variety of oil producing and refining enterprises, including Tomskneft and Megionneftegas,two of the beneficiariesunder the proposed Project. The state's shareholding in each of these enterprises will be 38% of total stock and 51% of voting stock. The four vertically oil integrated companies, Lukoil, Yukos and Surgutneft and Sidanco are 45% state-owned and in turn hold 38% controlling interests in another set of producing and refining enterprises, including, in the case of Yukos, Yuganskneftegas, the third beneficiary under the proposed Project. The state appoints the Board Chairman (General Directors) of Lukoil, Yukos, Surgutneft and Sidanco and key Government ministries or agencies, including Fuel and Power, the State Property Committee and the AntimonopolyOffice, are represented on their Boards. Finally, the two transportation enterprises, Transneft and Transneftprodukt, are 100% state-owned and in turn hold at least 51% of each of the enterprises involved in oil transport.

3.34 Although the energy sector was specificallyexcluded from the 1992 Russian State Program of Privatization, the Government's intent, expressed in its November 1992 Decree, is that interests in oil enterprises which are not specifically identified for state holding will be made available to employees and managers of the enterprises, to the public and to certain special interest groups, such as native people in Siberia, through preferential share purchase schemes or the voucher system established under the Program of Privatization. Up to a 15% shareholding will be available to foreign investors. Further, except in the case of oil transport enterprises, it appears that the state's controlling interest itself must be disposed of within three years. 16 3.35 The November 1992 Decree on oil goes further than other energy subsector decrees in distancing commercial operations from government, and in establishing a basis for rapid corporatization and eventual privatization of enterprises in the subsector. This is appropriate. Russia's oil sector is well suited to the early emergence of competitionbased on a significant number of independententerprises, at least in the exploration, production, refining and distribution functions. The sector already contains more than 30 geological (exploration) associations, 40 producing associations (many of which have sub-unitsor NGDUs which themselvescould be viable commercial enterprises) and 20 refining associations. Where natural monopoliesexist for the present, e.g., in crude oil and product transport, regulated independence of the enterprises involved could produce competitive results and is under Government consideration.

3.36 As noted earlier, clarification of the institutionalresponsibilities for the petroleum subsector is critical to its orderly development. In the context of encouraging new investmnentin the sector, the Goverunent and the Parliament have made an important clarification of institutional roles in designating the State Committee on Geology as the licensing authority in conjunction with Regional authorities. Additional divisions of responsibilitybetween the Ministry of Fuel and Power and the Committee on Geology have been clarified in joint conununiques.

3.37 Other important responsibilities over the oil sector, for example, taxation (Ministry of Finance), environmental protection (Ministry of Environmental Protection and Natural Resources) and policy and sector oversight (Ministry of Fuel and Power) appear to have been reasonably agreed at the level of the center or federal government. Relations between the center and the regions, however, are still evolving in a number of important areas such as taxation, property rights and licensing. These ambiguities need to be removed. The Government has assigned a very high priority to progress in this area. Recently, a Protocol was signed between the Ministry of Fuel and Power and the Khanty-Mansisk Okrug, the major oil producing region in Siberia, clarifying respective roles in the oil sector.

H. Foreign Direct Investment in the Oil Sector

3.38 While Russia expects to attract some foreign equity investment in Russian oil enterprises in the form of shareholding (para 3.34 above), a far more important need is for direct investment in production rehabilitation and more importantlyin the development of new oilfields.

3.39 The number of new oilfields commissioned for development has fallen at an alarming rate over the past 2 to 3 years, from about 30 per year in 1991 to two in 1993. Enormous hydrocarbon reserves, crucial to economic recovery, are left undeveloped for want of finance. Tendering of such fields, including especially the participation of foreign oil companies, is the only practical near term possibilityfor a turnaround in the rate of new field development. Foreign company participation has the potential to bring massive new investment to Russia. Up to US$50 billion is believed to have been earmarked for Russia by internationalcompanies, provided attractive projects are tendered on reasonable terms and conditions. Foreign participation would also bring a significant transfer to Russia of profit-oriented management skills and new technology, and beneficial risk sharing.

3.40 Russia's experiments to date with foreign investment in the oil sector have been very uneven. Initially, there was a strong resistance to inviting meaningful foreign participation. The early deals 17 offered were not appealing: they were small, technically complicated or very high risk. Further, since the legal and fiscal framework for oil tendering was inadequate, contract negotiations were complex, lengthy and of necessity conducted at several levels. The contract approval process involved local agencies and branches of goverrnent, at least six central ministries or conmnittees and, ultimately, the President, Prime Minister and the Supreme Soviet. Not surprisingly, foreign direct investment in the oil sector so far has been insignificant, certainly relative to sector needs. That said, it has had a demonstrable impact on sector performance. Over 40 international joint ventures are now operating in Russia. Most are small. However, productiornin 1993 from these ventures exceeded 10 mirlliontons or just under 3% of national production, and should increase in 1994.

3.41 Unfortunately, several of the smaller foreignjoint venture projects that have gone ahead have run into serious difficulties, partly due to differences between the local and foreign joint venture partner, but in good part attributable to the failure of the government to deliver on export quotas, predictable access to oil transport and on promised tax relief, particularly with respect to the export tax. The Government appears to have largely resolved the quota and export tariff difficulties through Decrees issued in May 1994 on the abolition of quotas amidthe restoration of export tax privileges. However, the experience of early joint ventures has had a dampeningeffect on new investor interest. In fact, a sharp fall-off in interest in the smaller to medium-sizedjoint venture projects is already apparent. No agreements on major new investment projects have been signed as yet. While 6 to 8 of these are pending with international oil companies, negotiations have been, until recently, immensely complicated and time consuming.

3.42 Against this background, attracting foreign direct investment on the scale required will be a daunting task. Nevertheless, the Govermnent of the Russian Federation and Regional Governments are now devoting considerable attention to the preparation of project tenders. Based on the experience painfully gained over the past two years, the process of tendering, while certainly not complete, has been considerably refined. Two major tenders were conducted in 1993 in Khanty- Mansisk (West Siberia) and Sakhalin (new areas). The results of the Khanty-Mansisk tender were announced in September 1993. The tender drew bids from Shell, Amoco, Exxon, and Mobil, with Amoco and Shell named as winners along with Russian partners. Winners in Sakhalin named in January 1994 included Texaco, Mobil, and Exxon. Following tender awards, the winners must negotiate detailed agreements with the relevant authorities. Recent tenders negotiations have moved much faster than under earlier tenders. Several agreements could be signed in the next several months. Their effectiveness, however, will be conditioned on satisfactoryassurances regarding the applicable legal and fiscal framework.

3.43 Preparation for international tendering is currently being carried out in accordance with the provisions of the Law on the Subsoil. Lead roles are played by the State Committee on Geology and regional governments. Necessary coordination with the Ministry of Fuel and Power and other ministries at the center and with agencies of regional government is achieved through a temporary commission which includes representatives from all interested parties. Technical data packages are being professionally prepared by joint ventures among three or four Russian institutes and western service companies. In the event that new petroleuimlegislation redefines the licensing authority, great attention will need to be paid to the transition to ensure that work on tenders continues with the minimum disruption. 18 3.44 The Government and a growing number of Regional Authorities are increasinglycommitted to tendering attractive projects to the international and domestic industry. The current focus is on explorationprojects. A number of significantdevelopment projects already exist, however, and have yet to be included in a tender. Most are under license to Producer Associations. A major challenge for the Government will be to persuade the Associationsto release these projects for tender to a joint venture partner. The reluctaniceof the Producer Associationsis attributed to their concern that, until the arrears problem is resolved or access to export markets is assured, early development of their projects will prove uneconomic.

3.45 Finally, successful tendering to internationalinvestors will depend not only on an efficient tendering process but also on: (i) clarification of past legislative and administrative actions, particularly of those events which have sent a negative message to the international industry, (ii) satisfactory legislation on petroleum licensing and taxation; and (iii) the resolution of a number of policy issues specifically related to the conduct of a tender (for example, auction versus direct negotiation and the terms and conditions of Russian participation in licenses). Industry reactions to the recent Khanty-Mansiskand Sakhalin tenders confirmedthe critical importance of progress in each of these areas.

I. Russian Oil Sector Reform Program

3.46 As will be readily apparent from the foregoing, the introduction and implementationof a reform package on the scale required to bring about recovery in the Russian oil sector is an extraordinarily difficult task. Yet, the potential rewards to reform are enormous. Reforms should be implementedon an urgent basis, as an integral part of the macroeconomicstabilization program, because they offer the best opportunity for significantlyrelieving present and prospective budget and balance of payments constraints.

3.47 Under the Technical Cooperation Agreementbetween the Russian Federation and the Bank, the Government and the Bank engaged in an intensive dialogue in Russia's oil sector reform progran. In the context of the First Oil RehabilitationLoan, the Government provided the Bank with a Letter of Intent which proposed that the practice of regular consultations with the Bank be maintained with a view to achieving mutually satisfactory results, especially in the areas of price, taxation and legislation. This program of consultationsis now well establishedand will be continued under the proposed Project. In addition, at the Government's request, the First Oil Rehabilitation Loan includes a US$10 million component for technical assistance to support the Government's sector reform in price, taxation, legislationand other areas such as enterprise restructuring and the promotion of private investment. Implementation of this component is about to begin. In the meantime policy programs funded by bilateral agencies under Bank supervision are ongoing.

3.48 Annex 3-2 summarizesprogress to date on sector reforms and future reform targets. In the context of the proposed Second Oil RehabilitationProject the Government has provided the Bank with a Letter of Policy Intent (Annex 9-1) outlining recent policy reforms and near term goals. 19 IV. THE BANK'S PETROLEUM LENDING EXPERIENCE

A. Petroleum Lending Experience Outside Russia

4.1 The proposed Project would be only the second Bank petroleum loan to Russia. However, the Bank has considerable experience in financingpetroleum projects elsewhere in the world, on the basis of which it has developed a set of guidelines for oil lending. These guidelines emphasize the promotion of policy reforms and private sector investment, the transfer of operational and managerial expertise and the strengthening of the financial, lecinicaland commercial capacity of the domestic petroleum industry. Because of the p .ential detrimental impact of oil and gas projects on the environment, the Bank assigns considerable importance to the adequacy of measures to avoid pollution and harm to indigenous people, and more generally, ensure that any potential damage can be brought rapidly under control.

B. First Oil Rehabilitation Project

4.2 The criteria and considerations listed above are reflected in the Bank's strategy for the Russian petroleum sector and are incorporated into the Bank's First Oil Rehabilitation Loan to Russia. The First Oil RehabilitationLoan was structured as to both location and project components to avoid displacement of private capital and was paralleled by a major program of technical cooperation on policy issues. Technology transfer was built into the Loan as explicit technical assistance and in the design of project implementationcomponents which have attracted bids from several major international oil companies as well as qualified internationalconsultants. Repair and replacement of leaking oil pipelines is a major componentof the Project and will contribute directly to environmentalclean-up, as will improved drilling and production practices under the Project. The Project makes specific provision for the acquisition of environmental equipment and technical assistance. The structure of the First Oil RehabilitationProject, which will be largely duplicated by the proposed Second Project, has served as a model for similar projects prepared by other international agencies, for example, the EBRD, and for private sector rehabilitation projects. Further, the policy dialogue associated with the First Project has contributed to improvements in oil prices and in the legal and the fiscal framework for new investments,enhancing the financial viability of the oil sector and, attracting new, albeit as yet far from sufficient, funds to the sector.

4.3 The First Oil Rehabilitation Loan was declared Effective November 15, 1993. Implementation for the most part has gone very smoothly. Lessons learned from the First Oil RehabilitationLoan highlight the importance of: (i) identifying a consistent counterpart team with sufficient authority to move a project forward; (ii) coordinating among key interested parties (Ministries, agencies, levels of government) on critical or controversial project issues; (iii) early detailed attention to procurement and other implementationissues and the potential benefits of a Project Preparation Facility (PPF) in this regard; (iv) involvinglocal consultants and institutes in the process; and (v) an early start in cooperation with the relevant Ministries on an Environmental Impact Assessment (EIA). The design and preparation of the proposed Project anticipates each of these issues. Core teams of representatives from the Government and the Producer Associations have been established to prepare and implement the Project on the Russian side. The Bank has discussed with the Government the reed for close collaborationbetween Ministry of Fuel and Power, 20 Ministry of Finance, Parliamentary Committeesand the Ministry of Justice during the later project stages of signature, effectivenessand disbursement. The experience gained in the preparation of the First Oil RehabilitationLoan will be particularly helpful in this regard, both to the Bank and to the Government. PPFs have been set up to expedite Project implementation. Local consultants aie involved in procurement preparation and, at an early stage, were engaged to help prepare the EIA.

4.4 Other significantexperience includes recognitionof: (i) a deeply ambivalentattitude in Russia towards foreign direct investment, official policies notwithstanding;and (ii) the lingering power of old central planning views on policy formulation, business practices and the uses of new technology. These issues have been taken up in the policy dialogue with Government and in Project design.

C. The Bank's Future Lending Strategy in the Russian Oil Sector

4.5 The greatest potential for early returns from Russia's oil sector lies in the restoration to service of a portion of an estimated 25,000 to 35,000 idle wells in Western Siberia. While a large number of these wells are not expected to be economic, many can be made to produce profitably within a matter of months. Well workovers have been the principal focus of domestic and foreign activity and development fiance over the past two years. Contracts for the restoration of 8,000 wells have been signed between Producer Associationsand oil companiesor service contractors. The Bank's First Oil RehabilitationLoan and the EBRD's parallel loan are essentially devoted to well workovers, as are pending Japanese and US EXIM credits. Investments in this area have begun to pay off already and there has been a perceptible slow-downin the annual rate of decline of domestic production, from 15 percent in 1992 to an estimated 11 percent for 1993. The Bank's First Oil RehabilitationLoan will have a significantpositive impact on production over the next 24 months, equivalent at peak to 3 percent of national production. Internationaljoint ventures with Russian Producer Associations have resulted in similar gains. It should be noted that production rehabilitation investments to date can be attributed in good part to the incentives which developed out of the Government-Bankpolicy dialogue associated with the First Oil RehabilitationLoan and to the demonstration effect of the Loan. The design and policy components of the proposed Second Oil RehabilitationProject closely resemble those of the First Project.

4.6 The Bank's future lending strategy for Russia's oil sector can be summarized as follows:

(a) Second Oil Rehabilitation Project: The Bank's immediate focus will be on implementationof the First Oil RehabilitationProject and on timely completion and implementationof the proposed Second Oil RehabilitationProject. The rationale for the Second Project is essendally the same as the First, including early economic benefits and policy reform. However, this would be the Bank's last oil rehabilitation project. The First and Second Project will have played a critical demonstration role and alternative finance should become increasingly available.

(b) New Proiect Areas: The Bank has already begun to turn to new project areas in the oil sector, applying the same general criteria as were applied to the rehabilitation projects. These include: 21

(i) Joint Ventures: Supportto joint venture developmentof major new oil fields. In the medium to long-term, this is the only solution to declining production and exports. One or two operations of this type are envisaged, to encourage the early implementationof joint ventures between Russian and international oil companies. The current lending program includes such a project for FY 96, which is now being prepared.

(ii) Refinery Ungrading: Relativelymodest investments in refmery modernization could significantly reduce the volumes of crude oil consumed by domestic refineries, freeing up crude oil for export.

(iii) Crude Oil Transport: "Debottlenecking" investments in the crude oil transport sector can be expected to expand exports and improve production incentives. Investnents of this type will be critical to the success of Government policies intended to free up crude oil exports.

4.7 The Bank has taken care to define its role in the Russian oil sector as that of a catalyst to private investment. At the same timne,the Bank recognizesthat private financeon the required scale will not be forthcoming quickly. This is certainly true of major development projects, as well as refining and crude oil transport. Bank funding can make a valuable direct contribution during a transition period and at the same time, promote the conditionsultimately required to attract private capital.

V. BORROWERS AND BENEFICIARIES

5.1 The Borrower and Guarantor of the proposed loan will be the Russian Federation represented by the Ministry of Finance. The responsible sector ministry is the Ministry of Fuel and Power. The beneficiaries will be three Producer Associationsin Western Siberia, each of which is a joint stock company: Megionneftegas (MNG), Tomskneft (TN), and Yuganskneftegas(YNG). Funds will be on-lent to these Associations which will be responsible for implementingthe Project (see Chapter VI).

5.2 A brief account of the structure of the upstream Russian oil sector including the role of the Producer Associations within this structure, is given in Chapter III. This Chapter provides generic descriptions of the legal status and structure of Oil Producer Associations, which are characteristic of the Associations participating in the Project. Further details are provided in Annex 5-1, which summarizes the legal characteristics of the participating Associations. The operational and management structures of these Associationsare outlined in Annex 5-2.

A. Organizationand Management

5.3 Producer Associationsare operating entities generally responsible for oil and gas production within a contiguous geographic region. Associations comprise a number of functional subsidiary enterprises, the most important of which are NGDUs, the field operators. The management of the 22 Association is responsible for overseeing and coordinating the subsidiary enterprises, including corporate activities such as external financing, govermnent relations, legal affairs, external contracting with suppliers and customers, and arbitration and regulation of transfer prices between subsidiary enterprises. The Producer Association generally has exclusive jurisdiction over oil produced by the NGDUs. The Associations are also responsible for the majority of social infrastructure within their jurisdiction, although some Associations are starting to shift these responsibilities to municipalities.

5.4 While the NGDUs are responsible for preparing production plans, these plans have traditionallybeen finalized through negotiationsbetween the Producer Association, the Ministry and the State Oil Committee. Experts from the scientific institutes in Tyumen may provide third-party assessment of achievable production levels. In the past, critical production decisions in the Associations were subject to external control, and Producer Associationsconsequenty have limited experience in decision making related to capital investment. In addition, since exploration was carried out by the Ministry of Geology, they have minimal experience in evaluating exploration and development opportunities. Producer Associationsand Geologic Associationsare beginning to form alliances as central funding declines for the Geologic Associations, but this process is hampered by uncertainty regarding rights and jurisdiction.

B. Legal Status

5.5 As discussed in Chapter 3, Decree 1403 of November 1992 established the framework for oil sector reorganization over the next three to five years. By late 1993, the majority of Producer Associations and even some NGDUs had been transformed into open joint stock companies. The Associations participating in this Loan have all been established as joint-stock companies, a pre- requisite for obtaining Bank financing. The majority of shares of these Associations eventually will be held by employees and other private investors although initially the majority of voting shares are currently or will shordy be held by the holding companies (Rosneft in the case of Megion and Tomsk, and Yukos in the case of Yugansk) which in turn are controlled by the Government. Over the next two to three years the Government is expected to divest its shares. In the interim the Producer Associations will operate as autonomous organizations with the legal and administrative powers expected of commercial enterprises.

C. Mineral and Land Rights

5.6 The legal regime and permits relating to mineral and land rights are also in the process of being reformulated. Until recently, mineral permits were granted to Producer Associations for a period of only two or three years and their renewal depended on a number of factors, including production performance. In other words, there was no long-term security of rights. This system clearly did not safeguard the right of extraction in existing oil fields, nor did mineral permits cover pre-extraction exploration and appraisal rights. The Law on the Subsoil and the Statute on Licensing, enacted during 1992, provide a framework for licensing. Licenses or permits issued under these laws provide secure rights to explore, develop and produce petroleum for a reasonable period, up to 25 years. Producer Associations submitted license applications for fields currently under production during late 1992 and the Government has issued such licenses in conjunction with 23 joint stock company approvals. Evidence of field licenses, together with rights to surface access to the land under license, has been provided by the Beneficiaries of the proposed Project.

D. Relationship with Subunits

5.7 While overall coordinating and controlling fun lions are carried out by the Producer Association, each Association delegates some rights to its NGDUs, including the rights to conclude contracts, operate current bank accounts, manage the property entrusted to them for the purposes stipulated in their charters, and decide on labor issues. The scope of these rights is determined by the Producer Association and specified in the NGDU's by-laws, which are also approved by the Association. Tbe status and power of NGDUs vary substantially according to the amount of power the parent Producer Association vests in them. Some NGDUs are allowed to enter into external contracts, participate in foreign joint ventures, maintain settlement bank accounts in addition to simple current accounts and take on debt.

5.8 Since NGDUs will play a critical role in implementing the proposed Project, it is important to ensure that relationships between the participating Producer Associations and their NGDUs remain stable. Establishment of the Producer Associations as joint stock enterprises has clarified the relationship and provides the mechanism for stability. None of the NGDUs of the Associations participating in the Project have the status of separate legal entities. The NDGUs of the participating Associations have also been involved from the beginning in defming and preparing the proposed Project.

E. Accounting Systems

5.9 All Russian enterprises use the national accounting system that is based on a unified chart of accounts and specified rules for recording all transactions. These accounts have historically been driven by tax and state reporting needs. A new unified system of accounts was introduced in February 1992. This system, based partly on international Generally Accepted Accounting Principles (GAAP) and arising from a United Nations sponsored accounting review, is considered an improvement over the previous system but still dictates the recording of all financial transactions based on standardized rules and accounts and not on accounting principles'. Accrual based accounting was adopted in principle in 1992 and implementation is currently underway. The planned transition to international GAAP over the next few years is creating great uncertainty as most Russian accountants are not familiar with the concepts of GAAP.

5.10 The accounting systems in the Producer Associations generally provide an adequate structure for maintaining Project accounts. Transactions are recorded at the NGDU level where Project iInplementation will occur, the law requires that transactions be appropriately documented, and there are sufficient numbers of trained accounting clerks at each NGDUJ. However, recording errors still occur. Instances of unrecorded fixed assets are common, and since enterprises rarely take trial

I/ A numberof other initiativesin generalaccounting reform are underway, including: (i) EU fundingof ongoing work in accountingreform by the InternationalAdvisory Board (a group of Bank, internationaland Russian governmentand academicexperts), (ii) UN sponsoredtranslation of well-knownUS accountingtext books, (iii) the BritishCouncil's funding of coursesfor 40 accountingtrainers, and (iv) WorldBank funding of trainer programs. 24 balances, errors are prevalent at the end of the accountingperiod. Experience has shown that some transactions, such as the recording of foreign currency or intra-enterprise payments, can create problems when they are not adequately prescribed in the unified system. Enterprise accounting also shows a lack of regard for materiality: for instance, numerous insignificantitems might be recorded while major items may be lumped within miscellaneousaccounts.

5.11 In general, Producer Associationshave computerized only payroll, fixed assets and contract accounting. All Producer Associations are in the process of increasing computerization but are hindered by a lack of finances, trained staff and adequate software. Most Russian accounting software is poorly designed and with the volatility of the Russian chart of accounts, quickly out of date. International accounting software that can prepare accounts in different formats is often adopted for use in foreign joint ventures but is not a long term solution for Producer Associations' overall accounts.

5.12 The management information systems of the Producer Associations will require substantial improvementssince they have been geared to satisfying information requirements for the Ministries, not internal managementneeds. The enterprises are increasingly required to make strategic decisions that were previously made by the old Ministries of Oil and Geology. Capital budgeting procedures and criteria will need to be developed and supported by the information system. Cash management is also an unfamiliar and critical task currently facing the Associations.

5.13 During discussions with the Associationsit was agreed that financial advisory services would be provided to support Project implementationand the Associations in general (para 6.20). These specialists would help ensure that project accounting procedures meet the Bank's requirements, provide short-term advisory services in critical areas such as cash management, assist in the preparation of financial statements according to international standards, and provide training in international oil and gas accounting practice. The specialists will come from one of the large international accounting firms familiar with both Russian and international oil and gas accounting. Terms of Reference for the proposed fiancial advisory services are provided in Annex 6-7.

5.14 A longer-term consideration, associated with privatization in particular, will be the need to re-establish the Associations' financial positions. Current balance sheets are misleading for a number of reasons. The historic cost basis of fixed assets results in serious underestimation of the current economic value of the assets2. The value of oil reserves are not included in the Association's assets. Conversely the balance sheets typicallycontain non-oil assets (such as farms and social infrastructure) and are often inflated by double counting. Uneconomicand obsolete assets currently on the balance sheets (such as dated receivables) will need to be written off and, by international standards, capital investment (for example, drilled wells) is generally high relative to production levels. Re-estimation of the Associations' balance sheets will need to be conducted from the perspective of the net present value of future earnings. Simple revaluation of assets to current prices will not provide an accurate picture of the Association's economic value. The current process of selling shares in the integrated holding companies, such as Lukoiland Yukos, to the domesticand internationalmarkets will provide initial indications of company values.

2/ The value of currentassets exceeds the valueof fixedassets for each Associationin the Project. 25 F. External and Internal Audits

5.15 The preparation of pro-fonna financial statements based on the Russian chart of accounts is mandatory in Russia. Statements of income and balance sheets are submitted quarterly to the Government. However, external audits of these statements are only required where a foreign joint venture or foreign trade is involved. Otherwise the Producer Associations do not have formal external audit arrangements. Tax inspections (compliance audits) occur periodically but are not mandatory. Tax audits are adversarial, and mainly involve checking that all transactions have been recorded in accordance with Russian law and include a review of documentation, co- ract formats and compliance with legal requirements. This type of audit requires a very detailed and lengthy review of the Producer Association's manual ledgers. A typical GAAP audit based on Generally Accepted Auditing Standards (GAAS) is not required.

5.16 Currently over 1,000 firms offer audit services in Russia includingthe "big six" international finms. The international accounting fims are well established and active in Russia, some with a large contingent of Russianaccountants and auditors trained in internationalGAAP. The audit firms in Russia currently operate without license or regulation3. During 1993 the Russian administration and previous legislature deliberated draft national legislationaimed at establishing a framework for accounting, record-keepingand reporting as well as prescribing certain minimumaccounting concepts and standards generally along the lines of GAAP. While the draft law cleared all parliamentary hurdles it was vetoed by the executive. In its place a decree, 'Temporary Rules for Audit", was issued in December 1993. Passage of a law governing accounting and audits is expected during 1994.

5.17 Internal accounting controls in the Associations are maintained through internal audit departments that typically have two to four staff. Overall accounting resources range from 8 to 18 people in the Producer Association, and a greater number within the NGDUs. The chief accountants of the NGDUs report to the chief accountantof the Producer Associationwho in turn reports directly to the Director General of the Association.

5.18 Prior to initial loan disbursement the Producing Associations participating in the proposed Project will be required to appoint external financial auditors acceptable to the Bank. The proposed audit law for Russia should be in place prior to submission of the first set of audited financial statements from the Associations and will provide the framework for audits and financial reporting. If this law is delayed, then in the interim, GAAP based audits of the Association's Statements of Income and Cash Flow should be possible, since accrual accounting is under implementationand a qualified restatement of the accounts to GAAP is possible. However, a GAAP audit of the Association's Balance Sheets will not be meaningfuluntil rules governing revaluation are established.

31 A Bank ImplementationMission in late 1993 shortlisted 8 Russian audit firms as acceptable to conduct audits of Project accounts for Bank projects. These firms were deemed capable of conducting full financial audits of borrowersonly in association with one of the "big 6" international audit firms. 26 5.19 The participating Producer Associations will furnish to the Bank:

(a) Actual and forecast financial statements, within three months of the end of each fiscal year;

(b) Audited project accounts beginning with the account for fiscal year 1994, within six months of the end of each fiscal year; and

(c) Audited financial statements of the Association (including a qualified restatement in accordance with GAAP if required) showing their performance and position beginning with fiscal year 1994, within six months of the end of each fiscal year.

G. Financial Situation and Prospects

5.20 The Producer Associations in Western Siberia have generally experienced severe erosion of their fimancialpositions over the past five years. The most vLsiblecause of this erosion is the sharp drop in production as shown in Table 5.1 below. Overall production levels in Western Siberia declined by almost 40% over the period 1988 to 1993, from 409 million tons per year to 248 million tons. The causes of production decline are varied: inadequate investment in new fields to replace mature reservoirs; idle wells due to shortages of production equipment; premature water breakthrough; and a disincentiveto reactivate idle wells due to inadequateproducer revenues. A lack of fimancialreserves, low producer prices and reductions in Government budget allocations are the root causes of the low levels of investment in Western Siberia over the past five years. During the past two years a further complication has been the rise in inter-companyarrears, resulting from the economic restructuring, friction in the banking system, and the disincentive to pay under conditions of high inflation. Only in April 1994 were Associations formally allowed to stop shipments to delinquent customers4. The upstream oil sector was collectively owed in excess of 6.4 trillion rubles (US$3.5 billion) at end February 1994 and in mm owed suppliers and the Government a similar or greater amount.

Table 5.1: Annual Oil Production by Association (million tons)

Producer 1988 1989 1990 1991 1992 1993 Association

Megionneftegas 21.5 19.7 17.3 16.7 14.6 13.5

Tomskneft 14.5 14.9 15.0 14.0 12.0 11.6

Yuganskneftegas 68.3 65.3 59.1 50.5 40.8 33.4

Westem Siberia 408.7 404.5 374.6 332.4 287.0 248.0

Western Siberia 1% 7% 11% 14% 13% Annual% Decline

4/ Presidential Decree #307, April 8, 1994 27 5.21 Productiondecline has not been uniform across the participatingProducer Associations. Megionneftegas(MNG) has dropped37% over the past five years;Tomskneft (TN) has lost 23%; Yuganskneftegas(YNG) productionhas droppedby 51% and the super-giantMamontova field in Yugansk, over 70%. Variationsbetween Producer Associationsstem from different reservoir characteristicsand age, managementcapability and location.

5.22 All ProducerAssociations face seriouscash flow problems. In early 1992,losses stemming from productiondecline were compoundedby increasesin inputcosts of 30 to 60 times, as supplier prices were liberalized,while oil revenuesincreased much less under state price control. Decree 1089of September1992 provided Associations with the abilityto raise pricessubject to a price limit of 1.5 dmes productioncosts and subject to their ability to negotiatethe increasedprices in the market. This led to a fourfoldincrease in averagecrude oil prices. In 1993, the price limit was abolished. Prices have been more or less freely negotiatedsince and constrainedonly by export limitationsand conditionsin the domesticmarket. While producer revenues improved, cash flow was still poor because of worseningcustomer payment problems. Trade receivablesfor the three Associationsincluded in the proposedProject explodedto over 30% of sales during 1993. The Associationsrely heavilyon barter as one means of managingcash flow under these conditions. Cash flow will improveas oil price reformcontinues but the ProducerAssociations are likelyto face paymentproblems for some time as the downstreamoil sector goes throughsignificant structural adjustment. Controlof cashflow duringthe currentperiod of high inflationand sectoraladjustment will be one of the most criticaltasks facingmanagement.

5.23 Arrears to oilfield suppliers rose dramaticaly in response to these cash shortfalls, exacerbatingthe problemof oilfieldequipment shortages. The Associationsare also often in arrears on salaries, contributingto a loss of experiencedstaff. The ProducerAssociations currently have limited scope to reduce staff and operadngcosts in responseto these changes, although many externaldrilling crews have been dismissed. Makingthe necessarystructural adjustments (notably in labor productivity)to minnize cost escalationand retaincash flow for new fielddevelopment will be a majorchallenge for the Associations.Capital and labor productivityis substantiallybelow that of internationaloil companies.Further details of the ProducerAssociations' historic financial status are providedin Annex 5-3.

5.24 Improvementin sector financialperformance has been supportedthrough a number of Governmentreforms over the past two years, includingliberalization of the domesticcrude oil market to allow Producers to negotate prices freely with domesticbuyers; provisionof export permitsfor incrementalproduction from major rehabilitation projects and new fields;export tax relief where commensurateinvestment occurs; excisetax relief for high cost production,and profit tax relief through asset revaluation,accelerated depreciation and investmenttax credits. Continued progresson domesticprice, tax and marketreform is plannedas summarizedin Annexes3-2 and 9-1. 28 5.25 In the medium to long term, the Producer Associationshave the resources to regain financial viability. While oil production has declined, each Association still holds significant oil reserves5 . The Producer Associations have well-trained and innovative technical staff. How quickly and effectively the Associations are able to develop the management skills needed for commercial operations is a critical and unpredictable factor for future success. That the three Associations participating in the proposed Project are willing to work with internationaloil companies is a positive sign. Project advisors (see para 6.20) will provide furrther support for this transitiot. The Associations currently have low financial risk as they are not encumbered with long-term debt. However, short-term debt and payments arrears have increased dramatically in the past year and it is uncertain what fixed financial obligations to the state will be established as part of privatization and whether these obligations will reflect realistic asset values.

VI. TlHE PROJECT

A. Project Objectives

6.1 The proposed Project's principal objectives are to: (i) slow the rate of oil production decline in Western Siberia and thus strengthen the Russian Federation's ability to earn foreign exchange in the near term; (ii) transfer international technical, environmental and managerial practice to the operation of oil fields in West Siberia; (iii) promote a more efficient and environmentallysustainable use of Russia's petroleum resources; and (iv) through policy consultations, continue past support to sector reforms conducive to attracting the equity and loan finance anc international participation necessary to reverse the oil production decline.

B. Project Description

6.2 The investment intervention in the oil sector most likely to yield early economic benefits is the provision of essential inputs to support current oil production operations. Oil production has fallen in recent years at a faster rate than normal reservoir decline would dictate due to curtailment of normal workover operations, reduced in-fill drilling and lack of spare parts to replace equipment such as inoperative pumps. By some estimates 35,000 production wells in Western Siberia are inoperative. Since Western Siberia represents over 70% of national oil production, this level of shutdown has a critical impact on one of Russia's key sources of foreign exchange. The Siberian Scientific Research Institute estimates that 70% of these idle wells can be restored with simple workover investments. The location of the West Siberian basin in relation to the other main oil producing basins in Russia is shown in Map IBRD 24146R1.

6.3 The proposed Project will focus on Producer Associations in Western Siberia. Map IBRD 24145R1 indicates the locations of the main petroleum Producer Associations of Western Siberia.

5/ Estmated recoverableoil reservesin the eightfields covered by the Projectare: 30 milliontons for MNG, 240 milliontons for TN and 375 milliontons for YNG. Theselevels represent in excessof 15 years of currentproduction for each field. The Associationseach hold significantadditional reserves in other fields. 29 During Project preparation, a number of Producer Associationsin West Siberia were approached and visited. The number of Producer Associationsto be included in the proposed Project is limited to three to facilitate speedy project preparation, avoid unduly complex implementationarrangements, and ensure the availability of a critical mass of resources to each. Megionneftegas, Tomskneft and Yuganskneftegasare included based on the following criteria:

(a) The quality of programs proposed by the Associationand their early response to the opportunityto participate in the Project, and their willingnessto support rapid project preparation;

(b) The openness of management towards innovation and their desire to move quickly towards commercializationand market-orientedoperations, and

(c) The presence of internationaloil companies in the Association (in service contracts, joint ventures or other arrangements), which is an indication of the willingnessof the Association to be open towards private capital and new technology.

6.4 Based on a technical review of the geology of selected fields, and a well-by-well assessment of the work programs planned to be undertaken by the three Associations, the following general components are recommended for inclusion in the proposed Project for each Association:

(a) Oil Field Modernization: A two year integrated program of oilfield rehabilitation which will comprise: modernizationof approxiinately1,200 wells includingprovision of measuring facilities; and reconstructionof associatedsurface facilities, particularly, oil pipelines (over 800 km) and water conduits, with corrosion resistant pipe. The programs will be focussed on wells and surface facility replacement in up to three fields within each Association to ensure investments are sufficiently concentrated so that workovers are fully supported by reliable surface facilities. The criteria for selecting the fields focused on economic returns but also considered the potential impacts of future programs in the field. Since the well operations would not occur until early 1995 they should not interfere with wells currently under contract to other parties.

(b) In-fill Drilling: Programs of in-fill and step-out drilling (127 wells) have been identified in each Association including the drilling of horizontal wells from existing wellpads. Horizontal wells are recommended to avoid drilling in environmentally sensitive regions of the field and to increase productivity rates per well, thereby reducing the number of wells required to efficiently drain the reservoirs.

(c) Environmental Protection: Support for environmental protection wiU be provided through; enhancement of the Association's emergency response capabilities, environmental monitoring and managementtraining including assistance in planning programs to safeguard the interests of national minorities in or near Project areas and through trial clean-up programs, such as bioremediation, for previous spills and damage. This support will includeprovision of training, manuals and equipment, such as vacuum trucks, skimmers, laboratories and testing facilities. 30 (d) Field OptimizationStudy: A comprehensive field optimization study will be carried in one of the fields currently under production within each Association. This study would be aimed at identifyingand evaluating optimal plans for future operation of the field including both subsurface and surface facility considerations. This study will re-examine current development strategies with the goal of establishing whether the field could be exploited with a reduced number of wells at an in-situ reservoir pressure considerably lower than present. The program would include provision of computer equipment and services, such as workstations and software support, plus training to undertake reservoir analysis and simulations. The study would be carried out by engineers within the Associations, supplementedas needed by experts from the Russian oil research institutes and international experts.

6.5 Projects of the type proposed can be implemented relatively quickly. Implementation is expected to occur over roughly a 2-year period once equipment reaches the field. Comparable programs underway in Western Siberia arc being completed in similar or even shorter periods. The estimated project cost is US$678 million (including 15% import duties). The workover and drilling programs included in the Project are derived from broader investmentprograms and equipment lists provided by the Associations. It is important to note that the programs (and therefore the equipment and services lists) were derived during project preparation, based on the situation prevailing at that point in time. There will inevitably be some changes in the composition of the equipment and service lists at the time of implementation. A sufficient level of flexibility has been built into the procurement arrangements to accommodatethese changes.

6.6 Annex 6-1 provides technical background and details of the proposed Project including the geological setting, current operations and plans of the Associations involved, and the programs recommended for consideration under the proposed Project. Some of the main technical issues and how they would be addressed are discussed below.

6.7 While there is clearly an abundance of high-calibre technical staff in the Producer Associations, production decline cannot be reduced simply by providing goods and services to the Producer Associations. Historic technical and incentive constraints are gradually diminishing, but there is still a risk that equipment could be deployed in the workoverl drilling of low-productivity wells that would not be economically and financially viable, unless appropriate measures are introduced in the project design. The workover screening practices of the Associations have been audited by technical consultantsand found to be adequate. Nonetheless, screening of well candidates at the time of implementationwill be essential to select wells with sufficient productivity potential. This screening would be accomplished through review of work plans by consultant technical specialists attached to Project hnplementation Units (PIUs), which would be established in each of the participating Producer Associations and charged with the responsibility of implementing the Project. The structure and staffing of the PIUs are discussed in paras 6.19-6.22. In addition, the PIUs, assisted by the technicalspecialists, would help determine technical changes that could enhance operational efficiency and increase productivity. To enable this, the PIU would need to:

(a) Realign performance criteria to conform with economic oilfield development practices. This would entail departure from previous practices such as assessing the 31 performance of drilling enterprises by the number of meters drilled; and construction enterprises, by the length of pipe laid or the number of welds per day.

(b) Introduce new technology where required. This would entail departure from uniform, standardized approaches for a wide range of applications, with more attention to specific requirements of individual fields and wells. The application of sub-optimal techniqueshas led to a number of major problems. A prime example is the excessive waterflooding of fields which has added substantially to the cost of production and affected the overallrecovery from reservoirs. Other examples include: the excessive production of water which is transported over long distances before separation; and the inhibition of well productivity by setting subsurface pumps at uniformly shallow depths due to technical constraints.

6.8 To enhance the productivity of wells included in the Project, particularly in areas where the rate of production under existing techniques would be marginal, it is proposed to lower the sub- surface pumps, in addition to improving producing zone segmentation and casing perforation. Although greater pump depth will require heavier tubing and increased rig capacity, productivity increases between 50-100% are expected to be achieved. The Project will also introduce limited horizontal drilling of new wells. This technique will not only reduce the number of vertical wells normaUlyrequired to drain the reservoirs, thereby reducing future operating expenses, but will also minimize environmental impacts, especially in environmentallysensitive areas. On waterflooding, while it may not be feasible to substantially change the procedures in the short-run, the Field Optimization Studies proposed under the Project would provide the basis for improvements in the future. Further discussion of technical issues is included in Annex 6-2. The recommended scope of work for the Field Optimization Studies is contained in Annex 6-3.

6.9 In early 1992 the Government promulgated Decree IOR enabling private oil companies to invest in workover operations and be paid through an exportable share of the incremental oil production resulting from these operations. The program was extended in March 1993 via Government Resolution #179 and broadened to allow cost recovery for local and foreign service contracts in addition to direct investment. These workover programs, while not the long-term solution to production decline (which will require substantial new field development), are to be encouraged as a short-term measure. To date contracts for the rehabilitationof over 8,000 wells have been signed. Some of these programs are being innplementedwithin the three Associations in the proposed Project and care has been taken to ensure that the Project does not interfere with, but rather complements, the efforts of the private sector. Indeed, the presence of private sector operations and the associated technical expertise would be beneficial to the Associations and the proposed Project.

C. Project Cost Esthnates

6.10 The costs of individual Project components based on a roughly two-year disbursement between late 1994 and end-1996, are summarized in Table 6.1, for the participating Producer Associations.

6.11 The basic procurement packages for the Project are summarized in Table 6.2 including physical and price contngencies by package. Further details on quantities of items and scheduling 32 of costs are given in Annex 6-4. As noted in para 6.5, sufficient flexibility has been built into procurement arrangements to enable changes in the composition of equipment and services for each of tie Producer Associationsto take into accountchanging conditionsduring project implementation.

Table 6.1: Project Cost Breakdown by Component

(US$ million equivalent)

Project Component Meglonneftegas Tomskneft Yuganskneftegas Total Number Cost Number Cost Number Cost Number Cost OPERATION 1/ WeUlWorkovers 75 16 525 111 576 121 1,176 249 In-Fill New Wells 76 120 11 14 40 67 127 201

Surface Facility Installation(kn) 255 20 576 47 - - 831 67 EnvironmentalManagement 5 5 5 15 Field OptimizationStudy 3 8 8 19 UnallocatedRig Costs & Misc. 2 6 17 25 ImplementationTA 4 5 4 12 Sub-Total 169 195 223 587 Import Duties 2/ 15 18 20 53 Interest During Constr. & Fees 12 12 14 38 Total FinancingRequired 3/ 196 225 257 678

Notes: 1/ Costs include 6% physicalcontingencies plus average price contingenciesof 2% from late 1993 cost estimates (source: Staff estimates).

2/ Oil producers are required to pay 15% import duties on equipmentand materials.

3/ Numbers may not add due to rounding. 33 Table 6.2: ProJect Cost Breakdown by Goods and Services

(US$ million equivalent)

Goods and Services Megionneftegas Tomnskneft Yuganskneftegas Total Local Foreign Total Local Foreign Total Local Foreign Total Costs

1. Equipment & Materials BaseCost - 92 92 116 116 - 128 128 336 Physical Contingencies 1/ 6 6 . 10 10 10 10 26 Price Contingencies I I - 2 2 - 2 2 6 Total Cost 99 99 - 128 128 - 140 140 367 2. Connmodities Base Cost 7 7 - 2 2 4 4 13 Physical Contingencies - 0 0 - 0 0 - 0 0 1 Price Contingencies - 0 0 0 0 0 0 Total Cost - 8 8 2 2 - 5 5 14 3. Services Base Cost - 34 34 20 20 - 34 34 88 Physical Contingencies - 2 2 - 2 2 - 2 2 6 Price Contingencies - 1 1 0 0 1 1 2 Total Cost - 37 37 - 22 22 37 37 96 4. Technical Assistance Base Cost - 6 6 - 8 8 - 7 7 21 Physical Contingencies - 0 0 1 1 1 1 2 Price Contingencies - 0 0 - 0 0 0 0 0 Total Cost - 6 6 - 8 8 - 8 8 23 5. Local Labor/Consuction Base Cost 19 - 19 35 - 35 32 - 32 85

Physical Contingencies - - - .. Price Contingencies 0 - 0 1 - I 1 - 1 2 Total Cost 19 - 19 35 - 35 33 - 33 87 6. Local Transport Base Cost - - - - - Physicat Contingencies - -

Price Contingencies . . . .- Total Cost . . 7. Import Duties /2 15 - IS 18 - 18 20 - 20 53

Total Base Project Costs 34 139 173 53 145 197 52 174 226 596 Physical Coningencies - 8 8 - 12 12 - 13 13 34 Price Contingencies Q _ 3 1 3 3 1 3 4 10 Total Project Cost /3 35 150 184 53 160 213 53 190 243 640 8. Interest During Constr. on IBRD Loan - 12 12 - 12 12 - 14 14 38

9. Total Financing Required 35 161 196 53 172 225 53 204 257 678 Notes: 1/ Costs include 6% physical contingencies plus average prce contingencies of 2% from late 1993 cost estimates.

2/ Oil producers are required to pay 15% import dut on equipment and materials.

31 Numbers may not add due to runding. 34

D. Financing Plan

6.12 The financing plan outlined in Tables 6.3 and 6.4 includes an IBRD loan of IUS$500million equivalent. The Producer Associationswould be responsible for US$141 million equivalent of local costs, including import duties totalling approximatelyUS$53 million equivalent, and US$38 million in foreign exchange for interest and other fmancingcharges during the implementationperiod. While co-financing was soughtduring Project preparation to fill the financinggap for a larger project it was not possible to conclude arrangements on a basis acceptable to all relevant parties.

Table 6.3: Proposed Financing Plan by Institution (US$ million equivalent)

Financing Source Local Foreign Total % of Total

IBRD - 500 500 74% Producer Associations 141 38 178 26%

Total 141 538 678 100% Percent of Total 21% 79% 100%

Table 6.4: Proposed Financing Plan by Component and Association (US$ million equivalent)

Financing Source Megionneftegas Tomskneft Yuganskneftegas Total Local Foreign Total Local Foreign Total Local Foreign Total Costs

IBRD - 150 150 - 160 160 - 190 190 500

Producer 35 11 46 53 12 65 53 14 67 178 Associations Total Financing 35 161 196 53 172 225 53 204 257 678

6.13 The proposed IBRD loan would be available to partly finance equipment, materials, services and technical assistance in each of the participating Producer Associations. Direct disbursement procedures will be used to ensure that funds flow directly to the proposed Project. Special Accounts would not be utilized. Project Agreements would be concluded between the Bank and each of the Associations. A Loan Agreement would be concluded with the Russian Federation, represented by the Ministry of Finance. Subsidiary Loan Agreements would be concluded between the Russian Federation and each of the Associations.

6.14 The Bank loan would be from the Currency Pool with a maturity of 17 years, including 5 years grace, at the Bank's standard variable interest rate. The on-lending terms to the Associations would include a maturity of 10 years, including 2 years grace, at the Bank's standard variable 35 interest rate plus an on-lending premium equal to 75 basis points payable to the Government. Revenues going to the Government as a result of the mismatch in grace periods will be re-lent to fmance projects in each of the participating Producer Associations, including projects for the mitigation of adverse environmental impacts and for the support and development of indigenous peoples. The Subsidiary Loan Agreements will include mechanisms to accomplish this and assure adequate review and supervision of the projects so financed.

6.15 Since project cash flow is greater in the early years due to the declining production profile, equal annual principal payments have been chosen by the Borrower, as opposed to an amortization schedule more heavily weighted to the later years.

6.16 While the Associationsmeet eligibility criteria for a Single Currency Loan (SCL) and would benefit from a SCL loan, which would match US dollar revenues from the export of incremental production from the proposed Project with a US dollar liability, the pilot nature of the SCL program precludes use of a SCL loan at this time.

6.17 The lending arrangements, legal linkages, flow of funds and the flow of goods and services under the Bank's loan are presented in Annex 6-5.

E. Insurance

6.18 Insurance for goods and services to the point of delivery to the Producer Associations would be covered under the bids from suppliers. In addition, an umbrella logistics/shippingcontract may be used, as in the First Oil Rehabilitation Project, to cover inspection, expediting and shipping services from supplier to Project site. Insurance coverage for the operations of the Producer Associations has historically been provided through budget transfers from the Government. This arrangement will continue under current ownership conditionsthrough the holding companies which own majority shares in the Producer Associations. The Associationsare effectivelyself-insured with risks shared among the different Associations. Self-insurance is an accepted practice in the international oil industry due to the high cost of external insurance. The Russian insurance industry is also not well developed at this time. While there are over 900 insurance finms, they are generally small and inadequatelycapitalized. The majority are likely to disappear once the proposed Insurance Law (expected to be introduced to Parliament this year) is passed. Only a few Russian insurance firms could potentially provide coverage to the upstream oil sector although they have no experience with the sector at this time. The cost of insurance coverage could range from 0.5% to 2.0%, depending on the state of facilities and the risk inherent in the operations. Premiums will likely tend to the higher end given the lack of maintenanceover the past 5 years. The insurance industry would also be unlikely to provide significant enviroznental liability coverage.

F. ImplementationArrangements

6.19 For each ProducerAssociation involved in the Project,a ProjectImplementation Unit (PIU) would be establishedwhich consists of the followingRussian staff to be designated by the Association:a Project Director would head the PIU and would be supportedby a Technical Manager, ProcurementManager, Finance Manager and a Logistics/Administrative Officer. In additionto the PIU, each of the ProducerAssociations would form a Field TechnicalUnits at the 36

NGDU level consistingof the following staff designatedby the Association: a Geologist, a Reservoir Engineer, a Production Engineer, a Drilling Engineer and an Environmental Specialist. Project Directors have been appointed and are in the process of assigning personnel to the PIUs.

6.20 To strengthen each PIU, consulting support services would be provided under the proposed loan to assist the Technical, Procurement and Finance Managers. In order to facilitate project implementation, it is required that internationally known firms conversant with Russian and Bank practices be selected to provide the following specialists for each PIU;

(a) Specialists to support the Technical Manager would likely include: a geologist/reservoir engineer, a production engineer, a drilling/ workover engineer, a pipeline engineer and an environmental specialist. These and other home office specialists would provide advice on project implementation to the PIU Technical Manager in their respective areas of competence. This advice would be extended to the NGDU level through the Field Technical Units;

(b) The Procurement and Logistics Managers would be supported by a procurement specialist and a logistics/ materials management specialist to advise on the required procurement procedures under the loan and to assist in all aspects of the procurement process including the preparation of bid documents, evaluation of bids, the preparation of contracts with suppliers of equipment and services, expediting, inspection, transport, logisticsand disbursementprocedures. These persons will assist local procurement specialists contracted to assist the Associations. In view of the urgency of commencing these activities as soon as possible, the Technical and Procurement Specialists will be financed under a PPF advance; and

(c) Financial specialists would assist in establishing project accounting procedures, facilitate the preparation of financial statements which conform with international standards, and provide general financial advice to the Producer Association.

6.21 The organization chart of the PIU is presented in Annex 6-6. Draft Terms of Reference of the consultant specialistsare included in Annex 6-7. Once the Technicaland Procurement Specialists are established in each of the Associations, it is expected that the bidding process for the other specialists would be initiated.

6.22 On-the-jobtraining will be provided to Producer Associationmanagers through the specialists supporting the PIUs and the technical service contractors. Training in field development plaming will be provided within the proposed Field Optimization Studies. General training in enterprise management for all the Producer Associations in West Siberia is envisaged under the Bank's proposed Project for Management and Financial Training and the European Union's management training programs established at Tyumen University.

6.23 Project supervision, as detailed in Annex 6-8, will entail 45 staff-weeks per year, with four supervision missions during the first year of implementationand three during the second. 37 G. Reporting Arrangements

6.24 Reporting arrangements are particularly important given the nature of the Project, which will require frequent adjustment of the work program to compensate for changing conditions during implementation.Agreement was reached with the Associationsthat their respective PlUs will prepare monthlyprogress reports on physical progress of the project, procurement status, costs incurred and anticipated, disbursements, administrative and institutional performance. In addition, the project accounts will be audited annually by independent auditors satisfactory to the Bank according to acceptable auditing standards. Understandings were reached on the submission of fimancial statements, and audited accounts for the Project and for each Association (see para 5.19). The Associations will be required to submit copies of all consultants' reports to the Bank and prepare a Project Completion Report within six months of Project completion.

H. Procurement

6.25 Table 6.5 summarizes the methods of procurement proposed to be used for the IBRD loan. Details by Producer Association are given in Annex 6-9. As mentioned in para 6.5, procurement arrangements are structured so as to be sufficiently flexible to deal with adjustments in the work program during project implementation.

6.26 As shown in Table 6.5, the equipment and services to be financed by the Bank consist of the normal items needed for well comipletions,repairs and workovers on any oil production rehabilitation project. The purchased rigs, flowlines, casing, tubing, pumping and processing equipment, and some chemicals (US$367 million or 73 % of the Bank loan) are available from a large number of potential suppliers and will be procured following InternationalCompetitive Bidding (ICB) procedures.

6.27 Oilfield services (well logging, cementing, drilling, MWD and stimulationservices) and some of the chemicals are highly specializedand available from only a small number of qualified foreign suppliers and contractors and will, therefore, be procured following Limited International Bidding (LIB) procedures. As mentioned in para 6.18, an umbrella logistics/shippingcontract may be used, as in the First Oil RehabilitationProject, to cover inspection, expediting and shipping services from supplier to Project site. These services would also be bid using LIB procedures. An allowance of US$2 million for each Association will be provided under the loan for miscellaneousequipment and materials to be procured using international shoppingprocedures in cases where quick procurement is necessary. The maximum size of any single contract using this method will be US$300,000 and will be subject to prior Bank review. For specializedequipment or where only one qualWiedsupplier exists, small contracts, valued at less than US$50,000, may be procured using direct contracting procedures to an aggregate amount of US$1 million per Associationand subject to prior Bank review in each case. 38 Table 6.5: Su=mary of Proposed Procurement Arrangements (US$ million equivalent)

Goods and Services IBRD Financing N.B.F. /1 Total

ICB Othr Costs /2 t. Equipment & Materialsl

1.1 Workover /Drilling Rigs 58 58|

1.2 Well Materials 53 53

1.3 Infrastructure 63 - - 63

1.4 Pumping Equipment 97 - - 97

1.5 Processing Equipment 32 - - 32

1.6 Environmental Equipment 12 - 12

1.7 Support Equipment 26 - 26

1.8 Miscellaneous Equipment 17 9 - 26

Total Equipment and Materials 358 9 - 367

2. Commodities

2.1 Drill Bits 9 - 9

2.1 Chemicals 3 3 - |

3. Services

3.1 Well Services 26 - 26

3.2 Rig Services 65 65

3.3 Pipe Laying Services 5 5

4. Consulting

4.1 Field Opdmizadon TA 8 8

4.2 Implementation TA 15 - 15

5. Local Costs

5.1 Labor/Construction .. 24 24

5.2 Infrastructure - 60 60

5.3 Eng. & Management 4 4

6. Import Duties (15%) - 53 53

7. Inerest During Constr. & Fees - 38 38

8. Total 370 130 178 678

I/ nN.B.F.' means 'Not Bank financed'. The amounts shown in the N.B.F. column inchludeUS$178 million from the Prducer Associations. The medtods of procuement in the IOther' column include LIB (US$99 million). intemational shopping (US$6), direct contractng (US$3) and selection of consultants (US$23 milion) according to the Bank's Guidelines for the Use of Consultants.

2/ Numbers may not add due to runding. 39

6.28 A Country Procurement Assessment report for Russia has been initiated but not finalized. Use of local procurement procedures will be limited to the procurement of: minor oilfield equipment and services; rig crews; flow line crews; and local services. For these activities, which the Bank will not finance, local procedures are considered acceptable.

6.29 Any interested supplier from Russia or one of the former Soviet Republics will be allowed to bid on the ICB packages but only a limited number of manufacturers exist (particularly in Russia) which are API-certified or equivalent and therefore qualified to supply equipment to the required standard. Nevertheless, the bidding documents for lCB procurement will include the Bank's standard domestic preference provisions for the procurement of goods so that any eligible and qualified Russian manufacturer will be allowed to benefit from the preference, should they bid. This would include Russian/internationaljoint ventures which meet domestic value added requirements. During the first year of implementationof the First Oil RehabilitationProject, a few contracts were awarded to Russian bidders. The Bank is currently preparing a technical assistance project to enhance the international competitiveness of Russian oil equipment manufacturers and will hold seminars to introduce them to Project-related bidding opportunities.

6.30 Procurement for the Project will be handled separately by each Producer Association. Since the Associations have only limited direct experience in the procurement of imported equipment and services, (having been permitted by the Government to enter into such transactions for the first time in early 1992), consultantprocurement specialistswill be assigned to the Project ImplementationUnit in each Association to assist the Association to carry out its procurement responsibilitiesunder the loan efficiently (para 6.20). Termisof Reference for the Technical and Procurement Specialists are given in Annex 6-7. Execution o- the services is expected to start by August 1994. The experts will be selected according to the l,ank's Guidelines for the Use of Consultants. In addition, the Associations have contracted v h Moscow based consultingfirms to provide procurement assistance and liaison and communicatiu. with the bidding community and the Bank as was done successfully under the First Oil RehabilitationProject. All terms of reference will be subject to prior Bank review and all letters of invitation, evaluation reports and final contracts related to Bank funded consultant contracts in excess of US$50,000 will be subject to prior Bank review.

6.31 Approximately 50 bidding documents will be issued by each Producer Association in two roughly equal tranches covering the two drilling seasons. All ICB and LIB invitations to bid, bidding documents, proposals to award and final contracts will be subject to prior Bank review because of the Producer Associations' lack of familiarity with Bank procurement procedures. To streamline the review process and improve the qualityof procurement in general, ICB Standard Bidding Documents will be used. Specific bidding documents will be prepared and released prior to Effectiveness in order to facilitate maximum equipment delivery during the 1994/95 drilling winter season.

6.32 The PIUs will be responsible for preparing initial procurement plans and thereafter, monthly reports during early project implementation,updating the status of all required procurement actions. These plans will contain a detailed list of all bidding documents to be issued, a schedule for concluding each proposed contract giving the date when the draft will be ready for Bank review, when bid documents will be released, the bid opening date, when the bid evaluation report will be given to the Bank for its "no objection", when the contract is expected to be signed and when the equipmentwill be delivered or the services performed. Estimatedcommitted and final actual contract 40 cost information will also be included in these reports. Draft procurement plans have been completed.

6.33 A General Procurenient Notice was published in early June of 1994 in Development Business alerting potential bidders of procurement activities and the expected release of bidding documents.

I. Disbursement

6.34 The Bank's contribution to the proposed Project is expected to be employed in the following manner: US$367 for equipment (rigs, flowlines, casing, tubing, pumping, processing and environmentalequipment); US$14 million for drill bits and chemicals; US$96 million for specialized oilfield and pipeline services; and US$23 million for technical assistance to the Associations. The Beneficiarieswill finance interest charges and commitnent fees during Project implementationwhich together amount to US$38 million on the Bank Loan. Disbursement categories and amounts are sumnmarizedin Table 6.6.

Table 6.6: Disbursementof the IBRD Loan (US$ millions equivalent)

Category Amount/1 Disbursement 1. Equipmentand Materials/2 367 100%of Expenditures/3 2. Comrnodities 14 100%of Expenditures/3 3. Services: TechnicalOilfield 96 100% of Expenditures 4. TechnicalAssistance: Consulting 20 100%of Expenditures 5. Project PreparationAdvance 3 100%of Expenditures 6. Total 500

Notes: 1/ Numbersmay not add due to rounding.

2/ Including:rigs, linepipe, tubing,pumping, processing, environmental and miscellaneousequipment.

3/ 100% of foreign expenditures;100% of localexpenditures (ex-factory cost); and 70% of local expenditures for other itemsprocured locally. If local biddersare successful,the Bank will finance local expenditures as necessary.

6.35 The disbursement profile of the Bank's Loan is given in Table 6.7. The distribution over the roughly two-year implementationperiod (spread over three Bank fiscal years) is uneven, with 60% of the Bank loan disbursed during the first year of implementation.This is because some of the basic equipment such as rigs are required up-front to implement the Project. 41 Table 6.7: Disbursement Schedule (US$ million equivalent)

Bank Fiscal Year (endingJune 30) Goods and Services 1995 1996 1997 Total 1. Equipmnent& Materials 210 158 367 2. Commodities 5 9 . 14 3. Services 28 45 23 96 4. TechnicalAssistance 6 11 6 23 5. Total: 248 223 29 500 Cumulative: 248 471 500

6.36 Funds from the Bank Loan may be withdrawn under standard World Bank procedures which include reimbursement to the borrower of eligible expendituresprior to Effectiveness, direct payment to suppliers! contractors/ consultants, and Special Commitmentsto cover letters of credit.

6.37 Project implementationis expected to start immediatelyfollowing Effectiveness of the Bank Loan, expected by the fourth quarter of 1994, and the Project should be completed by late 1996. The closing date of the Loan will be July 1, 1997.

J. Technical Assistance

6.38 A technical assistance provision of US$23 million, allocated among the three participating Producer Associations, is included under the proposed Project:

(a) Technical, financial and procurement specialist support (US$12 million) for the Project ImplementationUnits (paras 6.7-6.8 and 6.20-6.22);

(b) Field re-development studies (US$8 million) at each of the three Associations to provide consultingservices, engineering and data upgrading for optimizingreservoir managementand field development for future operations; and

(c) Environmental specialists (US$3 million) to support development of environmental managementcapabilities including emergency response and pilot clean-up programs.

K. Environment

6.39 The Bank's OperationalDirective on EnvironmentalAssessment, OD 4.01, requires that large mineral extraction projects (including oil and gas developments) are to be classified as Category A projects. The OD requires the preparation and public disclosure of a draft Environmental Impact Assessment (EIA) prior to project Appraisal. 42 6.40 In the Russian Federation, the Ministry of Environmental Protection and Natural Resources has national responsibilityfor implementingthe very comprehensive 1991 Environmental Protection Law. Under this law, the Ministry implements "Expert Reviews" at State and local levels. These occur after completion of an EIA report.

6.41 International and Russian environmental consultants assisted the Producer Associations to prepare EIAs. These EIAs have built upon the work carried out under the First Oil Rehabilitation Project. Consultations with local groups were held by the Associations in January, 1994. Draft ElAs were submitted jointly to the Ministries of EnvironmentalProtection and Natural Resources and Fuel and Power in early February 1994. Clearance by the Govermnent of Russia and Local Enviromnental Authorities and submittal of the English language summary to the Bank occurred in March 1994. The EIA was circulated to the Executive Directors of the Bank and to the Public Information Center on March 17, 1994.

6.42 Despite a very well developedbody of environmentalprotection legislation in Russia, there has been, until recently, relatively little concern for the environmental impacts of oil development and poor enforcement of this legislation. This has been due to a lack of financial support and access to up-to-date equipment and services available internationallyin the oil and gas industry, as well as an overriding emphasis in the past on meeting gross production goals to support industrial investment.

6.43 Historic oil and gas activitiesin Western Siberia have had a very serious impact on all aspects of the regional ecology (land, forests, rivers, wetlands, groundwater, soil, air). Moreover, pollution migrating from the region via waterways and atmosphericdeposition pose serious problems for other regions.

6.44 The wide-ranging environmental issues in the West Siberian oil sector cannot be fully addressed under the proposed Project. The problems are immense and merit special consideration over a longer term. The Bank is in the process of preparing several environmentprojects, including one focusing primarily on the petroleum sector. The proposed Gas Injection Demonstration Project would involve investment to support gas flaring reduction and environmentallysustainable oil field development in a Western Siberian Producer Association. A second project, the proposed Environment Management Project, will include training for local administrators to help strengthen environmental management capabilities of administrations in Western Siberia in the areas of assessment, permitting, monitoring and enforcement.

6.45 Environmentalcomponents of the Second Oil RehabilitationProject will focus on mitigating environmentaleffects of implementingthe Project itself, improving the environmentalmanagement capabilities in the Producer Associations and carrying out pilot cleanup programs, such as bioremediation, to address past damage. hnported oil production technology will permit environmentallymore benign practices than current practices, for instance, through the use of closed containmentfor drilling fluids and biodegradabledrilling muds. Moreover, a key component of the Project, replacement of surface flowlines, will have marked beneficialeffects on the environment as discussed below. Since the proposed Project will not open "greenfield sites", it should not impose 43 additional environmental or social burdens on the roughly 125 indigenous people who are located near the Project areas6 .

6.46 The Project will help reduce environmental impacts, not only through rehabilitation and modifications of existing oil and gas production operations but also through provision of environmental cleanup and spill response equipment, analytical stationary and mobile laboratories, and corrosion testing facilities for each Association. Furthermore, pilot programs in the areas of remediation, revegetation and automation of flare systems will help provide the groundwork for cleanup of past damages through detailed evaluations and tests of alternativemethods for cleanupand mitigation. The overall budget for the specific environmental component of the Project is US$15 million, roughly allocated equally among the three Associations.

6.47 Positive Impacts: Rehabilitationof oil gathering pipelines, which accounts for US$67 million or roughly 12% of Project Cost, will reduce the risk of oil being spilled into aquatic and semi-aquatic ecosystems, one of the major sources of environmental damage in the past. In each of the Associations the gathering networks are prone to spills because the liquids being transported to the separation units have a high water content and over time this water content has led to corrosion of the pipelines. Average pipe life is as low as 3 to 5 years. Replacementof these leaking pipelines with non-corrosive pipe will significantlybenefit the environent. The proposed field optmization studies will also help develop alternate strategies for field development which will reduce the need for field infrastructure, thereby lessening the environmentalimpact.

6.48 Negative Impacts: The Project emphasizes rehabilitation of existing wells and well workovers. Since these wells already have well pads in place with access roads, there will not be any additional environmental burden from pad and access road construction. However, the new wells in existing fields will require some additionalwell pad and access road construction. The well pads and access roads are constructed from sand dredged from local rivers and lakes. This dredging is very disruptive to aquatic organisms, from single cell species to salmonid fish. Moreover, while the majority of associated gas in the project area is utilized7, as the Project will increase oil production in the participating Producer Associations by approximately 15%, this will result in an increase in flaring of associated natural gas of approximately0.38 billion cubic meters per annum (5% of regional emissions).

6.49 Mitigation and Implementation Plans: The completionof wells already drilled and workovers will have minor adverse impacts if the Producer Associations implement better methods for controlling drilling wastes and containing the initialflow of liquids from the worked over wells. The Project will provide equipment to handle well pad wastes which can also be used for cleaning oil spills from pipeline leaks. Careful selection of sand dredge areas for new well pads will minimize negative impacts. The Project also provides for strengthening the environmental mitigation and monitoring departments establishedunder Russian law in each of the three Producer Associations.

6 Indigenous people living in close proximity of oil production activities of the Project are: 5 families in Megionneftegas, 55 people in Tomskneft and 53 people in the Yugansineftegas areas.

7 Megionneftega%utilizes 87% of associatedgas, in Yuganskneftegas88% is utilized wbUiein Tomskneft 20% of associatedgas productionis currendyutilized. 44

These departments will be strengthened through provision of the environmental equipment and programs outlined above and through technical assistance for training, implementationof monitoring systems, assistance in planning programs to safeguard the interests of national minorities in or near Project areas, studies to address issues such as proper well abandonment and increased utilization of associatedgas and baseline data acquisition. A condition of Loan disbursement will be the release of bid documents and Letters of Invitation for the environmentalequipment and technical assistance components of the project. Grant funding is being sought to carry out environmental management training for the Associations in addition to the three participating in the First Oil Rehabilitaion Project. In addition, an EU funded program is under consideration for strengthening the planning and administrative capabilities of the regional environmental authorities and for establishing a regional action plan for improvingthe conditionsof nationalminorities. Annex 6-10 provides further details on the environmental and social effects of the Project and the mitigation measures proposed and background information on environmentalconditions in West Siberia.

VII. ECONOMIC JUSTIFICATION AND RISKS

A. Project Justification and Benefits

7.1 The proposed Project consists of three main production components: (i) workover and rehabilitation of idle oil wells; (ii) in-fill drilling of new wells in existing fields; and (iii) replacement of critical surface gathering facilities and field pipeline infrastructure which has been experiencing accelerating failure rates and subsequent oil spillage due to excessive corrosion. These components were selected on the basis of their potential to make early contributions to the stabilization of oil production in Western Siberia, increase sector revenues and thereby provide important support to macro-economic recovery. As shown in Table 7.1 economic returns are high, with economic rates of return gready exceeding 50% for each componentand an overall benefit-cost ratio of over 2.0 at a real discount rate of 15%. The high returns result from the low investment required to restore shut-in production and the export opportnity value of incremental oil production. At its peak the aggregate Project would provide 8.3 million tons per year (160,000 barrels per day) of incremental production, representing a 2.5% increase in expected national output. The Project is designed to have important demonstration effects which can be broadly replicated across Western Siberia.

Table 7.1: Summary of Project Economic Returns

MNG TN YNG Total Benefit-CostRatio Well Workovers 2.4 2.1 2.4 New Wellsin ExistingFields 2.6 2.6 2.3 Surface Pipe Replacement(km) 2.2 2.9 AggregateB/C Ratio 2.5 2.3 2.4 2.4 AggregateNPV ($ mdlions) 440 514 577 1,531 45

7.2 The primary benefit of the Project would be incremental oil production which has an economic value at the wellhead of US$89 per ton. This value is based on forecast Russian export prices of US$113 per ton (based on an international benchmark price of US$120 per ton) over the life of the Project less transport costs estimated to total US$24 per ton (including pipeline, tanker transport and port charges). No real oil price increases have been assumed for the base evaluations.

7.3 Project inputs are dominatedby importedmaterials, equipmentand services with foreign costs representing just over 80% of total economic costs. Shortages exist for all oilfield inputs within Russia and as such the economic cost of these inputs is represented by imports. The Producer Associations do not have significant supplies of materials which could be utilized in the proposed program. In addition, the recommendationto lower pumps will require heavier well tubing than is currently available in Russia and will also necessitate the use of international workover rigs with greater lifting capability than the standard 50 ton rigs available in Russia. Inadequate equipment and materials for well cementing, perforation, stimulationand horizontal drilling will necessitate the use of international service contractors, at least for initial wells. Local costs include rig labor, site and road rehabilitation, power supply, some well services and engineering and management. While it could be argued that the economic costs of some inputs, such as drilling labor and domestic pipeline transport, are negligible due to idle capacity in the country, these factors have not been incorporated into the economic evaluations, nor are they significant to the evaluations. The characteristics of individualproject components are discussed below and summarizedin Table 7.2. Further details of the economic analyses are provided in Annex 7-1.

Table 7.2: Summary of Project Component Costs and Benefits

MNG3 | TN YNG |JTotal Number of Operations l l Well Workovers 75 525 576, 1,176 New Wells in ExistingFields 76 11 40 127

Surface Pipe Replacement(km) 255 576 - 831 CapitalCosts ('000 $/Operation) Well Workovers 240 220 220 New Wells in ExistingFields 1,600 1,240 1,680 Surface Pipe Replacement 80 80 80

Incremental Production (tpdlwel) /1 Wen Workovers 16 11 15 New Wells in ExistingFields 84 75 63 Surface Pipe Replacement 2 4 3 Total Production(million tpa) 2.3 2.8 3.2 8.3 Benefit-CostRatio /2 2.5 2.3 2.4 2.4 Not"s 1/ Productionestimates include an allowancefor potentialabandonment of 10% of the wells. 2/ Benefit-Costratio based on $89 per ton value of oil at the wellead. 46

7.4 Workover, rehabilitation and completion of idle wells would generally involve installation of heavier tubing to lower down-holepumps, recompletionand well stimulation, which would restore shut-in production and could increase well productivity by an estimated 50%. Capital costs per well vary from US$150,000 to US$400,000depending on the need for well services (such as stimulation), the type of pump installed, and well depth. Operating costs are estimated to total US$18 per ton (US$2.5 per barrel)8 excluding social welfare payments which equal 40% of wages plus minor workovers costing US$72,000 every two years.

B. Economic Sensitivity Analyses and Project Risks

7.5 Project economic returns are robust relative to variations of ± 25 % in key project parameters including: capital costs, operating costs and production. Project components maintain strong economic returns at border prices as low as US$11.5 per barrel. This is due to the high base level of project returns. Nonetheless, a significant Project risk exists due to uncertainty about well productivity. Historic well production records are uncertain and the candidate wells which will be available at the time of implementationare partly unknown due to on-going workover programs in the Producer Associations9. This risk is acceptable given the large number of potential wells for rehabilitation (over 3000 in the three Associations) and can be managed through careful well screening and review during Project implementation. Production irom rehabilitatedwells could also be less than expected due to the state of the reservoir or due to unforeseen downhole problems that result in abandonmentof the well. Allowance for this possibilityis built into the evaluation of Project economics. The developmentwells which will be drilled as horizontal wells face the upside potential of much higher initial returns, but carry a technical risk of unsuccessful completion or high water break through rates. The risk of improper drilling of horizontal wells will be managed through contracting these services to specializedfuims and flexibilityin program implementation. Annex 7-1 shows the sensitivity of economic returns to a broad range of potential oil prices and other parameters over the project life.

VIII. FINANCIAL EVALUATION

A. Projected Profitability and Risks

8.1 Potential financial returns from the overall Project and individual components have been assessed on a stand-alone basis to determine whether it is in the Association's financial interest to undertake these investments. The atl•ity of the Associations to service the proposed loans on an aggregate and stand-alone basis have also been examined. A real after-tax cost of capital for the

8/ Based on a late 1993 conversion of R 1200/US$.

9/ From 1,500 wells rehabilitated across Russia during 1993 approximately 4 million tons of oil was produced during the first 9 months of the year. At this pace average productivity per well would be 10 to 20 tons per day depending on the dming of rehabilitation. These rates of production would provide acceptable economic and financial reurns for the proposed Project. 47 Producer Associations of 15% was assumedt0. While this return is lower than those required by international oil companiesfor new field developmentin Western Siberia, it reflects the lower risks associated with the proposed Project components. Project capital and operating costs are described in Chapter VII (Economic Analysis), with further details provided in Annex 7-1.

8.2 Under current (May 1994) and forecast tax and sales conditions, the overall financialrate of return for the project exceeds 40% and all components show acceptable fimancialreturns as shown in Table 8.1. The four key risks to Project viability are oil prices, both international and domestic, well productivity, tax levels, and access to export markets. The overall Project is still viable at international prices as low as US$98 per ton ($13.50 per barrel) throughout the project life although a few components would not be viable. The Project can sustain productivity declines of 25 % from expected levels and still exceed a 25% rate of return. At forecast oil prices of US$120 per ton ($16.50 per barrel), the overall Project could absorb an increase in taxes, although some components would become non-viable. However, a combination of low oil prices and an increase in tax levels would render the overall Project non-viable. While internationalprices are expected to fluctuate over the medium term around US$120 per ton, it is near term prices which are critical to rehabilitation projects such as this and there is a significant likelihood that oil prices remain soft for the next few years. Thus the Project could not tolerate an increase in tax levels until such time as profitability is assured due to improvementsin conditions, such as higher oil prices.

Table 8.1: Sunmary of Project Financial Returns

.NG TN YNG Total FinancialRate of Return (%) Well Workovers 62% 40% 70% New Wells in ExistingFields 45% 60% 30% Surface Pipe Replacement (km) 20% 48% AggregateFIRR 43% 44% 53% 47% AggregateNPV ($ millions) $89 $91 $112 $292

8.3 A major financial problem faced by all Associations is payment arrears. Producers were collectively owed 6.4 trillion roubles or US$3.5 billion by end Febmary 1994 which is equivalent to approximately 30% of domestic sales revenues. This problem arises from a number of factors including: setdement delays in the banking system which results in 2 to 6 month delays for payments; a disincentive to pay under conditions of high inflation; financial difficulties of customers; and, until recently, limited scope for suppliers to cutoff customers in arrear. These problems occur within integrated oil companies as well as independents.The proposed Project is not immediatelyvulnerable to this problem since it qualifies for export quotas. However, the overall fnancial performance of

IO/ Based on an assumed capital structure of 30% debt and 70% equity which is typical for upstream operations in international oil companies. While financingof the proposed Project would be over 70% debt, overall leverage for the PA's should not significantly exceed 30% in the fuAtre. 48 each of the Associations is currently severely constrained by these problems. Producers are now authorized to cut-off supplies to delinquentcustomers, and, while this should sharply reduce arrears, producers could face cash flow problems stemming from payment difficulties for the near term. In other sectors of the econtomythe arrears problem largely disappeared once stringent payment conditions were imposed. The Ministry of Fuel and Power has commissioned an international accounting firm to examine the causes and potential solutions to the problem.

B. Financial Covenants

8.4 The key financial performance goals for the Producer Associations relate to cash flow. In a period of rapid price changes cash flow managementwill be critical. The Producer Associations must be concerned with liquidity and their ability to not only meet debt service obligations but also to provide funds for on-going investments. Typically, a significant portion of investments in the upstream oil sector are funded from internal cash generation or equity. This will be particularly pronounced in Russia until the capital markets improve. The main financial performance covenant proposed for the Second Oil RehabilitationLoan is that the Producer Associations maintain a debt service ratio of at least 1.5 (ratio of earnings before interest and depreciationless royalties, revenue and profit taxes to total short and long term debt service obligations). A second covenant, related to working capital, will require maintenance of a current ratio of no less than 1.25, including restrictions to dividend payments and maintenanceof average accounts receivableat 60 days of sales and accounts payable at not greater than 75 days of cash expenses by fiscal year 1995.

8.5 Since the Producer Associationswill operate in a market oriented industry, revenue or return based financial performance covenants are not warranted. Sector policy reforms covering prices and taxation, however, are critical in this respect.

3L. AGREEMENTS REACHED AND RECOM[MENDATIONS

9.1 The Government and the Producer Associations have made considerable progress on the preparation of the Project for implementationand on sector reforms.

9.2 During Negotiations, the Producer Associationsagreed to the following future actions with respect to Project implementation:(i) maintenance of a 1.5 debt service ratio; (ii) maintenance of acceptable levels of working capital; (iii) provision of montnly reports on procurement and Project progress during the first year of implementationand quarterly thereafter; and (iv) annual submission of audited Project accounts and financial statements.

9.3 Project actions which need to be taken prior to loan Effectivenessare submittal of subsidiary loan agreements and legal opinions ratifying loan documentation.

9.4 There are two conditions of Disbursement for each Producer Association's part of the Project; (i) release of Letters of Invitation and bid documents for the environmental management portion of the Project; and (ii) appointmentof financial auditors. 49 9.5 The Government submitted a Letter of Policy Intent to the Bank, June 8, 1994, in which it records recent progress in a number of key policy areas, including the liberalizationof oil exports, the safeguarding of tax incentives and the developmentof legal and tax reform in the oil sector. The letter also expresses the Government's intention to continue the practice of regular policy consultations with the Bank, to introduce further reforms in critical areas such as oil transport regulation and to complete ongoing legal reforms. The Government's letter is included in Annex 9-1.

9.6 Based on the above agreements, the above Project is suitable for an IBRI) Loan of US$500 million equivalent to the Russian Federation, for 17 years including a 5-year grace period, at the Bank's standard variable rate for Currency Pool Loans.

EC3IV June 1994 50

Amex 2-1 RUSSIA PRIMARY ENERGY SUPPLY (Thousand TOE)

19285 1298 12_ 198 1989 199L 191 1992 1993 OIL CrudeOil Production 547,730 566,795 575.176 574,466 557,748 516,200 461,100 395,800 354,000 Crude OilImports 28,210 30,977 30,929 37,568 30,906 18,800 18,1OC 16,200 8,000 CrudeOil Exports (245,697)(263,989) (272,984) (279.110) x260,153) (211,000) (180,000) (142,000) (127,500 OilProduct Imports 0 0 0 3.291 1,379 5,820 5,875 4,600 6,000 Oil ProductExports (55,340) (55,787) (56,320) (59,878) (50,438) (78,000) (74,000) (49,000) (36,500 ApparentConsumption /1 274,903 277,996 276.801 276,337 279,442 251,820 231,075 225,600 204,000

NATURAL.GAS Production 373,769 406,904 440,361 477,124 498,169 518,218 520,098 505,576 488,529 Imports 54,917 55,983 58,397 59,101 59,182 56,764 55,630 55,630 55,630 Exports (134,684)(146,025) (163,567) (182,554) (198,410) (202,061) (198,823) (187,720) (171,766 ApparentConsumption 294,002 316,862 335.191 353.671 358,941 372,921 376,905 373,486 372,393

HARDCOAL Production 108,035 111,512 113,420 115,964 113,759 109,138 94,467 90,242 80,857 Inports 26,609 26,161 25,694 25.208 23,702 22,175 19,801 19,801 19,801 Exports (21,514) (21,963)(22,387) (22,804) (22,430) (22,090) (16,282) (16,119) (14,654 ApparentConsumption 113,130 115,710 116,727 118,368 115,031 109,223 97,986 93,924 86,004

RROWJNCOAL Production 59,530 61,438 62,413 64,448 59,996 58,194 55,332 52,857 47,360 Inports 0 0 0 0 0 0 0 0 0 Exports 0 0 0 0 0 0 0 0 0 ApparentConsumption 59,530 61,438 62,413 64,448 59,996 58,194 55,332 52,857 47,360

Nuclear 25,878 27,416 31,377 32,862 33,384 30,830 29,289 28,703 27,531 Hydro/Geothermal 13,743 14,130 13,975 13,837 13,734 13,803 13,803 13,803 12,975 Inports 2,778 2,786 2,485 2,795 2,907 2,924 2,984 2,984 2,805 Exports (2,571) (2,881) (3,173) (3,130) (3,371) (3,388) (3,354) (2,683) (2,683 ApparentConsumption 39,828 41,451 44,664 46,364 46,654 44,169 42,722 42,807 40,628

TOTAL PRIMARY C SPTION 781,393 813,457 835,796 859,188 860,064 836,327 804,020 788,674 750,386 PercentChange 4% 3X% 3% 0% -3% -4% -2% -5%

SHAREOF TOTAL XUPPLY Oil 35% 34% 33% 32% 32% 30% 29% 29% 27% NaturalGas 38% 39% 40% 41% 42% 45% 47% 47% 50% Coal 22% 22% 21% 21% 20% 20% 19% 19% 18% Other 5% 5% 5% 5% 5% 5% 5% 5% 5% 1/ includinglosses and own use. Source: Goskomstatand Planecon ORGANIZATION OF RUSSIAN UPSTREAM OIL SECTOR (DECREE 1403, NOVEMBER 17. 1992)

RUSSIAN G tVERNMENT MINISTRY OF FUEL & POWER

1-'''I- I I II 100% 100% 100% 45% 45% 45%

TRANSNEFT TRANSNEFTEPRODUCT | U SRT

I l_1 _1 1~~~ 1 'I_I 38% 51% 51% 38% 38% 38%

PRODUCING & §YUGANSKNEFTEGAS k REFINING ASSOCIATIONS MEGION CRUDE TRANSPORT ASSOCIATIONS

REFINING ASSOCIATIONS_ TOMSKNEFT

PRODUCING & REFINING ASSOCIATIONS PRODUCT TRANSPORT & DISTRIBUTION OTHER OIL ASSOCIATIONS ASSOCIATIONS

x Note: -Figures den~ote shareholding 1- 0 I ORGAIZATIONCIUW OFTHE FUEL AND ENERGY COMPLEX

MINISTEiROF FUEL AND ENERGY

FIRSTDEPUTY MIMSISE FIRSTDEPUTY MINISTE FIRSTDEPI.TY M SIISE

(,s, SeCtor) (Oil Sector) j (Fu_.I)

DEPUTYMINISTER DEPUTYMINISTER DEPUTYMINISTER DEPUTYMINISTER DEPUTYMINISTER DEPUTY1iJU'STER DEPUTYMINISTER

Fetoln Ecwc Rulinsl) (Etaon J F6*nce for t ectuicky) tUce"eF ad Q*40te (Econko a Finene ,Elcrkky sadCool) toe oa & Got)

ADMINISTRATIONS Coal Industry & DEPARTMENTS Onl Industry NINDEPE-NDENTuSTATE ORGANIZATIONS Oil ProductSupply Electric Powe Ugo'Rostil MecianicalCosisructlon for the Fuel ______Rosneftegax andEnergy ComjiAexand Conversion Rasenerto Energy Resource Prqkervatimonandefeatto Rosenergostrol Noa.Conventional Energy Soureces GxaiptO Investment Polkcyand Capital Construction Rosnefteprodukt I 1 Problems of the North Association "Rlostopproin" Day-to-DayRegulation ~~~~~~~~~~~~~~~Associationof BusinessCoopertion for the Ptovhioinand OTHER ORGANIZATIONS Replenilshmentof Enegy Equipnwcnt"ENKOMt" I)ay-to-Day Rcgulation AFFILIATE~~DWIT'H foreign Economc Association'ASFN' AFFILIATE ~~~~~~~Scientific-TechnicalAssociation"Energpprogress' ______TIlE MINISTRY Commetclil-indusitrIa Associadion for Energ Industrialsts B"nchrAsoriaio for Materfal-TeckudcaiSupply 'Energorynol'

______Firm 'Energoproekt' Russian Fuel and Energy Excl-inge Oil Exchange 53 Annex 3-2 Page 1 of 3 RUSSIAN FEDERATION

OIL SECTOR REFORM

PROGRESSSNCE 06I930 REFORM REFORMOBECTIVES ANDFUTURE ACTIONS

A. Price 0 Substantialprogress toward 0 Price levels have increased from 1/3 to internationalparity. near 60% world levels.

o Export liberalizationwill put further upward pressure on domesticprices.

O DomesticMarket o Dismantlementof domestic allocations Liberalization. now substantiallycompleted. Producers may refuse sales on groundsof non-payment.

O Profit ceiling limits on price formation abandonedSeptember 1993.

B. Trade 0 Increase oil export quotas 0 Crude oil exports to non-FSUincreased Liberalization rapidly and ultimately 20% over the course of 1993 from 66 abolish them. million tons to 80 million tons.

o 1994export targets to non-FSU increasedto 90 million tons.

o Quotas abolishedeffective July 1 by Decree#1007, May 23, 1994

0 Decreaseand ultimately 0 1994centralized exports target to non- abolish centralizedoil FSU reduced to no more than 25 exports. million tons by Decree, March 1994.

a Centralizedexport agreementswill not be reviewed and shouldphase out by end 1994.

* Date of Board Approvalof First Oil RehabilitationLoan. .S4 Annex 3-2 Page 2 of 3

RUSSIAN FEDERATION

OIL SECTOR REFORM

PROGRESSSINCE 06/93* REFORM REFORMOBJECTIVES ANDFUTURE ACTIONS

C. Crude Oil 0 Establishacceptable 0 Key principlesof non-discriminatory Transport regulatoryframnework. economictariffs and adequaterules for access contained in draft legislation now before Parliamnent.

0 Governmenthas confirmedintent to put new regulatoryframework in place by year-end 1994.

D. Taxation 0 Reduce statutory tax levels to 6 Price RegulationFund (tax on price provide adequateincentives. increases) abandonedSeptember 1993, largely offset, however, by increased rates of excise tax.

o Rates of Governmenttake expressed as a % of profit or operatingmargin vary from 80% to 90% for flowing production and 65% to 75% for new production.

0 Governmenthas confirmedintent to maintainor deepen existing tax incentives.

o Imple-aentpromised tax e PresidentialDecree 497, May 19, 1994 incentives. restoredexport tax privilegesand provides acceptableprocedures for their implementation.

o Significantshift from 0 Existingrevenue taxes (excise taxes revenue to profit-based and royalties) are set to show taxation. sensitivityto profitability. Studies to facilitate further moves to profit- based taxationare planned.

0 Decree 2285, issued December24, 1993, provides for fully acceptable profit-basedtaxation for new ProductionSharing Contracts.

* Date of Board Approvalof First Oil RehabilitationLoan. 55 Annex3-2 Page 3 of 3 RUSSLANFEDERATION

OIL SECTOR REFORM

PROGRESSSNCE 06I93* REFORM REFORtMomQO VS ANDFUTURE ACTIONS * Reasonableassurances on tax ° Decree 2285 of December 1993 stabilization. stabilizes fiscal terms for all new ProductionSharing Agreements.

o Simplifytax administration a GovernmentResolution 320, April to increasecompliance. 14, 1994 converts percentagead valoremexcise tax to an equivalent ruble per ton tax.

E. Petroleum 0 Early completionof 0 Processingof legislativedrafts Legislation acceptable and seriouslydisrupted by political comprehensivelegal and events of September/October1993 contractual frameworkfor and new Parliamentaryelections, oil operations. December1993.

a Draft Law on Oil and Gas submittedto Parliament, April 1994. Additional relevant legislation will be submitted in the coming months. Drafts are well advanced.

0 PresidentialDecree 2285 issued December 1993 outlining attractive frameworkfor oil operations conductedunder ProductionSharing Contracts. Enablinglegislation/ regulationsnow being prepared.

a Comprehensivelegal framework targeted for end-1994or early 1995.

* Date of Board Approvalof First Oil RehabilitationLoan. 56

Annex 5-1 Page 1 of 4

RUSSIA SECOND OIL REIABILUTATTONPROJECT

LEGAL CHARACTERISTICS OF THE PARTICIPATING JOINT STOCK COMPANIES (PRODUCER ASSOCIATIONS)

I. MEGIONNEFTEGAS

A. Charter and Legal Structure

1. Open joint-stock company "Megionneftegas" is a legal entity and was established in accordance with Presidential Decrees N1403 and N721 of 11/17/92 and 7/1/92 respectively. The Committee on State Property Managementof the Tyumen Oblast was its founder. MNG's Charter was adopted by the conference of the labor collective and registered with the Megion City Soviet on April 1, 1993 and approved by the President of Rosneft, the Committee for State Property Managementof Tyumen Oblast and notarized by the State Notary of Tyumen Oblast. The Company is a successor to the State Production Association "Megionneftegas"and may perform any business activity other than those prohibited by law. The Charters of MNG's subunits were approved by MNG's Director General at that time of registration.

2. The annual Meeting of Shareholders is the supreme governing body and 50% of ordinary shareholders constitute a quorum. Emergency meetings can be convened by the Director General. The Company can be liquidated by decision of the Shareholders Meeting or by court decision.

3. The Board of Directors consists of the Director General, a representative of the workers collective, a representativeof the local Soviet of Peoples Deputiesand, while 40% of ordinary shares are federal property, representatives of the Committee for State Property Management, the Ministry of Fuel and Power, and the State Committee for Anti-Monopoly Policies and Promotion of New Economic Structures, which vote at Shareholders Meetings in accordance with the federal property block of shares. The Board adopts decisions on all issues relating to Company activities other than those which are within exclusivejurisdiction of the Shareholders meeting.

4. The Director General is an ex-officio Chairman of the Board of Directors. When the Company was established the Director General was appointed by the Government of the Russian Federation or a body authorized by it. The Director General conducts operative management of the Company.

5. The ManagementBoard is an executive body of the Company, whose activities are governed by a Statute approved by the Board of Directors. The Company is obligated to meet its commitments in respect of resource mobilization in accordance with the law and approved mobilization plans, which are considered as a State order pursuant to Presidential Decree N288 of 3/21/92. The Company management is liable in accordance with the law for non-fulfillmentof obligations and tasks. 57

Annex 5-1 Page 2 of 4 6. Lending agreements can be concluded only by MNG and have to be signed by the Director General and Financial Director. MNG bears ultimate financial responsibility for all operations conducted by its subunits although each subunit has its own balance sheet and current bank account. The Audit commission manages and presents the annual financial audit report to the Board of Directors.

7. Since MNG's subunits are not independent legal entities, they are basically limited to concludingservice contracts with each other, with transfer prices regulated by the Association. Any transactions with other entities must be authorized by the Producer Association.

8. MNG has joint ventures with two foreign oil companies for well rehabilitation and possible new field development.

B. Licenses

9. Megionneftegashas been granted licenses, valid until December 2013, for the right to use the subsoil in respect of oil and gas extraction in the oilfields comprising the Project, in different rayons of the Khanty-Mansiysk AutonomousOkrug of the Tyumenskaya Oblast.

H. TOMSKNEFT

A. Charter and Legal Structure

10. Open joint-stock company "Tomskneft" (TN) is a legal entity and was established in accordance with Presidential Decrees N1403 and N721 of 11/17/92 and 7/1/92 respectively. The Committeeon State Property Managementof Tomskaya Oblast was its founder. The TN Charter was discussed in the conference of the Labor Collective and was approved by the Minister of Fuel and Power on July 12, 1993. The Charters of subunits were approved by TN's Director General at that time. The Charter has been registered by the AdministrationHead of the City of Strejevoi (location of the Company), approved by the Committeefor State Property Management of Tomskaya Oblast and notarized by the State Notary of Tomskaya Oblast. The Company is a successor to the State Production Association "Tomskneft" and may perform any business activity other than those prohibited by law.

11. The annual Meeting of Shareholders is the supreme governing body and 50% of ordinary shareholders constitute a quorum. Emergency meetings can be convened by the Director General. The Company can be liquidated by decision of the Shareholders Meeting or by court decision.

12. The Board of Directors consists of the Director General, a representative of the workers collective, trustee representatives and a representativeof the local Soviet of Peoples Deputies. The Board adopts decisions on all issues relating to Company activities other thanthose which are within exclusivejurisdiction of the Shareholdersmeeting.

13. The Director Generalis an ex-officioChairman of the Board of Directors. When the 58

Annex 5-1 Page 3 of 4

Company was established the Director General was appointed by the Government of the Russian Federation or a body authorized by it. The Director General conducts operative managementof the Company.

14. The Management Board is an executive body of the Company, whose activities are governed by a Statute approved by the Board of Directors and consists of directors of the largest production units, mainly NGDUs. This body fulfills operational functions such as coordinating day-to-day activities of all NGDUs, and works in close cooperation with the Director General. The Council of Managers includes all directors and managers of subunits, the Chief Geologist, Chief Engineer and other leading specialistsof TN. The Council of Managers holds its sessions primarily for discussing long-term business prospects. The Company is obligated to meet its commitments in respect of resource mobilization in accordance with the law and approved mobilization plans, which are considered as a State order pursuant to Presidential Decree N288 of 3/21/92. The Company management is liable in accordance with the law for non-fulfillmentof obligations and tasks.

15. The Audit commission manages and presents the annual fmancial audit report to the Board of Directors.

16. At present, TN is involved in (or is considering) five projects with foreign companies:

(a) a work-over contract with Oman Oil and Benton Oil; and

(b) three joint ventures with Fracmaster.

B. Licenses

17. Tomskneft has been granted licenses, valid until December 2013, for the right to use the subsoil in respect of oil and gas extraction in the oilfieldscomprising the Project, in different rayons of Tomskaya Oblast and Khanty-MansiyskAutonomous Okrug of the Tyumenskaya Oblast.

Im. YUGANSKNEFTEGAS

A. Charter and Legal Structure

18. The Charter of Yuganskneftegas is basically identical to those of "Megionneftegas" and "Tomskneft", descnbed above, with the following differences:

(a) the joint-stock oil company "YUKOS" was the founder of the Company;

(b) the Company is a successor to "Yuganskneftegas"Production Association;

(c) during the period when "YUKOS" owns 38% of shares, the annual Shareholder Meeting is not valid unless a YUKOS representative is present; and 59

Annex 5-1 Page 4 of 4

(d) the Board of Directors consists of the Director General, a "YUKOS" representative, a representative of the workers collective and, while 38% of ordinary shares are federal property, representatives of the Committee for State Property Management, the Ministry of Fuel and Power, and the State Committeefor Anti-MonopolyPolicies and Promotion of New Economic Structures.

19. The Charter of Yuganskneftegashas been approved by the "YUKOS" Board of Directors, the Committee for State Property Management of the Khanty-Mansiysk AutonomousOkrug and is registered with the Administration of Nefteyugansk rayon and notarized.

20. YNG has two joint ventures with Fracmaster to carry out rehabilitation operations and has been granted the right to negotiate with Amocoand Shell for developmentof two large new oilfields.

B. Licenses

21. Yuganskneftegashas been granted licenses, valid until December 2013, for the right to use the subsoil in respect of oil and gas extraction in the oilfields comprising the Project, in different rayons of the Khanty-Mansiysk AutonomousOkrug of the TyumenskayaOblast. 60

Amiex 5-2 Page 1 of 9

RUSSIA SECOND OIL REHABILITATION PROJECT

ORGANIZATIONAL STRUCTURES OF THE JOINT STOCK COMPA (PRODUCER ASSOCIATIONS)

I. MEGIONNEFTEGAS

A. Organizational and Management Structure

1. The General Director

2. Director of Drilling

(a) Drilling Administration (b) Derrick Construction and Drilling Rig Administration (c) Drilling Cementation Department (d) Specialized ConstructionAdministration

3. Director of Technical Supplv

(a) Deputy Director of Technical Supply (b) Division of General Supply and Central Warehouse (c) Transport Division and Car Service Shop (d) Airport (e) Technical Land Transport #1 (f) Technical Land Transport #2 (g) Road Construction and Repair Administration (h) Mechanized Works Administration (i) Transportation Venture for Drilling Teams

4. Director of Commerce

(a) Division of Security (b) Commerce Enterprise

5. Director of Maior Constucion

(a) Production and Technical Projects Planning Division (b) Oil Construction Department (c) Completion Equipment Department (d) Construction DevelopmentGroup (e) Major Building Repairs and Construction Shop 61

Amn 52 Page 2 of 9

(f) Bureau of Construction Department (g) Bureau of Project Finance (h) Construction Venture in KrasnadarskykrayAdministration (i) Electrical Equipment Constructionand Installation Administration

6. Director of Agriculture Industrial Complex

(a) Agriculture Department (b) Agriculture and Farm Enterprise (c) Association in Golyshmanovo

7. Director of Personnel and Social Development(Pensions and Housing)

(a) Sports Complex Director (b) Social Development Department (c) Personnel Department (d) Chief of Public Relations and Press Center (e) General Operations Maintenance and Repairs (f) Drink Shop (g) Production and Sale Enterprise (h) Megion City Service and Repair (i) Medical Center O) Orientation and Training Center (k) Self Financing Contract Center

8. Chief of Public Relations and Press Center

9. Leeal Department

10. External Relations DeDartment

11. Enterprise "Oil Service'

12. Technical Director. 1st Deputy Director

(a) Central Engineering Technology Service (b) Administration of Exploration of Oil and Gas (i) Oil and Gas Extraction Shop #1,2,3,4,5,6,7 (ii) Well RefurbishmentShop (minor repair) (iii) Well Work-Over Shop (iv) Enhanced Recovery and Well Work-Over (v) Preparation of Oil Well Refurbishment (vi) Logistics Support Unit for Electrical Submersible Pumps (c) Sales Department for Oil Products 62

Annex ,5-2 Page 3 of 9

(d) Department of Chief Mechanic (i) Pipeline Equipment and Accident Remediation (ii) Maintenance Service Facility (e) Chief Energy Specialist (i) Power Supply Center (f) Department of Automation and Production (i) Remote Control and Production Automation Shop (ii) TelecommunicationShop (g) Department of Environment (h) Computer Center (i) Department of Safety and Accident Prevention (j) Oil Processing/Treatmentand Gas Production (i) Processing/Treatmentand Pumping Facility #1 (ii) Processing/Treatmentand Pumping Facility #2 (iii) Gas Shop

13. Controller

(a) Accounting Department

14. Financial Director

(a) Economic Planning Department (b) Labor and Salary Department (c) Finance Department

15. Director of Geology

(a) Investments and Control of Property Department (b) Field Geologists (c) Geology Specialist (d) Geology Department (e) Oil Field Development Department (f) Hydrodynanucs and Reservoir Development Laboratory

16. Assistant to the General Director on Administrative Issues

(a) Copy Room (b) Administrative Front Office

17. Assistant to the General Director on Economy 63

Amewx5-2 Page 4 of 9

II. TOMSKNEFr

A. Organizational Structure of Tonskneft

1. General Operating Units

(a) Department of production, technical supply and equipment delivery; (b) Department of gas recovery and utilization; (c) Department of technologicaltransport for drilling operations; (d) SpecializedDepartment #1: Construction material preparation; (e) SpecializedDepartment #2: Geological and geophysical data preparation; (f) Construction and assembling enterprise of "Tomskneftestroy"; (g) Oil industry research and design Institute "TomskNIPIneft"; (h) Kedrovsk Department of Technological Transport; and (i) Moscow representative office

2. Central Support Units

(a) Road Construction Department; (b) Capital construction department; (c) Engineering construction department; (d) Trust "Strezhevoyspetsneftstroy"(specialized construction of oil facilities); (e) Rig assembling department; (t) Plugging department; (g). Central base for renting and maintenanceof drilling equipment; (h) Department of technological transport, specializedmachinery and highways; (i) River ship company; (j) Clusters' information and computer center; (k) "Aviatransneft"Enterprise; (I) Information and publishing center; and (m) Trade and production supply center

3. Social Units

(a) Training center; (b) State farm "Strezhevoyspetsneftstroy"; (c) Tourist base "Neftyanik" (the "Oilman"); and (d) Hotel complex "Kedr" ("Cedar")

4. Field Production Units

Strezhevoyneft (a) Oil and Gas Production Department "Strezhevoyneft"; 64

Annex 5-2 Page 5 of 9

(b) Strezhevskoy Departnent of enhanced oil recovery and well work-over; (c) Strezhevskoy Drilling Department; (d) Strezhevskoy Department of TechnologicalTransport #1; (e) Strezhevskoy Department of TechnologicalTransport #2; (f) Strezhevoy assembling and setting-up department; and (g) Strezhevoy specialized construction departnent

Vakhmeft (a) Oil and Gas Production Department; and (b) Department of Technological Transport

Vasuganneft (a) Oil and Gas Production Department; (b) Drilling Department; and (c) Department of TechnologicalTransport

flgolneft (a) Oil and Gas Production Department

Luginetskenft (a) Oil and Gas Production Department

B. Magnaement Structure of Tomskneft

1. TTheDirector General

2. Production Management Block - headed by the Chief Engineer

(a) Engineering/Producton Department (headed by the First Deputy GM-Production) (i) Oil and Gas Production Departments (NGDU); (ii) Enhanced Recovery and Wells' Work-Over Department; (iii) Information and Computer Center; (iv) Assembling and Setting-up Department; (v) Central Base for Production Services; (vi) Tomsk Research and Design Institute; and (vii) CommunicationDepartment

(b) Geology Department

3. Commercial and Financial Block - headed by the First DeMutv GM - Commercial

(a) Commercial Department - headed by the Deputy General Manager of Economics (i) Procurement Department; and 65

Annex 5-2- Page 6 of 9

(ii) Finance and economic activitiesof all independent structural Departnents

(b) Accounting Department - headed by the Chief Accountant

4. Personnel and Social Development Block - headed bv Deguty GM - Social

(a) Pre-school Children InstitutionsDepartment; (b) Hotel Complex Department; (c) Cultural Center "Neftyanik" ("The Oilman"); (d) Training Centre; (e) Tourist Base "Neftyanik"; (f) Construction and Renovation Department; (g) Trade and Production Supply Association for Workers; (h) State Collective Farm "Strezhevoskoy"; (i) Subsidiary Farm "Voskhod"; and (j) IstrimnskDepartnent of Engineering Constructions

5. General Matters Block - headed by Deputy GM - Support

(a) Road Construction Enterprise; (b) TechnologicalTransport Departments; (c) "Aviatransneft"Department; (d) Maintenance and Operations for River Fleet; and (e) Production and Technical Supply and Delivery Departnent

6. Productionand Exploration Drilling Block - headed by Deputv GM - Drilin,

(a) "Tomskburneft" Department; (b) Technological Transport for Drilling Equipment Departnent; (c) Rig Assembling Department, and (d) Plugginj Department

7. CaRital Construction Management Block - headed by DeMut=GM - Construction

(a) "Tomskneftestroy"Department 66

Amsex 5-2 Page 7 of 9

III. YUGANSKNEFTEGAS

A. Organizational Structure of Yuganskneftegas

1. General Operating Units

(a) Oil and Gas ProductionDepartment; (b) Surface Administration for Newly developed oil and gas fields; (c) Department of drilling No. 1; (d) Departnent of drilling No. 2; (e) Department of exploratory drilling; (f) Central production service base for drilling equipment; (g) Department No. 1 of enhanced reservoir recovery; (h) Department No. 2 of enhanced reservoir recovery; (i) Department of wells' production itensification "Inrasf'; (j) Rigging up Department; (k) Plugging Department; (1) Department of technological transport No. 1; (m) Department of technological transport No. 2; (n) Department of technological transport No. 3; (o) Department of technologicaltransport No. 4; (p) Central Base for renting and reconditioningof the oil field equipment; (q) Central Base for renting specializedmachinery and rig equipment; (r) Central Base for on setting up and maintenance of power generating equipment; (s) Central Base for production services of automation units; (t) Department of electrical circuits and electrical equipment operation; (u) Chemical engineering operations "Yuganskneftepromchim";AND (v) Electrical motors repair plant;

2. Central Support Units

(a) "Yuganskneftepromchim"Special Construction; (b) "Yuganskneftepromchim"Road construction; (c) "Yuganskneftepromchim"Renovation and construction; (d) "Yuganskneftepromchim"Construction; (e) Geophysical Department; (f) Engineering Center "Western Siberia"; (g) Department of production and technical supply; (h) Construction and Mounting Departnent No. 2; (i) Department of technological transport No. 5; (j) Department "Yugansktorf" (Peat); (k) Ostrovanaya (Island) Base for technical services and equipment supply; (1) Nefteyugansk Central base for oilfield equipment and construction work-over; 67

A_nex5-2 Page 8 of 9

(m) Construction Management Department (pipe anticorrosion plant construction); (n) Departnent of heat and water supply; (o) Specialized enterprise for drilling and explosion operations; (p) Automatic control systems maintenance Departnent "YuganskASUneft"; (q) Avia-transportationDepartnent; (r) Normative research station;

3. Social Units

(a) Nefteyugansk Trading center; (b) Trading Company "Temp"; (c) Department of social and communal supply; (d) State farm "Neftevugansky"; (e) State farm "Singapaisky"; (f) State farm 'Cheuskinskoye"; (g) Poultry Farm; (h) Nefteyugansk green house enterprise; (i) Brewery; (j) Joint squadron of militarized guards; (k) Sports and recreation center 'Ob"; (1) Health center "Yugan"; (m) Small production and research enterprise "Electrum"; (n) Cultural center 'Yugan"; (o) Daily public and political news-paper "Za Yuganskuyuneft"(For Yugansk Oil); (p) Information and commercial TV center 'Intelcom"; (q) Center of non-traditionalmedicine, adaptation and preventive medicine; (r) Industrial technical school; (s) Training center; and (t) Complex design Department

4. Field Production Units

Mamontova (a) Oil and gas production Department "Mamontovaneft"; (b) Oil and gas production Department 'Maiskneft"; (c) Mamontov central base for renting and maintenance of oil field equipment; (d) Mamontov Deparment of enhanced reservoir recovery and wells' workover No. 1; (e) Mamontov Department of enhanced reservoir recovery and weLlsworkover No. 2; (f) Mamontov Department of electrical circuits and electrical equipment operation; (g) Mamontov Department of technologicaltransport No. 1; (h) Mamontov Department of technologicaltransport No. 2; (i) Mamontov Department of technologicaltransport No. 3; U) Maiskoye Department of technologicaltramsport; (k) Mamontov Department of drilling operations; 68

Annex 5-2 Page 9 of 9

(1) Mamontov Plugging Department; (m) Mamontov base of production and technical services and equipment supply; (n) Mamontov Central piping base; (o) Mamontov central base production services for rigging-up operations; (p) Mamontov department of water supply; (q) Construction department No. 4; (r) Mamontov departnent of social and communal supply, (s) Trading company "Neftyanik"(Oilman);and (t) Farmers' cooperative "Siberia"

Poikovskoye (a) Oil and gas production department "Pravdinskneftn; (b) Salym Department of drilling operations; (c) Salym Rigging-up Department; (d) Salym Department of electrical circuits and electrical equipment operation; (e) Poikovskoye Department of technologicaltransport No. 1; (f) Poikovskoye Department of technological transport No. 2; (g) Trading company 'Pravdinka"; (h) Poikovskoyedepartment of social and communal supply; (i) Ural Regional representative office; (j) Agricultural firm "Turinskayan; (k) Implementationresearch and engineering center "Neftegaztechnologia"; (1) Boarding house "Guta"; (m) Constructiondepartment No. 3 "Yugan"; (n) Management of facilities under construction in Anapa; (o) Constructiondepartment No. 1 'Anapskoye"; (p) Family sanatorium "Lastochka" (Swallow); (q) Representativeoffice in Kurgan; (r) Representativeoffice in Omsk; (s) State farm "Roshinsky"; (t) Constructiondepartnent No. 3 "Ymapskoye; 69

An=5-3 Page 1 of 6 FINANCLALSTATUS OF PRODUCE ASSOCIATIONS Balance Sheet MEGIONNEFrEGAS tlMiDionRubies) IMillion RColede - 1991 992 1993 C1de _991 9 93 -Coe _____C de19 1- i I . Fixed Assets 1. Capital 12 Non-MaterialNFA 1 400 Charter Capital 1,504 6,610 6,610 20 Fixed AssetsGFA 2,191 65,453 117,967 410 Resources 21 Accuml Depreciation 843 26,708 31,310 420 SpecialFunds 211 97,651 255,766 22 Fixed Asses NFA 1,348 38,745 86,658 430 EarmarkedFinacial 502 502 30 EquipmentCWIP 18 1,506 2,777 440 Other 40 hIvesunentCWIP 165 5,451 34,128 450 Other 50 LongTerm lnvestment 29 7,474 25,838 460 Other 60 Settlementof Founders 470 Profit in Current Year 17,617 70 Other Non-CurrentAsset 471 Profit Distributed 17,617 80 Total Fixed AssetsI 1,560 53,176 149,401 472 Profit Not Distributed Q Q 480 Total Capital 1,716 104,763 262,879 II. Current Assets 100 Suppliers/Stocks 55 2,324 10,926 H. Current Liablties 110 Catte 4 34 223 520 Total LT Loans 9 605 1,486 120 Low ValueAssets 11 221 1,126 600 Short Term Bank Loas 42 4,363 7,978 130 UncompletedConstr. 1 3,801 15,368 610 Bank Loansto Persons 0 0 140 Advances 0 15 292 620 Short Term Loans 150 Production 3 583 1,615 630 Trade Payables 97 9,181 72,548 162 Materals 126 5,324 33,402 640 OutstandingBills 170 Trade Costs Coods 0 468 1,851 650 WagesPayable 37 685 3,550 175 Other 1,308 4,372 660 Social Insur Welf1re 29 552 4,946 176 Other 670 Prop. & PersonalInsur. 8 54 180 Total CurrentAssets 1I 202 14,078 69,175 680 Other 0 690 Non-Budgetary 15 9,903 38,879 I m.Settlements 700 Budget 20 12,476 57,303 200 Receivables 154 28,477 157,017 710 Otber Creditors 54 3,812 9,925 210 Bils Receiveable 0 720 Advancesfrom Cust. 0 220 With Affiliates 0 730 AdvancePaymets 18,062 32,610 230 to Budget/State 49 32 172 740 AdvancePayments 23 510 1,694 240 to Personnel 0 2 1,937 750 Bad DebtAllowance 250 Other Debtors 12 40,397 27,014 760 Other Short Term 19Q 217 260 Advancesto Suppliers 3 344 12 770 Total 466 60,374 230,974 270 Short Term Investment 1,940 3,682 280 Casb 0 97 2,189 780 BALANCE LLAB. 2,182 165,137 493,852 290 Current Account 44 1,048 307 l errors 0.00% -0.00% 0.00% 300 Foreig Exchange 2 22,494 63,160 310 Other LiquidAssets 114 3,053 12,869 Ratdo 1991 12 1993 320 Other Current Assets 42 Q0 a | 330 TotalM 421 97,883 268,359 Current Ratio 1.33 1.85 1.46 CA/CL 1.67 2.67 1.43 340 Lass from PreviousYear CA/FA 0.40 2.11 2.26 | 350 Loss from CurrentYear 6,918 Debt ($ million) $2 $22 $8 ______.__.______DebtService Ratio (Ull) 0.00 5.18 1.22 [360BALANCE ASSETS 165.137 493852 A/R as % of Sales 14% 34% 70

Page2 of 6 Profit and Loss MEGIONNEFTEGAS Unit Costs (Rubles/ton) (MillionRublesl Code [ 19911 1993 __ Code - . 1i__ 992 1993 Profit and Loss I 1 9 I Production(min tons) 16.01 14.6 13.5 10 Gross SalesRevenues (ca 4h) 60,328 266,6801 I 10 Avg DomesticPrice 1 4,490 28,428 15 VAT i 7,546 39,920!! 15 VATpercent 13% 15% 20 ExciseTiax I 2,4171 16,849! 20 Excisepercent 5% 7% 30 OdLer(MnclPRF) | 3,2081 13,27511 30 Otherpercent 5% 5% 40 ProductionCosts 35711! 213 409.; ij 40 Avg. Proda Cost 2.44 5.808 50 SalesGross Margin 0 11,446! (16,773;j 50 Avg. GrossMargin 785 (1,242 60 OtherNet Sales I 1,8201 (4781i 70 Non-SalesTransactions 12,4501 28,816S | SellingPrice in $/ton $20.0 $23.7 71 incl Securitiesand IV 2611 Prodn Cost in $/ton $10.9 $13.2 72 incl LocalTaxes 30,39911 80 Total Income 0 61t428 224974 90 BalanceProfit/Loss 0j 25,716 11,565i, 90 UnitProfit 1,763 857 92 Investme Deductions 0 4,256 101,1781 ii in $/ton S7.8 $0.7 94 Profit Tax 0 6,867 (28,676'I 92 NetIncome 0 18,849 40,241ij 92 Unit Net Income I 1,292 2,981 100 Excess LabourCosts - 17 Avg. ExchangeRate 25 _ 225 2

Profit Distribution Q 25i935 17618 i Production Costs($/ton I 200 Budget 7,459 9,1071 94 incl Profit Tax 0 6,867 (28,676j Base ProductionCost * $0.0 $10.9 $13.2 96 mcl Other (PRF, Royalty) 0 3,208 13,275 Addn. LabourCosts $0.0 $1.3 $0.0 101 incl Turnover Addn. Other Costs SQuSSu 150 incl ExcessLabour Tax i Total Prodn. Cost $0.0 $12.1 $13.2 i Rl~esora~ I (% increase) 9% 210 Reserves for Insurance 220 Savings/lnvestmentFund 14,160 incl InvestmentFund ddtions 230 ConsumptionLabour 4,116 459 250 Charity 260 Other 200 8,052 270 Rent/Lease on Land

Budget (Cash) O 1%U16 17482 Tax Exemptions 0 42i6 101-178 300 PropertyTax 69 741 500 ReconstructionInvest. 3,613 93,772 310 ProfitTax 1,476 9,048 520 EavironmentalProtec. 340 Royaltiesand Pollution 3,424 35,242 530 HealthCare Invest. 643 7,406 350 LandTax 8 44 540 Charity NGO's 355 VAT 7,562 29,441 550 Other 356 Excise Tax 1,156 3,072 560 Other - 360 ExportDuties 1,390 1,489 365 ImportDuties 380 PersonalTax 724 4,620 386 Other 3,262 15,711 390 Fines ,46 L8052 71

Annm -3 Page3 of 6 FINANCIAL STATUSOF PRODUCER ASSOCIATIONS Balance Sheet TOMSKNEGAS

C-de (MillionRubles) 1991 1992 1993Q3I [Code F 1991f_ 993Q3 1. Fixed Assets .Capital 1 12 Non-MaterialNFA 2 4 i 400 Charter Capital 3,197 3,609 5,629 20 Fixed AssetsGFA 3,915 91,388 116,9281 i 410 Resources 21 Accum. Depreciation 1,223 38,302 44,2441 420 SpecialFunds 9 62,990 118,389 22 Fixed Assets NFA 2,692 53,087 72,6841 430 EannarkedFinancial 162 4,521 14,747 30 EquipmentCWIP 26 557 1,046 440 Other 40 InvestmentCWIP 561 14,099 55,972 450 Other 50 LongTerm Investment 37 560 12,609 I 460 Other 60 Settlementof Founders 0 470 Profit in CurrentYear 8,737 2,448 70 OdLerNon-Current Asset Q 0 0 471 Profit Distnbuted 8,243 1,119 80 TotalFixed AssetsI 3,315 68,305 142,315 i 472 Profit Not Distributed Q 494 t.322 . 480 TotalCapital 3,369 71,614 140,094 II. Current Assets 100 Suppliers/Stocks 54 756 8,720 I 11. Current Liabilities 110 Cattle 7 59 5141 I 520 TotalLT Loans 8 7 401 120 Low ValueAssets 10 86 5161 600 Short TermBank Loans 233 5,056 13,382 130 UncompletedConstr. 0 4 7991 610 BankLoans to Persons 1 12 34 140 Advances 0 0 37 620 ShortTermrLoans 53 12 III 150 Production 45 174 1,503 630 Trade Payables 65 16,860 136,141 162 Materials 111 1,188 15,077 640 OutstandingBills 170 Trade Costs Goods 311 507 650 WagesPayable 33 373 3,447 175 Other 1,940 660 SocialInsur Welfae 9 581 6,938 176 Other 3 670 Prop. & PersonalInsur. 23 17 180 Total CurrentAssets II 227 2,578 29.940 680 Other 690 Non-Budgetary 3 1,327 7,596 m. Settlements 700 Budget 23 7,603 46,770 200 Receivables 72 27,995 136,228 I 710 OtherCreditors 60 1,495 4,391 210 Bills Receiveable 720 Advancesfrom Cust. 154 655 193 220 With Affiliates 730 AdvancePayments 614 1,603 230 to Budget/State 162 688 2,297 740 AdvancePayments 2 30 200 240 to Personnel 1 19 250 750 BadDebt Allowance 10 250 Other Debtors 51 414 11,387 760 OtherShort Term 31 22 Q 260 Advancesto Suppliers 19 236 1,828 770 Total 680 34,674 221,233 270 Short TermInvestment 31 27 63 280 Cash 1 114 548 I 780 BALANCE LIAB. 4,049 106,288 361,327 290 CurrentAccount 38 47 1,681 [ errors I 0.00% 0.00% 0.00% 300 Foreign Excbange 6 4,698 17,868 _ 310 Other Liquid Assets 123 683 3,590 Ratios 1991 1992 1993|| 320 Other CurrentAssets 330 Total m 502 34,920 175,738 CurrentRatio 1.07 1.08 0.93 CA/CL 2.61 1.24 0.86 340 Loss from PreviousYear 5 CA/FA 0.22 0.55 1.45 350 Loss from CurrentYear 485 13,333 Debt (S million) $12 $23 $12 i _Debt______Service Ratio (full) 0.00 1.31 -0.31 360 BALANCEASSETSR 4,049 106.287 361.325] |i A/R as %of Sales 21%, 27% 72

Page 4 of 6 Profit and Loss TOMSKNBFTEGAS Unit Costs (Rubleslton) (MillionRubles) 'JCode 1991 1992 1993Q3 Code _1991 19921993Q3 Profit and Loss f i Production(mln tons) 14.0 12.2| 8.2 10 Gross SalesRevenues (ca h) 35,821 124,616'! 10 Avg DomesticPricc 1 4 ,68 6 29,394 15 VAT 6,4481 20,545i 15 VATpercent 189 16% 20 ExciseTax 1,4691 6,208 20 Excisepercent 5%, 6% 30 Other CtnclPRF) | 4,1861 76 30 Otherpercent 129o 0% 40 Producton Costs I1.7.03Q 108&,931 40 Avg. Prodn Cost I M91 13.29 SO SalesGross Margin ° I 6,6891 (10,907; 50 Avg. GrossMargin 5461 (1,334 60 Other Net Sales 8.073 70 Non-SalcsTransactions I (1,425 SellingPrice in $/ton i $ 20.81 $24.5 71 inclSecuritiesandJV 1} J ProdnCostin$/ton $6.21 $11.1 72 incl Local Taxes 1581j 80 TotalIncome Q 23-719 104.434ii 90 BalanceProfit/Loss 0 6,689 (4,259 I 90 Unit Profit 5461 (521 92 InvestmentDeductions 0 0 4,944 i in $/ton S2.41 (S0.4 94 Profit Tax 0 2,140 (2,945 I 1 92 Net Income 0 4,548 (1,314 1 92 Unit Net Income 3721 (161 100 Excess LabourCosts 8 5:376 I Avg. Exchane Rate 1 251 2251 1.200 I I Profit Distribution 0 0 Di5 Production Costs ($/to4~ 200 Budget 761 94 inclProfit Tax 0 2,140 (2,945 | Base ProductionCost $S0.0o $6.2| $11.1 96 inclOther (PRF, Royalty) 0 4,186 76 Addn. LabourCosts $0.0 | $0.0 $0.0 101 incl Turnover 2,977 Addn. Other Costs Su $QQ Su 150 incl Excess LabourTax 1,688 TotalProd. Cost $0.0 $6.21 $11.1 i (% increaise) 79% 210 Reservesfor Insurance i 220 Savings/InvestmentFund l * incl InvestmentFund d6ductions 230 ConsumptionLabour 119| 250 Cbarity 260 Other 24 i 270 Rent/Leaseon Land I I_I_I_I_I

Budget(Cash) Q 38,417 Tax Exemptions 0 4.944 300 PropertyTax 756 500 Reconstructionlivest. 4,310 310 ProfitTax 2,211 520 EnvironmentalProtec. I 340 Royaltiesand Polluion 7,457 530 HealthCare Invest. | 635 350 Land Tax 222 540 CharityNGO's 355 VAT 12,109 550 Other 356 ExciseTax 6,208 560 Other _ __j 360 ExportDuties 77 365 bIport Duties 380 PersonalTax 1,943 386 Other 7,214 390 Fines 220 73

Amex 5-3 Page 5 of 6 FINANCIAL STATUSOF PRODUCER ASSOCIATIONS Balance Sheet YUGANSKNEFTEGAS (MilionRubles) Code 1991 1992 1993IQ3 Code 1 19911 1992 1993Q3 1. FixedAssets 1. Capital 12 Non-MaterialNFA 2 33 400 Charter Capital 6,076 6.218 10,673 20 Fixed AssetsGFA 8,274 200,975 256,701 410 Resources 21 Accum.Depreciation 3,295 88,926 101.058 420 SpecialFunds 50 142,859 289,535 22 Fixed Assets NFA 4,979 112,049 155,643 430 EarmarkedFinanial 7 105 9 30 EquipmentCWIP 35 978 3,613 440 Other 40 IavestmentCWIP 743 22,959 99,134 450 Other 50 LongTerm Investment 69 3,702 9,736 j 460 Other 60 Settlementof Founders 470 Profit in CurrentYear 32,463 65,973 70 OtherNon-Current Asset Q 0 0 471 Profit Distributed 32,667 70,480 80 TotalFixed AssetsI 5,826 139,690 268,159 472 Profit Not Distributed Q 3 (5 480 TotalCapital 6,133 149,184 295,711 I. CurrentAssets 100 Suppliers/Stocks 187 3,212 20,784 II. Current Liabilities 110 Catde 5 51 247 520 TotalLoans 10 1 120 LowValue Assets 34 272 2,645 600 Short Term BankLoans 189 19,950 53,096 130 UncompletedConstr. 7 117 15,499 610 BankLoans to Persons 2 0 20 140 Advances 0 0 202 620 ShortTerm Loans 4 4,051 4,869 150 Production 98 1,158 6,795 630 TradePayables 200 28,815 222,279 162 Materials 254 8,630 57,422 640 OutstandingBills 170 Trade Costs Goods 440 650 WagesPayable 175 1,773 13,032 175 Other 9,016 660 SocialInsur Welfare 18 1,391 17,014 176 Other &1 670 Prop. & PersonalInsur. 1 4 28 180 TotalCurrent Assets II 585 13,440 113,870 680 Other 690 Non-Budgetary 119 1,971 5,530 Im. Settlements 700 Budget 100 31,970 204,952 200 Receivables 117 28,355 268,549 710 Other Creditors 343 7,138 59,224 210 BillsReceiveable 720 Advancesfrom Cust. 1 663 723 220 WithAffiliates 730 AdvancePayments 0 990 1,091 230 to Budget/State 35 4,673 3,531 740 AdvancePayments 61 1,349 1,873 240 to Personnel 2 284 3,251 750 Bad DebtAllowance 250 Other Debtors 98 35,801 132,482 760 Other Short Term 454 0 Q 260 Advancesto Suppliers 3 612 15,995 770 Total 1,676 100,066 583,729 270 ShortTerm Investment 42 5,038 7,950 _ 280 Cash 1 167 675 780 BALANCE LIAB. 7,809 249,250 879,441 290 CurrentAccount 348 4,442 9,365 errors -0.00% -0.00% 0.00% 300 Forign Exchange 13 7,923 28,619 I I 310 Other iquid Assets 34 965 14,003 Ratios 1991 1992 1993 320 Other CurrentAssets 7D 7,542 7.987 330 Total II 1,397 95,808 492,406 CurrentRatio 1.18 1.09 1.04 CA/CL. 1.46 1.31 0.94 340 Loss from PreviousYear 1 1 CA/FA 0.34 0.78 2.26 350 Loss from Currew Year 312 5,0 Debt($ million) $8 $107 $48 ______DebtService Ratio (full) 0.00 1.33 1.14 360 BALANCEASSETS 7.8091249,251 879.441 A/R as % of Sales I f 8% 29% 74

An= 5.3 Page 6 of 6 Profit and Loss YUGANSKNEFNEGAS Unit Costs (Rubles/ton) (Million Rubles) Code 1 1991 1992 1993Q3 ICode 1991 1992 1993Q0 Profit and Loss Production(mln tons) 40.0 39.4 8.1 10 Gross SalesRevenues (ca h) 114,108 215,978 10 AvgDomestic Price 3,109 56,125 15 VAT 20,095 31,319 15 VATpercent 18% 15% 20 ExciseTax 4,911 5,140 20 Excisepercent 5% 3% 30 Other (Inal PRF, Royalty 14,165 30,745 30 Otherpercent 12% 14% 40 ProuedonCosts 54.2097 U7_6 40 Avg.Prodn Cost L5 1086 50 SalesGross Margin 0 20,840 61,108 50 Avg. GrossMargin 530 7,S68 60 Other Net Sales 5,422 (1,570 70 Non-SalesTransactions 5,604 6,435 SellingPrice in $/ton $13.8 $46.8 71 incl Securitiesand JV 6,812 1,830 Prodn Cost in $/ton $6.1 $9.0 72 incl LocalTaxes (349 (2,738 80 TotalIncome Q 85i963 13U" 90 BalanceProfit/Loss 0 31,866 65,973 90 Unit Profit 810 8,170 92 lnvestmentDeductions 0 2,128 23,518 in $/ton $3.6 $6.8 94 Profit Tax 0 9,516 13,586 92 Net Income 0 22,350 52,388 92 Unit Net lIcome 568 6,488 100 Excess LabourCosts 143 12889 Avg. AExcane Rate 25 225

Proftt Distrbution Q 32 20,483 Production Costs $fto 200 Budget 8,280 32,120 94 incl ProfitTax 0 9,516 13,586 BaseProduction Cost* $0.0 $6.1 $9.0 96 incl Other (PRF, Royalty) 0 14,165 30,745 Addn. LabourCosts $0.0 $1.7 $2.1 101 inclTurnover 6,482 Addn. OtherCosts SuQ Su SL 150 incl ExcessLabour Tax 207 4,507 TotalProdn. Cost $0.0 $8.6 $12.2 (% increase) 41% 210 Reservesfor Insurance 220 Savings/Invesmnt Fund 9,014 13,236 * inl InvestmentFund d :ucdons 230 ConsumptionLabour 15,310 20,733 250 Charty 12 238 260 Other 52 4,153 270 Rent/Lee on Land 415

Budget (Cash) Q 2982 37991 Tax Exemptions Q 2421 2U1I 300 PropertyTax 131 693 500 ReconstsucionInvest. 22 17,090 310 Profit Tax 3,019 3,671 520 Environment Protec. 340 Royaltes and Pollution 4,760 1,754 530 HealthCare Invest. 2,094 6,199 350 LandTax 32 92 540 Charity NGO's 12 230 355 VAT 9,961 18,371 550 Other 356 Excise Tax 3,916 1,270 560 Other 360 ExportDuties 710 365 ImportDuties 1,241 380 Persnl Tax 1,409 4,948 386 Other 5,909 4,379 390 Fines 45 1,572 75

Annex 6-1 Page 1 of 17

RUSSIA SECOND OIL REHABILITATION PROJECT

TECHNICAL OVERVIEW OF THE OIL PRODUCER ASSOCIATIONS

I. MEGIONNEFTEGAS (MNG)

A. Overview

1. Megionneftegasis a medium sized oil producing enterprise in Western Siberia with just under 17,000 employees. Its operational structure is made up as an association of a number of functional sub-units (see Annex 5-2) with an asset base of 9 developed and 6 undeveloped fields. In addition to the production units, the enterprise operates 27 drilling rigs, 40 workover rigs and supports substantial technical and social infrastructure in the region. In 1993, MNG produced 13.5 million tons of oil (270 thousand barrels per day), contributing 5 % of the oil from the Tyumen Region or about 4% of total oil pro&-i'edin Russia.

2. Foreign investment activity to date has been limited. A contract with MICI, a Belgian firm to finance well workovers and potential new field development is in a preliminary stage. Megionneftegasis also negotiating to assume part ownership of a refimeryin Belarous.

B. Investment Requirements/ProposedProject Component

3. Megionneftegasmedium term investment plans are summarized in the table below. Capital requirements for MNG to maintain production at 1993 levels is estimated at US$3.2 billion between now and the year 2000. This includes US$1.4 billion in new field development and US$1.8 for maintenance and routine well workovers. The proposed Project component will finance asproximately 10% of planned 1995/96 investmentactivity. Clearly the level of investment required by MNG to maintain production levels, although not as daunting as the larger Producing Associations, is stfillvery substantial.

Table 1 MegionneftegasInvestment Plan

1993 1994 1995 1996 Production(min tons) 13.5 13.0 11.9 11.3 Workovers (#) 695 700 720 730 of which Bank program 5% 5% New Wells (e) 295 700 800 800 of which Bank program 5% 5% Pipeline Replacement(kin) 920 920 920 920 of which Bankprogram 14% 14% 76

Annex 6-1 Page 2 of 17 4. MNG's oil production has been steadily declining since 1986. This is due to a combination of factors, the most prominent of which is the lack of fiancial resources to access the much needed equipment, spare parts and new technologyfor major field rehabilitation, and developmentof known fields. The technical difficulties experienced by MNG are principally due to the poor integrity of equipment, with many production weUlsrequiring excessivelyfrequent workovers due to mechanical failures of casing, primary cementations, tubing and sucker rod strings, and downhole pumps. Failure in the field pipeline and surface facility infrastructure has also been occurring at an accelerating rate due to increasing internal corrosion as field water production has escalated. To make an immediate impact on production levels, financing is urgently required for equipment and supplies to complete well workovers, drilling and completion of infill wells, and replacement of pipeline and surface facility infrastructure.

5. The proposed Project has been designed to promote an integrated approach to investment planning. Emphasis has been placed on field optimization and reservoir strategy. The proposed component for MNG therefore includes financing of rehabilitation, development operations and replacement of field pipeline and surface facility infrastructure in two fields; Megion and Pokoniasovskoye. To further catalyze the approach of investmentoptimization the proposed Project will also include financing for technical assistance to assist in preparing a detailed reservoir assessment and optimization strategy for the Pokomasovskoye field. Finally, a component is included to enhance the emergency and environmental response capabilities of the Producing Associations by financing required environmental equipment and training.

6. Project cost and operation summaries for each of the two fields in the proposed Project are contained in Annex 6-4 and Annex 7-1 respectively. The proposed Project, estimated to cost US$169 million (excludingimport duties and fnacing costs) would include: 75 well workovers and completions, 76 new infill wells, 255 mnof surface pipeline replacement, and the environmental equipment and training and technical assistance described above.

C. Brief Geological Setting

7. The license area of MNG is approximately 150 by 300 kilometers, located in the Tyumen Region of West Siberia. The south flank of the license area is forested ground which lies generally above the flood plain. In contrast, the nordtern license region is dominated by the flood plain of the river Ob. The flood plain reaches up to 50 kilometers in width during the spring and summer months, and in 1989 was officially declared a Water Resource Protection Zone. MNG has subsequentlybeen required to adapt traditional operationalprocedures to reduce any further adverse environmental impact in the Protected Zone area. These regulations have resulted in a significarnt curtailment in MNG's oil production potential. Modificationsto conventionaldrilling practices have not been able to meet the enviromnentalrequirements and substantialproduction has therefore been indefinitelyshut in. Two of the fields most significantlyimpacted by these constraints are the Megion and Pokamasovskoyefields. Without access to foreign exchange and proven internationaltechnology and expertise, particularlyin regard to horizontal well drilling and drilling fluids, this production will remain undeveloped. Following is a brief overview of the fields to be included within the proposed Project. Operational statistics for each of the fields and for MNG in total are shown in Tables later in this Annex. 77

Annex 6-1 Page 3 of 17

Megion Field

8. The Megion field is one of the pioneer oil fields of Western Siberia covering some forty square kilometers of the Water Resource Protection Zone. First production came on streain in 1964 and production reached close to I million tons in 1990 (20 thousand barrels per day). The field comprises three producing zones each developed with its own grid of production wells and water injectors. The producing horizons include; A-group, B-8, and the Jurassic formation with average reservoir depths of 1718, 2110, and 2470 meters respectively. Continuous injection of water has maintainedreservoir pressure at close to original thereby preventing the decline of gross production rates (oil and water). Water cuts have been steadily increasing and are currently averaging over 85 percent. Oil production in 1992 was 0.85 million tons (17 thousandbarrels per day) down 15 percent from the level produced in 1990.

9. As shown in the table below, remaining recoverable reserves at the Megion Field are estimated at 16 million tons (118 million barrels) and are located principally in the permeable Cretaceous B-8 and A-Group reservoirs. The primary drainage of these reservoirs are essentially complete, however, it is estimated that over 2 million tons (14.76 million barrels) of undrained reserves lie under the river Ob, beyond the reach of Soviet deviated drilling technology. The Jurassic reservoir no longer presents a viable target for further development drilling, although the potential for fraccing or commingled production should not be excluded. The proposed Project is designed to tap the remaining reserves through horizontal well drilling while undertaking the required well rehabilitation and surface facility investnent to drain this field to maturity. A sequential implementationof this component is recommended to ensure expected productivity is achieved.

Table 2 Megion Field Reserves (million tons)

Reservoir Initial Productionto Remaining Reserves Date Reserves A- Group 6.1 1.3 4.8 B-8 56.1 46.0 10.1 Jurassic 7.7 0.3 1.3

Total 63.8 47.6 16.2

Pokamasovskoye Field

10. The Pokamasovskoyefield also lies entirely within the flood plain of the river Ob, but unlike Megion is in the early stages of development. The field is jointly exploited by Langepasneftegasfrom the north bank of the Ob and by MNG from the south. MNG's development drilling in parts of the field have been indefinitely suspended untl appropriate equipment is accessible to reduce the environmental impact of continued drilling activity in the field.

11. Production from the Pokamasovskoyefield started in late 1988, and 216 wells have been 78

Annex 6-1 Page 4 of 17 drilled on a close grid in the center of thefield. Production reached a plateau rate of over 1 million tons in 1991. Water injection was initiated in 1989 and reservoir pressure is again close to original.

12. The reservoir is a sand of Jurassic age, on average 7 meters thick and located at a depth of 2740 meters. It is set in a low relief anticline whose crest corresponds approximately to the course of the river Ob. As shown below, remaining reserves are estimated at 14 million tons (103 million barrels) with two thirds of these located in the shut-in North and West North West area of the field.

Table 3 Pokamasovskoye Field Oil Reserves (million tons)

Field Area Initial Production to Rematning Reserves Date Reserves

Central 7.4 2.9 4.5

North 2.8 0.0 2.8

WNW 6.7 0.0 6.7

Total 16.9 2.9 14.0

D. MNG Operational Data

13. The following provides operational data for the MegionneftegasProducing Association and that of the two fields included within the Project. Table 4 Megionneftegas: Hlistoric Operational Performance Statistics

1986 1988 1990 1992 1993

Production/Injection: Oil mill.tonslyr 22.5 21.5 17.3 14.6 13.5

Water mill.tons/yr. 34.4 55.9 66.6 73.8 74.0

Gas mill m3/yr 1505 1443 1157 977 758

Water injected mill.tons/yr 68.1 76.7 70.8 81.9 78.0

Development Wel Statistics

Producers 1567 2124 2483 2871 3076

Idle Wells 156 68 149 148 298

Injectors 291 422 529 637 682

Total Wells 2014 2614 3161 3656 4046

Avg. Oil Prod./New Well tons/day 57 25 19 14 12

Avg. Water Cut % 61 72 79 84 85 79

Annex 6-1 Page 5 of 17

Table 5 Megion Field: Historic Operational Performance Statistics

1986 1988 1990 1992

Production/lnjection: Oil mill.tons/yr 0.85 0.91 0.95 0.85

Water mill.tons/yr. 2.19 4.38 4 98 5.38

Gas mill m3/yr 68 73 76 68

Water injected mill.tons/yr 3 31 2.83 3 03 3.44

Development Well Statistics

Producers 79 140 171 173

Idle Wells 29 12 19 18

Injectors 9 15 26 34

Total Wells 117 167 216 225

Avg. Oil Prod./New Well tons/day 37 12 8 3

Avg. Water Cut % 72 83 84 86

Table 6 PokamasovskoyeField: Historic Operational Performance Statistics

x______1988 1989 1990 1991 1992

Production/Injection: Oil mill.tonstyr 0.01 0.24 0.59 1.05 1.06

Water mill.tons/yr. 0 0 0.04 0.12 0.30

Gas mill m3/yr 1 13 32 57 57

Water injected mill.tons/yr 0 0 0.56 1.90 2.30

Development Well Statistics

Producers 2 26 67 108 149

Idle Wells 0 2 20 32 33

Injectors __ _ 0 0 13 23 34

Total Wells 2 28 100 163 216

Avg. Oil Prod./New Well tons/day 43 44 31 30 22

Avg. Water Cut ___ I 0 0 6 10 22 80

Annex 6-1 Page 6 of 17

II. TOMSKNEFT (TN)

A. Overview

1. Tomskneft is a medium sized Producing Association located in the Tomsk region abutting Tyumen with iust under 27,000 employees. The operational structure of TN is an associationof five NGDU's (production units) including; Streshevoyneft. Vakhneft, Vasyuganneft, Luguinesneft, and Igolneft. The enterprise has an asset base of 25 discovered fields, 6 of which are currently under development. In addition to the production units, the enterprise operates 42 drilling rigs, 110 workover rigs and supports substantialtechnical and social infrastructure in the region. In 1993, TN produced 11.6 million tons of oil (230 thousand barrels per day), contributing 4% of the oil from the Tyuiren Region or about 3 % of total oil produced in Russia.

2. Tomslneft has had an active approach to foreign investmentactivity. Contracts, although still insignificant in terms of total investrnentrequirements, are nonetheless further forward than some of the larger producing enterprises. Contracts have been reached with Fracmaster (with IFC involvement) and with Oman Oil. Contracts to workover 705 wells by October 1994 have been agreed.

B. Investment Requirements/Proposed Project Component

3. The medium term investment plan for Tomskneft is summarized in Table 1. Capital investment requirements for TN to maintainproduction at 1993 levels is estimated at US$3.5 billion between now and the year 2000. This includes US$1.5 billion in capital investment (US$0.4 billion to bring shut in wells back on stream and US$1.1 billion to develop known fields), and an additional US$2 billion to fmance maintenance and routine well workovers.

Table 1 Tomskneft Investment Plan

1993 1994 1995 1996 Production (mln tons) 11.6 11.7 11.3 11.1 Workovers (#) 2800 3700 4000 4400 of which Bankprogram 6% 6% New Wells (#) 809 720 720 750 of which Bank program 1% 1% Pipeline Replacement(km) 1,000 1,100 1,100 1,100

of which Bank program 26% 26%

4. TN operations include 4,112 producing wells and 1,311 injectors (see Table 2). Of the 81

Annex 6-1 Page 7 of 17 producing wells 2,260 (55%) are equipped with sucker rod pumps, 932 (23%) with ESP's and 920 (22%) are flowing. The flowing wells are required to shift to artificial lift (ESP's) in the near future. The number of shut-in wells has risen sharply over the last few years growing from 400 in early 1990 to over 1,500 at present. Pump failures are a significant operational constraint causing replacement at least once per year (compared with at least two years for international equipment).

5. TN also has severe operational difficulties with its 4,300 kilometers of pipeline and surface facility infrastructure. Pipeline failures and operational shut downs are accelerating due to escalating internal corrosion, exacerbated bv the low quality of the steel pipe.

6. The proposed Project includes an integrated approach for field rehabilitation(well workovers, in-fill drilling and replacement of field infrastructure) in three of Tomskneft's three most important fields; Sovetskoye (Strezhevoyneft NGDU), Vakhskoye (Vakhneft NGDU), and Pervomaiskoye (Vasyuganneft NGDU). The proposed Project will also include financing for technical assistance to assist in preparing a detailed reservoir assessmentand optimizationstrategy for the Sovetskoyefield. Finally, a component is included to enhance the emergency and enviromnentalresponse capabilities of the Producing Associations by financing required enviromnentalequipment and training. Project cost and operation summaries for each of the three fields in the proposed Project are contained in Annex 6-4 and Annex 7-1 respectively. The proposed Project, estimated to cost US$195 million (excluding import duties and fiacing costs) would include: 525 well workovers and completions, 11 new infill wells, 576 km of surface pipeline replacement, and the environmental equipment and training and technical assistance described above.

C. Brief Geological Setting

7. The license area of TN is approximately700 by 400 kilometers straddling the territory of the Tomsk and Tyumen regions of West Siberia. A large percentage of the operational environment is wetland, where operations are particularly subject to environmental sensitivities. Oil reserves of TN are estimated at 570 million tons (4.1 billion barrels) contained in reservoirs of Lower Cretaceous and Upper Jurassic age. The oil is of high quality with a specific gravity of 0.82-0.85 and a viscosity at reservoir conditions of 0.5-0.9 centipoise. All fields are subject to water drive by water injection whereby the reservoir pressure is kept close to initial, which is hydrostatic.

Sovetskoye Field

8. Production from this field marked the start of operations of Tomskneft PA in 1972. It is the PA's largest field with an original oil in place volume of 530 millions tons and approximately 226 million tons ultimate recovery. Cumulative production stands at 130 million tons leaving 96 million tons as remaining reserves. Oil production has declined continuouslyover the last 8 years by 5% to 10% each year, to about 3 million tons per year at present.

9. Production is principally from the Lower Cretaceous, the main production formation is the A horizon, subdivided into 8 zones of decreasing aerial extent and with thicknesses varying between 3 and 10 meters. The less importantB horizon is now essentially depleted. 82

Annex 6-1 Page 8 of 17

10. Major reservoir and fluid characteristicsare summarized in Table 3 below. The average well rate is 8 tons per day; water cuts range from 40% to 90%, averaging 70% for the Al reservoir and 84% for the whole field. To date a total of 1,190 producers and 230 injectors have been drilled; 150 producers are closed in, awaiting repair. Detailed well and production statistics are shown below.

11. The medium term drilling program for the field involves 400 infill wells both in the center and the northern part of the field. The 30-35 wells planned for 1994 are expected to yield an average oil production of 16 tpd.

12. The pipeline system in Sovietskoyeis more extensive than in other fields. During the initial development phase wells were drilled from individual pads rather than in clusters. The system suffers from major corrosion problems causing frequent leaks and consequent well shut-ins and pollution.

Pervomaiskoye Field

13. This field is the Vasyugan NGDU's largest accumulation and accounts for about 70% of its oil production. The reservoir is an Upper Jurassic, single monolithic sandstone at a depth of about 2,550 m with a thickness varying between 6 and 10 m. Major reservoir and fluid characteristics are summarized in Table 4 below. A total of 470 oil wells and 490 injectors have been drilled to date and the primary development of the main field is considered to be complete. The ultimate oil recovery is estimated at 44 million tons of which 50 per cent (22 million tons) has been produced. The production history over the last 8 years is shown below.

14. The average well produced 20 tons/day; the current field water cut is just over 20 per cent. A total of 150 producers and 60 injectorsare currently closed in for repair. Corrosion pi oblems are mainly encountered in the water injection system and in the production system connected to the high water cut producers. The field extends in a westerly direction into the Tyumen region and development is planned for this area by drilling a total of 250 wells, 160 producers and 90 injectors. The feasibility of drilling slim hole side tracks from existing wellbores, either to replace a lost drainage point or to recover attic oil will be investigated on a small scale (4 wells). As this is an ecologically sensitive forest area, it would benefit from the application of horizontal drilling rather Fan the currently planned developmentby conventional, vertical wells.

Vakhskoye Field

15. The Vakhskoye Field has been on production since 1976. It is subdivided into three areas: the central, the eastern and the northern area. Development started in the central area, followed by the eastern area in 1986 and the northern area in 1988. The total initial oil in place is estimated at 323 million tons, with ultimate recovery at 146 million tons of which 30 million tons have been produced to date (see Table 5).

16. Production is from the Upper Jurassic Jl and J2 reservoirs; sand thicknesses vary between 5 and 20 m. Major reservoirand fluid characteristicsare given in Table 5. The total numberof producersis 780: 370 in the central,290 in the easternand 120 in the northernarea. Of these some 83

Annex 6-1 Page 9 of 17

280 are closed in. The recent production history of the total of the three areas is shown below.

17. The northern area is least developed, with only 4% of its reserves produced to date, and a major part of the future drilling activity (some 500 wells) is focused on this area. However, part of it is located under the flood plains of the Vakh river, which makes it an ecologically sensitive area and a prime target for development by high angle/horizontal wells.

18. Average oil production rates in the three areas are in the range of 8 to 16 tpd/well, water cuts between 21 % and 53 %, the highest value referring to the central area. Three horizontal wells have been drilled in the field so far, of which two are on production. The performance of these wells has been disappointing, which is attributed to the severe formnationdamage, caused during drilling. Corrosion problems are most severe in the central area, which has been on production for the longest tine and has the highest watercut.

D. Tomskneft Operational Data

19. The following provides operational data for the Tomskneft Producing Association and the three fields included within the Project.

Table 2 Tomskneft: Historic Operational Performance

1993 Production/Injection:Oil mill.tons/yr 11.6 Water mill.tons/yr. 21.1 Gas mill m3/yr 1,224 Water injected mill.tons/yr 42.7 DevelopmentWell Statistics Producers 4,112 Idle Wells 1,559

Injectors 1,311 Total Wells 6,982 Avg. Oil Prod./New Well tons/day 8 Avg. Water Cut 65% 84

Annex 6-1 Page 10 of 17

Table 3 Sovetskoye Field: Historic Operational Performance

1986 1988 1990 1992 1993

Production/Injection: Oil mill.tons/yr 5.0 4.5 2.9 3.2 2.9

Water mill.tons/yr. 13.1 15.6 16.7 16.1 15.2

Gas mill m3/yr 357 279 242 203 181

Water injected mill.tonslyr 17.4 17.6 17.1 17.4 17.2

Development Well Statistics

Producers 876 974 981 1.019 1.039

Idle Wells 36 30 81 127 146

Injectors 197 196 212 226 232

Total Wells 1,109 1,200 1,274 1,372 1,417

Avg. Oil Prod./New Well tons/day 9.6 15.1 15.8 29.1 12.5

Avg. Water Cut % 72% 78% 81% 83% 84%

Table 4 Pervomaiskoye Field: Historic Operational Performance

1986 1988 1990 1992 1993

Production/Injection: Oil mill.ton /yr 1.9 3.0 3.2 2.7 3.4

Water mill.ton/yr. 0.2 0.4 0,4 0.6 1.0

Gas mill m3/yr 196

Water injected mill.ton/yr 3.7 5.8 6.8 6.2 7.5

Development Wel Statistics

Producers 230 334 385 360 470

Idle Wells 78 95 102 120 210

Injectors 238 360 430 475 494

Total 546 789 917 955 1,174

Avg. Oil Prod./New Well tons/day 30 33 15 20 20

Avg. Water Cut % 8% 11% 11% 17% 23% 85

Annex 6-1 Page 11 of 17

Table 5 Vakhskoye Field: Historic Operational Performiance

1986 1988 1990 1992 1993

Production/injection:Oil mill.ton /yr 2.5 2.6 2.6 1.9 2.6 Water milfLton/yr. 1.9 1.7 1.7 1.0 1.2 Gas Mi: m3/yr 70 75 230 180 177 Water injected mill.tonlyr 6.2

Development Well Statistics Producers 480 570 650 470 780 Idle Wells 15 40 100 315 280 Injectors 140 180 220 220 244 Total Wells 635 790 970 1,005 1,304 Avg. Oil Prod./NewWell tons/day 21 12 10 11 9 Avg. Water Cut % 45% 40% 40% 34% 32% 86

Annex 6-1 Page 12 of 17

III. YUGANSKNEFIEGAS (YNG)

A. Overview

1. Yuganskneftegas is one of the largest oil producing enterprises in Russia, producing about 15% of the oil produced in the Tyumen Region and contributing about 10% of the Russian total. It has an asset base of 42 developedfields and over 55,000 employees. By internationalcomparison, based on current production levels, (production in 1993 was 33 million tons or 660 thousand barrels per day), Yuganskneftegas is simnilarin size to one of the larger mid sized internationaloil companies such as Amoco. Current production levels understate the size of the enterprise, however, as by its proven reserve base and past production levels it would be more comparable with one of the internationalmajors such as Exxon or Royal Dutch Shell. By any comparison, as part of an effective economic reform programnand successfulenterprise restructuring, YNG should have the asset base to become a strong and profitable oil enterprise.

2. Yuganskneftegas includes four NGDU's (production units) namely; Ustbalik, Mamontova, Maiskoye, and Pravdinskoye. In addition to the production units, the enterprise operates 93 drilling rigs, 124 workover rigs and supports substantial technical and social infrastructure in the region.

B. Investment Requirements/ProposedProject Component

3. The medium term investment program for YNG is outlined in Table 1 below. Capital investment requirements for YNG are substantial. To maintain production at 1993 levels it is estimated YNG would require US$10 billion between now and the year 2000. This estimate includes about US$5 billion in capital investment (US$1 billion tr bring shut in wells back on stream and US$4 billion to develop known fields), and an additional US$5 billion for maintenance and routine well workovers. Although the proposed Project for Yuganskneftegaswill make an immnediateimpact on production levels and export earnings, the level of investrnent that YNG requires to stabilize production levels will only be achieved through massive external direct investment.

Table 1 YuganskneftegasInvestment Plan

1993 1994 1995 1996 Production (mlnitons) 33.4 30.7 25.9 24.2 Workovers (#) 2,200 3.400 4,300 4,500

of which Bank program 7% 7% New Wells (# 990 1,000 1,100 1,100

of which Bank program 2% 2% Pipeline Replacement(km) 1,200 1,200 1,200 1,200 of which Bankprogram N/A N/A 87

Annex 6-1 Page 13 of 17

4. YNG is a prime example of the difficulties facing oil producing enterprises in Western Siberia. Production has declined by over 40% since 1988, when YNG produced over 68 million tons of oil (1.4 million barrels per day) and the outlook is for this trend to continue. This rapid decline is the result of two key factors. First, YNG has depended on two super giant fields for tle majority of its production (Mamontova and Ust-Balyk). These fields have reached maturity and are entering into natural decline. This natural decline has been significantly accelerated, however, by the lack of equipment and spare parts for routine maintenance and well workovers in these large existing operations. YNG has an existing stock of over 1 1,300 producing wells, 3,400 of which are currently shut in awaiting repair or new equipment.

5. Second and equally important, however, YNG has not been able to fmance investmentin new field development to bring proven reserves into production to offset the expected production declines from its maturing fields. For YNG to stabilize production in the medium term major investment will be required both in; (i) routine maintenanceand well workovers to maximize production in existing fields; and (ii) new field development to bring proven reserves on stream.

6. The proposed Project for YNG includes an integrated approach to address these concerns. The proposed Project would fmance: (i) a modernizationprogram for the Mamontova field including well workovers, rehabilitation, and in-fill wells to make an immediate impact on production levels and increase ultimate economic recovery, (ii) completion of wells in the Srednye Asomkinskoye field, where many potentiallyprolific wells have been left idle due to a lack of required technology for high pressure hydraulic fracturing, and (iii) in-fi!l drilling in Prirazlomnoye for which advanced deviated drilling techniques are required to address reservoir permeability and environmental concerns. Emergency response equipment and training is also proposed to assist in reducing the environmentalimpacts of production, and, technicalassistance to prepare a field optimization strategy for the Prirazlomnoye field.

7. Project cost and operation summaries for each of the three fields in the proposed project are contained in Annex 6-4 and Annex 7-1 respectively. The proposed Project, estimnatedto cost US$223 million (excluding import duties and financing costs) would include: 576 well workovers and completions, 40 new infill wells and the environmental equipment and training and technical assistance described above.

C. Brief Geological Setting

8. The license area of YNG is approximately300 by 400 kilometers, located inthe Tyumen Region of West Siberia. The northern limit of the license area is defmed by the river Ob, and the western by the river Irtush. The flood plains of these major waterways and their tributaries reach a width of up to 50 kilometers during the spring and summer months. Following is a brief overview of the fields included within the proposed Project. Operational statistics for each of the fields and for YNG in total are shown in the Tables below.

Mamontova Field

9. The Mamontovafield is one of YNG's largestoil fields, and one of the first to have been 88

Annex 6-1 Page 14 of 17

brought on production, in1970. Production reached its peak in 1986 at 35 million tons peryear, (700 thousand barrels per day). It is estimated that over 30% of the producing wells are out of service, awaiting workovers. The reported loss of production potential is estimated at 250,000 tons per year.

10. The field comprises six producing zones each developedwith its own grid of production wells and water injectors. The producing horizons include; A-4,5,6 and B-8, 10,11 with average reservoir depths between 1,900 and 2,455 meters. Continuous injection of water has maintained reservoir pressure slightly above original, thereby preventing the decline of gross production rates (oil and water). Water cuts have been steadily increasingand are currently averaging over 85 percent. All wells are on artificial lift using either ESP's or beam pumps. Oil production in 1993 was 14.0 million tons (280 thousand barrels per day) down over 60 percent from the peak 1986 level.

11. As shown in Table 2 below, remaining recoverable reserves in the Mamontova Field are estimated at 140 million tons (over 1 billion barrels) and are located principally in the permeable Cretaceous B-10/11 reservoirs at a depth of about 2,500 meters. The primary drainage of these reservoirs are reaching maturity, however, significant undrained reserves lie within unswept areas of the main field and at the edges of the field limits, supporting further economic in-fill drilling.

12. This proposed Project is designed to tap the remaining undrained reserves through well workovers and horizontal well drilling while undertaking the required well rehabilitation to support this field to reach ultimate economic recovery. As the field has over 4,500 development wells it is beyond the scope of the World Bank project to rehabilitate the entire field. Well selection and screening will be undertaken to ensure that investment is targeted to the most productive wells while maintaining sufficient concentration in activities within the field to demonstrate the Project impact.

Table 2 Mamontova Field Reserves (million tons)

Reservoir Iitial Production to Remaining Reserves Date Reserves A-4 38 30 8 A-S,6 21 12 9 B-8 10 5 5 B-10,11 504 386 118 Total S73 433 140

Srednye Asomkinskoye Field

13. The Srednye Asomkinskoyefield lies in a remote area some 100 km east of Nefteyugansk. It is the major field in a cluster of oil fields, commonly called the Fainskoye Fields, which have all S9

Annex 6-1 Page 15 of 17

proven to be oil bearing in the Jurassic reservoir. Except for the northernmost tip, the field is entirely outside the southern limit of the river Ob. rhe southern and eastern limits fall within a heavily forested area.

14. The field was brought on to production in 1989 and 200 wells have been drilled on a close grid in the center of the field. Production has been disappointing in the suo-vertical wells despite water injectionhaving been implementedfrom the outset. This is due to the poor inflow performance of the wells as a result of a relatively low matrix permeability coupled with poor drilling practices, particularly the heavy mechanical skin left on the wellbore. Many wells have been left idle since the departure of the drilling rig due to a combinationof poor evaluation results and the inability to finance necessary foreign equipment and technology for acidising and high pressure fraccing operations.

15. The reservoir is a sand of Jurassic age, on average 7 meters thick, set in a low relief anticline with an average permeabilityof 36 mD. As shown in Table 3 below there is an estimated 11 million tons (80 million barrels) of remaining recoverable reserves. YNG entered into a foreign joint venture with Fracmaster which has had excellent success with hydraulic fracturing of these wells. The contract with Fracmaster is agreed on an annual basis with specific wells targeted for the Joint Venture. Since there are a substantialnumber of wells which require hydraulic fraccing the Project component is anticipated to fully complementthe activities of the private sector.

Table 3 Srednye AsomkinskoyeField Oil Reserves (million tons)

Reservoir finitial Production to Remaining Reserves Date Reserves Jurassic U-1 12 1 11

Prirazlomnoye Field

16. The Prirazlomnoye field is a giant field which is located in the north western corner of YNG's license area and is in the very early stages of development. The northern limit of the field area lies under the flood plain of the river Ob, and the south western under that of the river Irtush. A substantial portion of the central and southern area underlies a vast cedar forest reserve. The southern half of the field was offered for tender, however, no agreements have been reached.

17. The north central portion of the field has been under conventional development since 1986, but production performance on a per well basis has been disappointing. This is attributed to a combination of low formatioi. permeabilitycoupled with poor drilling practices which have induced mechanical skinson the wellbores.

18. The reservoir is a sand of Jurassic age, that thickens from some 6 meters in the south to over 20 meters in the north. Permeability also improves toward the north, reaching 60 mD. As shown 90

Annex 6-1 Page 16 of 17 below the field's remaining recoverable reserves are estimated 224 million tons (1.6 billion barrels). Russian Institutes have proposed horizontal well drilling to develop this field, but the Soviet deviated drilling technology is not sufficiently advanced for this field's development. The proposed Project is therefore proposed as a demonstrationproject for horizontal well drilling in this field to hopefully catalyze further private sector involvement.

Table 4 PrirazlomnoyeField OJIReserves (milliontons)

Resevoir IIniall Productionto Remaining Reserves Date Reserves Jurassic B-4,5 230 6 224

D. YNG Operational Data 0

19. The following section provides operational data for the Yuganskneftegas Producing Association and the three fields included within the Project.

Table S Yuganskneftegas: HistoricOperational Performance

1992 1993 1994 (proj) Production/lnjection:Oil mill.tons/yr 40.8 33.4 30.6 Water mill.tons/yr. 134.2 141.0 147.7 Gas mill m3/yr 1,576 1,500 Water injected mill.tons/yr 221.1 220.0 222.0

Development Wenl Stadstics

Producers 11,303 Idle Wells 3,435 injectors 3,223

Total Wells 17,961 Avg. Oil Prod./New Well tons/day 14.3 13.5 11.2 Avg. Water Cut % 77% S1% 85% 91

Annex 6-1 Page 17 of 17

Table 6 Mamontova Field: Historic Operational Performance

1986 1988 1990 9I' 1993

Production/Injection: Oi mill.tons/yr 35.2 31.3 24.4 15.3 14.0

Water mill.tons/yr. 36.5 84.7 91.9 74.6 56.8

Gas mill m3/yr 1,480 1,320 1,103 640 588

'Water injected mill.tons/yr 92.2 116.3 119.1 96.7 88.8

DevelopmentWell Statistics =_=_=_=_=

Producers 2,481 2,546 2,746 2,296 3,875

Idle Wells 48 120 198 938 1,260

Injectors 856 1092 1169 1,183 1,349

Total Wells 3,385 3,758 4,113 4,417 6,484

Avg. Oil Prod./New Well tons/day 40.5 34.0 28.4 19.3 18.0

Avg. Water Cut % 51% 63% 73% 80% 80%

Table 7 Srednye AsomkinskoyeField: Historic Operational Performance

1989 1990 1991 1992

Production/Injection: Oil mill.tons /yr 0.032 0.207 0.076 0.185

Water mill.tons/yr. 0 0 0.003 0.008

Gas mill m3/yr 2.18 14.08 5.17 12.58

Water injected mill.tons/yr 0.052 0.331 0.181 0.321

Development Well Statistics __=

Producers 22 62 88 51

Idle Wells 0 8 49 79

Injectors 4 6 11 22

Total Wells 26 761 148 152|

Avg. Oil Prod./New Well tons/day 8 18 6 7

Avg. Water Cut % 0 0.8% 4% 4% 92

Annex 6-2 Page I of 2 RUSSIA SECOND OIL REHABILITATIONPROJECT

TECHNICALRECOMMENDATIONS

1. This Annex discusses a number of aspects of oil upstream operations in West Siberia which need attention as a means of enhancingoperational efficiency and increasing productivity, some of which would be directly relevant to the proposed Project.

A. Geophysical and Exploration Geology

2. On various techniques currently being employed for the discovery and delineation of new oil fields, the following are recommended:

(a) The need for closer coordinationbetween the Producer Associations and enterprises responsible for appraisal of new oil reserves to enable formulation of optimum field development plans;

(b) Increased use of seismic surveys and data to better define and delineate the geological structures, thereby enablinga significant reduction in the number of wells needed for defining the reservoirs; and

(c) Coordination of exploration and development drilling programs to facilitate compatibilitywith, and the use of, exploration wells in production operations.

B. Development Drilling and Well Completion Practices

3. In view of the very large number of developmentwells which are drilled to exploit the fields, and the large number of fishing operations which are required for maintainingwells on production, it is suggested that each of the Producer Associations involved in the Project set up a technical task force to review and recommend a revision of the current drilling and completion practices, which would allow for a reduction in the number of wells required and thereby reduce the number of workovers. This task force would consider:

(a) the possibilityof simultaneouslyproducing reservoirs intersected by individual wells;

(b) improving the quality of the geological data acquired from each well by using modern logging and well testing techniques and services;

(c) improving the quality of well completion and stimulationpractices by using modem and higher quality cement, chemicals and technologies; and

(d) using higher quality tubing and couplings which would greatly reduce the number of fishing jobs caused by parted tubing. 93

Annex 6-2 Page 2 of 2 C. Oil Production and Reservoir Pressure Maintenance

4. Very large volumes of fluids (oil and water) are currently being produced. Over the passage of fime, the crude oil content is continuously decreasing. Moreover, very large volumes of water are injected into the reservoirs under the pressure maintenanceprograms. The Producer Associations are encouraged to consider the advantages of:

(a) lowering the pumping mechanismemployed for lifting fluids in the wells to increase weU deliverabilities;

(b) injecting crude oil/water emulsionbreaking chemicals into each well on production, to allow for the rapid separation of water from the effluent at the first gathering facility;

(c) reducing, or possibly eliminating, the amount of water being injected into the reservoirs; and

(d) preparing reservoir models to better understand the behavior and performance of the wells and reservoirs (a technical assistance provision is included in the proposed Project for reservoir modelling as discussed in Annex 6-3).

D. Surface Production Facilties and Pipeline Operations

3. The following measures are suggested:

(a) In order to reduce waste, it should be possible for the Producer Associations to require from steel mills a fill quality control inspection of all tubulars purchased, prior to their shipment to the centers of consumption;

(b) To mitigate internal corrosion of all surface facilities and flowlines, the Producer Associations would need to initiate and sustain, on a continuous basis, a program of chemical injection for corrosion inhibition;

(c) To reduce external corrosion of all pipelines and flowlines, Producer Associations should organize an appropriate quality control monitoring system to ensure that all lines are wrapped and coated properly with suitable materials and include, whenever possible, galvanic protection of the pipelines by an impressed current and sacrificial anodes; and

(d) Consider, over time, a major redesign of most production facilities to simplify operations and to allow for the rapid eliminationof reservoir-produced waters as soon as possible from the production trains and systems. 94

Annex 6-3 Page 1 of 3 RUSSIA SECOND OIL REHABILITATION PROJECT

FIELD OPTIMIZATION STUDY RECOMMENDED SCOPE OF WORK

A. Objectives

1. To establish a medium and long term field developmentplan for a key field under production to maximize the future economic performance of the field's exploitation, whilst also maximizing the recovery of remaining oil.

2. To establish a computerized data base of both technical and financial data in order to continuouslyupdate the study results, as further production and operating cost data become available, in the search for further economic optimization.

3. To develop an operations philosophy which will serve as a basis on which to continue exploitation of the field through to abandonment. This will include the identification of procedures needed to ensure successfulapplication of new technologies and field accounting processes identified during the course of the study.

4. To facilitate the transfer of ownership and full responsibility for the economic exploitation of the field entirely to the Production Association, in contrast to the current situation where Field Development Plans are dictated centrally.

5. To ensure incorporation of environmental considerations as a fundamental criterion in the technical design and in the operations philosophy for the field.

B. Analysis of Existing Data

6. The first step will be to load all available data into an appropriate data base. Such data will include seismic, wireline logs, well deviation data, well tests, core data, historic fluid production and water injection, pressure build-up, PVT, analyses of production and injection waters and maps of surface facilities. Well files, including drilling and work-over histories, should also be made available. These data will then be analyzed, validated and checked for consistency and accuracy.

C. Identification of Additional Data Requirements

7. After analyAisof the existing data, additional operations and/or data collection may be recommended in order to complete the data set. Such items could include additional seismic, drilling and coring of monitoring wells, wireline logging, more accurate production measurements through upgraded measurement facilities and trials to remove mechanical skin in the well-bore. 95

Annex 6-3 Page 2 of 3

D. Reservoir Modelling and Characterization

8. Analysis of the data from Tasks B and C above will allow a geological model to be developed. This will include structure maps, isopach maps, and cross-sections. This information, together with wireline log and core analysis, will be used to obtain a characterizationof the reservoir which will provide a quantitative description of the spatial variation of the main reservoir variables (porosity, permeability and oil saturation).

9. The model will form the basis for determinationof the original oil in place volumes, accurate analysis of past reservoir performance and predictions of future production performance.

E. Reservoir Engineering Stuffies

10. Reservoir studies, both conventional, and based on a simulation model, will then be performed in order to evaluate the past reservoir performance and to validate the reservoir model. This model will then be used to:

(a) evaluate alternative development scenarios; (b) obtain a reliable estimate of the remaining recoverable reserves under each scenario and select the economically optimum scenario; (C) identify the main uncertainties in future field development; and (d) provide guidance for a program of reservoir surveillance and field management.

F. Production Engineering Studies

11. These studies will address production optimization issues such as well completions, prevention of wellbore damage, removal of mechanical skin, potential for dual completions, recompletion strategy, horizontal wells and artificial lifting methods.

G. Operations Philosophy and Procedures

12. A new operations philosophy needs to be developed to guide the Associations through the period of adaptation to the new economic and cost-consciousenvironment. The introduction of new techniques and technologies as identified by the Field OpdtmizationStudy needs to be supported by a clear vision of how oil field operations are to be run in the future. New procedures will need to be developed in support of these operations. Crucial will be the establishment of an integrated production operations planning, monitoring and control system.

H. Alternative Surface Facilities

13. In response to the results of Tasks E, F and G above, the design and operations of surface 96

Annex 6-3 Page 3 of 3 facilities will be reviewed. This will include the promotion of scenarios which minimize the enviroramentalimpact of the Field DeveiopmentPlan.

I. Economic Evaluation

14. Each scenario proposed under Task E above will be evaluated with regard to marginal costs and benefits and cash flow. A detailed model for Operating Costs (OPEX) will be developed in order to allow optimization of the future business performance of the field. A particular focus will be an assessment of the economic remaining reserves in support of Task E above.

J. Field Optimization Plan

15. The above work will be summarized in a Field Development Plan which will propose one scenario for the future exploitation of the field which provides the highest economic returns, consistent with the Operations Philosophy. Investment opportunities will be identified to further improve the economic performance of the field. This FDP will then be incorporated in the Business Plan of the Production Association.

16. The FDP will be a living document, to be reviewed on at least an annual basis as additional technical, production and cost data become available. A data base will have been established which will facilitate the future managementof the field.

K. Training

17. Throughout the above sequence of integrated activities, the training of Production Association and other staff in a systematicapproach to the optimization of a field's economic performance in the new business environment will be emphasized. The Field RedevelopmentStudy clearly offers the ideal opportnity to provide personal growth in both technicaland managementskills over a two year period and develop self-sufficetncyfor field optimizationdecisions within the Production Association. 97 A6U Pa lotas

IMPLEMEITAIION SCBEDTJLE

1994 1994 1994 19f 199S 1995 - 95 . . j , .______02 Q3 Q4 QI 02 Q3 Q4 Ql 02 Q3 _ BoatdPxtwuiiilo 30Juan LOanEffecthveow (90 days) - AdvisonMobhil d 1:. Av#.

Rig BidRelme Rig Bid Rpaation (75 das) *SCpl Rig BidEvalustim (30 das) 14-Olt RigConiumdn (15days) Z f Workar Rig Dciivuy (I 10 days) ALL *feb Duling RigSev (90 days) MNG1. Drlg RigDevry (150 dao) YNG ; OtderBid Rdease w1y 0. Sp BidPmparin (45day) 164)d ."-4un WidEvaluszo (45 da) WI.$* ISJIuI (30 das Contring (15 day) . t 3Sut Ddhelim (60 days) . 3Fr34

Flkh Audios WJuuafJ .. Field Optinaon Studies SOcti

Workovers 47 188 355 509 650 792 959 1,113 NewWells 4 20 40 57 74 90 110 127 LinepipeReptac-m (n) 51 205 387 555 709 863 1,045 1.085

Sof Towal ogm 4% 17% 32% 46% 53% 71% S6% 100% WatkDaw Avllble 70 25 77 91 84 77 77 91 84

XPENDURME PROFULE (S MONO) 1994 1994 1994 1995 1995 1995 1995 1996 1996 1996- ...______0_QQ2 Q3 Q4 ,Q3Q4 Qi 02 03 Q4 Warweriig$ 2 4 9 Dril Rigp 6 36 Suppsrlunt 4 11 11 Procaslng iqulpm= S 14 14 Eavloamen_ Equipment 2 5 5 Equ ument&COmmodktes 16 29 29 29 41 41 41 Servies 14 3 11 12 11 11 11 12 11 Teche aAssbtsw I 1 1 2 2 2 2 2 2 2 Fueld9udles 1 0 1 1 1 1 1 1 L4caosucton 4 11 13 12 11 11 13 12 Cont_geocies 2 3 3 3 5 S 5 LocalThasport importuies 15 16 4 6 6 6 Sub-Total DA SZA AU 147.2 iS 1MA 221 2A2 25.1 i MCand Fees 3 8 8 13 C undavExpenditures 1 53 145 2J3 367 446 530 606 653 678

%of Toatd 0% 8% 21% 43% 54% 66% 78% 89% 96% 100% S in RuaainFY 8% 58% 34% %n 1ngikYa. 43% 460 1% TOTAL OPERATIONS

-______I_ Total MNO TO YNC war&ft~ft 1.176 75 525 76 .Rip I8 2 6 10 Day perWoulover 10 16 6 12 Tml Timc(YausC) 2.1 1.8 1.7 2.1 ffgff i V127 76 11 40 RIj 6 3 1 2 Darper Wenl 28 27 25 30 TomlTi(Yeau) 2.1 2.1 0.Q 1.8 I.085 407 59S 80 CQws U 3 4 Darper kmperCww 4 4 4 4 T IsMThwYeun) 1.3.6 1.8 &-&

* s an 330 tl wailablsdays per yeaw.R1ga hods we icopoae h vasge wwopai d.

07.4:PM - ONOW 98 PagelotS

(USSmiloa) AggregateProject act~ ~ Toa _lmet 1994 1995n _1 Tota Lca Porex Tomi I______L1ca Ptx Toald Loca Forex Tota Loca Pro 1. Equipment & Mat8oals _ __ BaseCost 336 336 33 33 227 227 76 76 PbysicalCoatng4acies 26 26 2 2 17 17 6 6 PriceConmncaes 6 6 Q a a I 2 ToW Cost 367 367 36 36 247 247 84 84 2 Commodr4es BaseCost 13 13 1 1 7 7 5 P bysicalConzngnies I 1 0 0 0 0 0 PriceComingen"es Q Q Q Toal Cost 14 14 1 1 8 8 5 3Services BaseCost 88 88 13 13 34 34 41 4 PhysicalCotingencies 6 6 1 1 2 2 3 PriConeinesnia 2 a 0 Q 1 1 1 TotalCost 96 96 14 14 37 37 45 45 .TechnicalAssistance DaseCost 21 21 2 2 9 9 11 11 Physic Co _tigacias 2 2 0 0 1 1 1 PficeCondngencies a a a a Q Q Q S Toal Cost 23 23 2 2 to tO 12 12 S.Local LabourlConutiudon BaseCost 85 85 39 39 46 46 PhysicdContinescies Price Congezcies 2 1 1 Totl Con 87 8 40 40 48 48 6. LocalTransport Bas Cog PhysicalContingencies Price Contingemns Total Cost

.ImportDutes 53 53 5 S 36 36 12 12 TotalBase Project Cost 139 458 596 5 49 54 75 277 352 59 131 1 .PhysicalContigencles 34 34 4 4 20 20 10 10 Prme CoDngncies 2 a la Q a 1 1 j 1 A Tol ProjectCost 141 500 640 S 53 S8 75 302 377 60 146 206 . Finandng Costs on IBRDLoan 38 38 3 3 1I 1 18 1 on Cher Lon

10. Total Finandrno Requlrd 141 538 678 5 56 61 75 318 394 OD

0646 PM-06 JW" 99 AAe3 6. page 3 of 5

(U3S$million) Megionneftegas

PwjectEeet . Toial 1994 199S 1996

_1_ Equ_pmen___M__ t_ Local PFoex Total Loca Forex Toad L Fox Toala Local Forx ToWa

Base Cost 92 92 110 0t 66 66 - 16 16 Physical Coangcia * 6 6 1 1 4 4 - I 1 PriceCondngedes *1 1 0 I I - a Q TotalCost 99 99 11 11 70 70 - 17 17 2. Commodites BaseCost 7 7 0 0 - 4 4 , 3 3 Physical Condngencbes 0 0 0 0 0 0 - 0 0 PriceContingencies 0 a 0 0 0 0- 0 0 TotalCost 8 8 1 1 4 4 - 3 3 3. Services Basecost - 34 34 5 5 13 13 - 16 16 PbysicalConingencies - 2 2 0 0 1 1 PriceContdagencies - 1 1 Q 0 Q - 0 0 Toal Cost 37 37 5 5 14 14 - 17 17

4. Technical Assistancs BaseCost - 6 6 0 0 3 3 - 3 3 Physical Contlngencies - 0 0 0 0 0 0 - 0 0 PriceContingecies - 0 0 Q 0 0 a - 0 0 TotalCost 6 6 1 1 3 3 - 3 3

S. Local Labour/Construction Base Cost 19 - 19 9 - 9 10 - 10 Physical Contingeies PriceCoaingenries 0 - 0 0 - n 0- 0 Total Cost 19 - 19 9 9 11 - 11

6. Local Transport Bass Cost Physca Contingencies Prie Contgencies Tota Cost

T.ImportDuties iS - 15 2 - 2 11 - 11 3 - 3

TotalBasseProjectCost 34 139 173 2 16 18 19 85 105 13 37 SO .Physical Co_Mi AgNs 8 8 1 1 5 3 2 2 Prce Contigencies 0 2 I Q Q Q 1 1 Q 1 1 otalProjectCo-s 35 150 184 2 17 19 19' 92 111 13 41 54

9. Financing Coats on IRD Loan 12 12 1 1 5 S 5 5 on OUe Loans

10. Total FinancinaReulred 35 161 196 2 18 20 19 97 117 13

06:46 PM -06/0994 100 Page 4 of 5

RIM SFCnN EABU.TIN PRJC

Tomskneft ProjectElemems | Tatal 199 1995 1996 Equipment MMaterials .. Local Forex Toma Local Forex Totall Loca] Forex ToTal

BaseCost - 116 116 - 10 10 747 74 - 3 32 PhysicalConnagencies 10 10 . 6 6 - 3 3 PriceConingencies 2 2 -Q 1. 1 - I1 TotalCost - 128 128 . 11 11 82 82 - 3S 35 . Commodities BaseCost * 2 2 - 0 0 * 1 1 * 1 1 Physical Contingencies 0 0 . 0 0 . 0 0 - 0 0 PriceCondngencies a Q -- aQa a Toal Cost 2 2 . 0 0 1 1 I 1 3. Services B CaseCst - 20 20 - 3 3 8 8 9 9 Physical Condngencies 2 2 . 0 0 . 1 - 1 PriceContingencies - aQ- a a a a - a Q Total Cost - 22 22 3 3 8 - 10 10 4. Technical Assistance BaseCost 8 8 1 1 3 3 - 4 4 Physical Contingencies I I 0 0 - 0 0 - 0 0 PriceContingencies a a a a - a a - a a Total Cost - 8 d 1 1 4 4 - 4 4 S. Local LabourlConstructon BaseCost 35 - 35 . 16 - 16 19 - 19 PhysicalContingencies Price Coningencies 1 1 - . 16 19 - 19| TotalCost 35 35 16 16 19 19 S. Local Transport BaseCost PhysicalContingencies PriceContingencies Total Cost

7. Import Dutes 18 - 18 2 - 2 1I1 it -

Total Base ProjectCoats 53 145 197 2 14 16 27 86 113 24 45 69 p PhysicalCondngencies 12 12 1 1 7 7 4 4 PriceContingencles I 1 1 a a a I I 1 1 2 TomalProjectCost 53 160 213 2 15 17 27 94 12 24 so 75 S. Flnancing Costs on tBRDLoan 12 12 1 1 5 5 6 on OtherLoans

10. Total FinancingRequIred 53 172 225 2 16 18 27 100 127 ^

06:46PM -06/09194 101 PqeSofS

Yugapskmeftegas TOI 199 1995 . 9 ______._____ L0-a1 SOr Totd Local Form ToW al 7xR Totn Local por Te 1. Equlpment & Materals. Dam cost 128 128 . 13 13 - 87 87 - 28 PbsicalCoungetcies 10 10 - 1 I . 7 7 - 2 2 } PriceCondvgenc- 2 I - 1 - I11 TotadCost - 140 140 - 14 14 95 95 _ 32 32

* Commodities I CoseCt 4 4 o0 0 2 2 - 2 2 PysiycnContnos - 0 0 0 0 0 0 0 0 PridceConugences a Qa - a Q - a a TotalCost - 5 5 - 0 0 3 3 2 2

BaseCost - 34 34 - 5 5 - 13 13 - 16 16 PhysicalContingencies 2 2 - 0 0 .I I 1 PriceCoqiencies I1 1 - a a Q a I Totl Cost 37 37 - 5 5 14 14 *17 17I

Technical Assistance BECost - 7 7 - I I 3 3 - 4 4 iPysw ConfingewAft I1-01 . 0 0 0 PorieCosDt CieS a a a Q a Q a a Dl ToutalCost a 8 - 1 1 3 3 4 4

S. Local Labour/Corstructl"'n BasmCost 32 - 32 1Si - 15 17 - 17" PhysicalContdngencies - Price CContngeves 1 - 1 - Q 1 - TOal Cost 33 - 33 IS - IS is

8. Local Transport BaseCost Phya Contigncies Prie Conngencies TOSaCost

T. Import Outes 20 20 2 - 2 14 - 14 5 -

Total Base Projet Cosbt 52 174 226 2 19 21 28 106 134 22 49 71 8 PhyswcalContdnges 13 13 1 1 8 8 4 4 PriceCoingencies 1 A Q a a a 1 2 TotadPoje Cost 53 190 243 2 20 22 28 115 144 22 S5 77

*.FInancing Costb on lMD Laa 14 14 1 1 6 6 7 7 on e Loans 4 10.TotalFlnanclna Rewuy 53 204 257 2 21 23 28 122 150 :2 61 8

06:46 PM - 06I~9A4 LENDING ARRANGEMENTS, LEGAL DOCUMENTS, AND ELOW OF FUNDS

4>FUNDS

LOA AGREEMENT ACCOUNT AG E

RUSSIANFEDERATION

LOAN ON - LENDING AGREEMENTS FUNDS

MNG l l

GOODS& SERVICS| PRODUCINGASSOCIATIONS PROJECT IMPLEMENTATIONUNIT (FOR EACII PRODUCING ASSOCIATION)

PROJECT DIRECTOR

E P ICRMN.AAE ' l I P_ROCURMENT MANAGER TECIHNICAL MANAGER FINANCE MANAGER ADMIN/LOGISTICS MANAGER

EIELD TECHNICAL UNITS

0 - GEOLOGIST - RESERVOIR ENGINEER - PRODUCTION ENGINEER - DRILLING ENGINEER - ENVIRONMENT ENGINEER

______------

OS PROCUREMENT SPECIALIST TECHNICAL SUPPORT rINANCIALLOGISTICS I UNDER BANK PPFr UNDER BANK PPF1 SPECTALISTS SPECIALIST

BE I I I g ~~~~~~~~~ENVIRONMENTGEOLOGIST/ PRODUCTION DRILLING 104

Annex 6-7 Page 1 of 9

RUSSIA SECOND OIL REHABILITATION PROJECT

TCECNICAL, PROCUREMENT AND LOGISTIC SERVICES FOR THE PROJECT IPLEMiENTATION UNIT

DRAFf TERMS OF REFERENCE

I. INTRODUCTION

1. The Government of the Russian Federation and (Producer Association Name) have applied for a loan from the World Bank for US$ million equivalent towards fnancing components under the World Bank's Second Russia Oil Rehabilitation Project. The beneficiary intends to apply part of its loan to a contract for Technical and Procurement Advisory Services, which is the subject of this letter,

2. The Producer Association will establish a Project Implementation Unit (PIU) which consists of the following Russian staff to be designatedby the Association: a Project Director would head the PIU and would be supported by a Technical Manager, a Procurement/ Disbursement Manager, a Finance Manager and a Logistics/ AdministrativeOfficer. In addition to the PIU, the Producer Association will form Field Technical Units at the NGDU level consisting of the following staff designated by the Association: a Geologist, a Reservoir Engineer, a Production Engineer, a Workover/ Drilling Engineer and an EnvironmentSpecialist.

3. To strengthen the PIU, consultingsupport services would be provided under the proposed loan to assist the Technical, Procurement, Logistics and Finance Managers. A reputable, internationallyknown firm, conversant with West Siberian conditions and World Bank practices, will be selected to provide the followingspecialists for the PIU backed by the experience and home office support of the firm. Other skiUs that you feel may be appropriate should be included in the proposal:

(a) Specialists to support the Technical Manager would likely include a Reservoir Engineer who would assist in project management,a Production Engineer, a Drilling! Workover Engineer, an Oilfield Equipment specialist, a Pipeline engineer (in Tomskneft and Megiomieftegas)and an Environmental Specialist. These specialists would provide advice on project implementationto the PIU Technical Manager in their respective areas of competence. This advice would be extended to the NGDU level through the Field TechnicalUnits;

(b) A Procurement Specialistwould advise the Producer Association on World Bank and oil and gas procurement procedures and assist in all aspects of the procurement process (including the preparation of draft equipment specifications and bid documents, preparation of bid evaluation reports and final contracts with suppliers and service ,ontractors, and preparation of disbursement requests) as well as 105

Annex 6-7 Page 2 of 9

recommend the institutionalchanges required to strengthen the Producer Association's procurement capabilities; and

(c) A Logistics Specialist would provide support to the logistics manager in the managementof shipping, inspectionand expediting contracts and overall logistics and materials management, in conjunction with the procurement teamn.

4. Knowledgeof the Russian petroleum industry will be a definite advantage as will previous experience on World Bank-financedprojects for procurementactivities. Each of the above specialists would need to be available for the two years over which the Project would be implemented. The specialists would be needed at the Producer Associations with the exception of the procurement specialist who would work out of the Association's Moscow based procurement office. The Producer Association will provide accommodationand board. The specialists should be aware that living and working conditions prevailing in Western Siberia during most of the year are severe.

5. Home office support will also need to be made available throughout the implementation period of the Project to provide qualified vacation backup and assist with training, specialized technical skills, liaison with the World Bank and any technical queries that come up. It is expected that approximately 110 man-months of total support will be required.

6. Feasibility studies have been carried out to define the Project, which will be made available to shortlisted bidders. Procurement will be divided into roughly two equal tranches and the Producer Association has commenced developmentof draft bidding documents (based on World Bank standard bidding documents) and detailed equipment specifications for the first tranche of equipment and services, with the assistance of local procurement advisors. The selected firm would be expected to provide immediately a procurement specialist and a specialist to assist in fmalizing equipment specifications to complete this process prior to bid document release. The Loan is expected to be approved and effective by September 1994 and the objective is to have the procurement process completed and a maximum number of contracts ready for award shortly thereafter. Initial Project implementationwill start in late 1994 or early 1995. The remaining technical specialists would be required to mobilize approximately 1 month prior to this date.

I. BACKGROUND

7. The proposed Project's principal objectives are to help reduce the decline in oil production in three West Siberian Oil Producing Associations by restoring idle and underproducing wells, drilling selectednew weUsin existing fields, rehabilitatingsurface infrastructure and enhancing future production and operating practices through provision of critical goods, services and technical assistance. The estimated total cost of the Project is approximately$680 million for which the World Bank is considering a loan totalling $500 million equivalent. The proposed Project will finance contracts for the critical goods and services needed by the Producer Association to support the following key project components;

(a) Workover of approximately 1.200 shut-in and under-producing oil wells including 106

Annex 6-7 Page 3 of 9

replacement of electric submersible and sucker rod pumps, utilizing purchased international workover rigs with 80 to 100 ton lifting capacity;

(b) Drilling of approximately 125 new wells in existing oilfields including horizontal wells, using purchasedor contracted internadonal drilling rigs (in Megionneftegasand Yuganskneftegas);

(c) Provision of technical services including MWD, logging, perforation, cementation, acidizing, and other specialized services to support the workover and drilling program;

(d) Replacement of over 800 km of oil gathering lines and production flow lines including partial installationof glass epoxy pipe (in Megionneftegasand Tomskneft);

(e) Undertaking of a field optimization study for a major field under operation including provision of data processing facilities, training, data collection and technical assistance; and

(f) Improvement of environmental management including emergency spill response capabilities, environmental monitoring, relations with indigenous peoples, training and initiation of pilot environmentalclean-up programs.

HI. TECNICAL ADVISORYSERVICES

8. The general tasks for which the technical specialists will assist the PIU are outlined below. Procurement and logistics tasks are outlined subsequently. Other tasks which you consider important should also be included in the proposal.

(a) Assist in the development of detailed drilling, completion, workover and infrastructure work programs related to the Project;

(b) Assist in the evaluation of geological/reservoir engineering data to select candidate wells and establish implementation priorities and assist in refinement of field development plans based on data obtained during Project implementation;

(c) Provide technical assistance and advice with regard to insta}lation,commissioning, operation and maintenanceof the oilfield equipment supplied under the Project, assist the Association with specification of requirements for future procurement of equipment and services under the Loan and support the PIU in the management of well service contracts and other contracts associated with the Project;

(d) Assist in the implementationofimproved drilling and completiontechniques to reduce formation damage and enhance production capability of the field so that the nmber of wells required to drain the reservoir may be reduced; 107

Annex 6-7 Page 4 of 9 (e) Assist with evaluations of surface facilities operated by the Association, and recommend where possible, measures to optimize operational procedures in order to minimize costs and maximize oil and gas throughout. Make technical reconunendations and assist in the development of alternate solutions for the installationand operation of surface facilities associated with the Project;

(f) Assist the Producer Association with co-ordination and management of the field development studies and training program and assist in the preparation of programs for acquisition of geological/reservoir data to be obtained from the drilling of new wells or during the workover of older wells;

(g) Assist the Producer Associationwith development of detailed terms of reference for enviromnental studies and implementationof the environmental management, pilot clean-up programs and environmentaltraining components of the Project; and

(h) Prepare periodic progress reports, as agreed with the PIU Manager and the World Bank, for all the drilling, workover and infrastructure programs funded under the Project.

IV. PROCUREMENTAND LOGISTIC ADVISORY SERVICES

9. For the loan to be successful and funds disbursed quickly, the Producer Associations will need technical assistance in the field of procurementand logistics/ materials management. Personnel in each Producer Associationare technicallycompetent, but the traditionalprocess for satisfying their procurement requirements has broken down. The Association requires support, particularly in the area of equipment specification and formal bid document preparation. To overcome these difficulties, the following services would be required from the selected consultant:

(a) Assist the World Bank to design and conduct a one week initial training program for Producer Association staff involved in procurement covering (i) how the World Bank's procurement policies and procedures will apply to their specific equipment needs and (ii) the nature of the current oil field equipment market;

(b) In conjunction with the oilfield equipment specialists help the Producer Association finalize technical specificationsfor critically needed equipmentand package each item in a way to attract maximum competitionfrom bidders;

(c) Advise the Producer Association on the appropriate methods of procurement to be used for each package (International Competitive Bidding - ICB or Limited InternationalBidding - LIB);

(d) Assist the Producer Association in preparing specific ICB bidding documents using the Bank's Sandard Bidding Documents for Goods for use on all World Bank- financed packages; 108

Annex 6-7 Page 5 of 9

(e) Develop with the Producer Association a procurement schedule allowing reasonable time for each step but resulting in a maximum number of contracts being ready for signature shortly after loan effectiveness (approximately September 1994);

(f) Monitor ongoing progress of the entire procurement process in the Producer Association, helping to resolve, if needed, any problems relating to advertising, the preparation of high quality specific bidding documents, answering requests for clarifications from bidders, bid opening procedures, bid evaluation criteria and techniques, preparation of high qualitybid evaluationreports for World Bank review, steps leading up to final contract signature, establishment of Letters of Credit, and in conjunction with the logistics specialist described below provide assistance in managing equipment delivery, customs clearance, inland transportation and final payment and processing of disbursement requests to the Bank; and

(g) Establish a reporting system for the Producer Association that will promptly flag problems in any of these areas.

10. The consultant will be responsible for the overall design and logistics of the training course mentioned in point (a) above. The World Bank will provide all course materials and possibly a trainer for a two day presentation concentratingon Bank policies and procedures. One day should be reserved for a detailed discussion about the petroleum equipment market covering traditional and new potential sources of supply, sources of current informationabout prices and other current market trends, etc. The remaining two days should be spent answering questions, finalizing the initial procurement plan for the Project and worldng on the drafting of the model bidding documents to be used on the Project.

11. It is anticipated that the selected firm will need to make available one full time expatriate knowledgeable in all aspects of procurement and contract administration. Previous experience on World Bank-financedprojects will be a definite advantage.

12. In addition to the Procurement Specialist based in Moscow a Logistics/ Materials Management Specialist is required in the Producer Association to provide initial support to the logistics manager in the management of shipping, inspection and expediting contracts and in establishment of warehouse procedures to handle equipment under the Project. 109

Annex 67 Page 6 of 9

RUSSIA SECOND OIL REHABILITATION PROJECT

FINANCIAL SUPPORT SERVICES FOR THE PROJECT IMPLEMENTATION UNIT

DRAFT TERMS OF REFERENCE

I. BACKGROUND

1. The proposed Project's principal objectives are to help reduce the decline in oil production in three West Siberian Oil Producing Associations by restoring idle and underproducing wells, drilling selected new wells in existingfields, rehabilitating surface infrastructureand enhancing future production and operating practices through provision of critical goods, services and technical assistance. The estimated total cost of the Project is approximately $680 million for which the World Bank is considering a loan totalling $500 million equivalent. The proposed Project will finance contracts for the critical goods and services needed by the Producer Association to support the following key Project components;

(a) Workover of approximately 1.200 shut-Ti and under-producing oil wells including replacement of electric submersible and sucker rod pumps, utilizing purchased international workover rigs with 80 to 100 ton lifting capacity;

(b) Drilling of approximately 125 new wells in existing oilfields including horizontal wells, using purchased or contracted internationaldrilling rigs (in Megionneftegasand Yuganskneftegas);

(c) Provision of technical services including MWD, logging, perforation, cementation, acidizing, and other specialized services to support the workover and drilling program;

(d) Replacement of over 800 lan of oil gathering lines and production flow lines includingpartial installationof glass epoxy pipe (in Megionneftegasand Tomskneft);

(e) Undertaking of a field optimizationstudy for a major field under operation including provision of data processing facilities, training, data collection and technical assistance; and

(f) Improvement of environmental management including emergency spill response capabilities, environmental monitoring, relations with indigenous peoples, training and initiation of pilot environmentalclean-up programs. 110

Annex 6-7 Page 7 of 9

II. FINANCIAL ADVISORY SERVICES

2. The Producer Association [NAME OF ASSOCIATION] requires the services of a firm, familiar with both Russian and international oil and gas accounting practices, and with experience in accounting and financial managementunder inflationary conditions to provide specialists to assist in the implementationof the Second Oil RehabilitationProject.

3. The World Bank requires maintenance of separate and auditable project accounts with the goal of ensuring loan proceeds are utilized efficiently and for the intendedpurposes. The contracted firm will assist the Association in enhancementof current project accounting procedures and systems to ensure full accountability of project funds and enable timely preparation of Project progress and completion reports. Project accounting will be required within NGDU's on a well-by-well basis. Project accounting procedures should be developed with due regard to materiality.

4. In addition to project implementationassistance, the Association requires general financial advisory services. This includes immediate assistance in improving management information capabilities and developing cash managementprocedures. Support is also desired in the process of transformation to internationalaccounting practices including the preparation of Association financial statements which conform to international standards. The contracted firm will provide specialists to:

(a) assist in short term financial management and planning including support in the development of sound cash, receivable and payable policies taking due account of the unstable and inflationary environment in which the Association currently operates; and

(b) provide training in international oil and gas iccounting principles which will assist the Association in preparation of financial statements which conform to international standards. An initial task of the contract will be an overall training, information and systems "needs" assessment.

5. The Producer Associationswill appoint an external auditor acceptable to the Bank at the start- up of project implementation. The contracted firm should coordinate its advisory efforts with the audit firm. 111

Annex 6- Page 8 of 9 III. SCOPE OF SERVICES

6. Under the direction of the Project ImplementationUnit, implementationwill occur within one or more NGDU's in the Association over a two year period (from September 1994 to December 1996). The Financial Specialist/Specialistswill need to be in place at the start of project implementation.They will report to the Finance Manager and will maintain close coordination with the Procurement and Technical Managers of the PIU as well as the technical and procurement spcilists assisting them.

7. The contracted firm would be expected to carry out the following tasks. Other tasks that are deemed important should be included in the proposal.

(a) Review project accountingrequirements and current accounting systems and practices at the Producer Association. A broader review will also be conducted by the external auditors to identify potential accounting problems. These reviews should be carried out in parallel to ensure consistency. Prepare a list of required procedure changes and a work program for implementationby the Association.

(b) Develop (if necessary) a simple computerized database system and recording procedures which will allow maintenanceof separate project records (by NGDU and by wells). Produce monthlyreports of project progress in both Russian and English. Training in system use should be carried out at the Association along with training in basic computer operations. The advisory firm should procure three micro- computers (1 per NGDU involved in the Project), together with printers and supplies which will be installed within the PIU.

(c) Provide seminars on managementand fincial accounting principles and practice. Initial seminars should be directed at senior management of the Association with later seminars directed at specificaccounting and economics functions of the Association. Seminars on Generally AcceptableAccounting Principles (GAAP) and the adjusting entries required to transform Russian accounts to basic international GAAP should highlight particular aspects of GAAP as regards oil and gas operations. The Association will be required to prepare year-end financial statements for 1994 according to both Russian standards and GAAP.

(d) Carry out a diagnostic study of short term management information requirements. Cash managementprocedures (including receivable, payable and inventory systems and strategies) should be examined in particular detail. Identify critical areas where the Association would benefit from short term advisory services and technical assistance and prepare terms of reference in conjunction with Association management. Approximately5 man-months are budgeted for these tasks.

The consultant should also prepare terms of reference for implementationof a broad management information system including computerized accounting systems to be 112

AM k1 page 9 of 9 carried out at a later date.

(e) On-going Supervision. One specialist should be at the Association for initialproject transactions, then every four months to monitor Project progress and accoting.

IV. ESTIMATED DURATION AND EFFORT

8. The Project is expected to require the following commitment in consulting services. The estimated '.dvelsof effort shown below are intended as a guide only.

(a) Project Accounting System Review Timing: Month 1 Estimated Effort: 2 weeks senior, 2 weeks intermediate at the Association.

(b) Project Accounting Procedures and System Development Timing: Month 2 Estimated Effort: 4 man-weeks intermediate (2 weeks at the Association)

(c) Seminars on Management and Financial Accounting (GAAP) Timing: Month 2 Estimated Effort: 6 weeks (senior) including 4 weeks at the Association

(d) Diagnostic Review of Information and Advisory Needs Timing: Month 3 Estimated Effort: 5 man-weeks - 2 weeks intermediate, 3 weeks senior.

Short Term Advisory Services Timing: Starting Month 4 Budget: 18 weeks including 10 weeks senior and 8 weeks intermediate.

(e) On-Going Project Supervision Estimated Effort: 4 weeks during initial equipment delivery period plus 2 weeks every four months for a total of 16 weeks (intermediate) 113

Page 1 of 2

RUSSIA SECOND OIL REHABILITATION PROJECT PROJECT SUPERVISION PLAN

1. The following supervision p!an takes into account only the requirements associated with implementing Project components in the Producer Associations. Reviewing progress on the Government's oil sector reform program and associated technical assistance will require approximately 20 staff-weeks per year in addition. An average of 45 staff-weeks is required each year for Project supervision.

2. Review meetings will be held in each of the three Producer Associations each April (prior to release of the coming year's equipmenttenders) and September (prior to fnalization of the coming year's workover program). On conclusionof each Mission the Ministry of Fuel and Energy will be briefed in Moscow.

3. Records will be maintained by each Producer Association showing original schedule against actual achievements and supplied to the Bank on the following aspects of the Project:

(a) procurement actionby bid package (bid specifications, bid invitation,openiing of bids, bid evaluation, award of contracts, signing of contract, and contract price);

(b) physical progress accordingto Project components and contracts (highlightingcritical activities and bottlenecks);

(c) actual Project costs and expenditures (local and foreign) and estimated remaining expenditures (local and foreign) projected quarterly through Project completion;

(d) information on problems encountered during implementation (including major mishaps) and expected impact on commissioning schedules; and

(e) minutes of meetings and progress reports of advisors.

4. Progress reports by each Producer Association and the Ministry of Fuel and Energy are to be submitted as follows:

(a) quarterly progress reports starting in September 1994;

(b) actual and forecast financial statements within three months of the end of each fiscal year starting in March 1995;

(c) audited Project accounts and fmancial statements within six months of the end of each fiscal year stardng July 1995; and

(d) a Project completion report. 114

Page2 of 2 RUSSIA SECOND OIL REHAILITATION PROJECT BANKSUPERVISION PLAN

IApproximate _xpected stiiifPM Dates Activity Skill Requremenas (staffweek:,

05/94 Procurement/EquipmentReview 10.0 (Pre-Board) Task Manager - FinalizeEquipment Usts Ist Bids PetroleumEngineer - ReviewPIU Lettersof Invitation EquipmentSpecialist - FinaUlizeProcurement Arrangements ProcurementSpecialist - ReviewDraft Bid Documents

07-09/94 Bid DocwnentReview PetroleumEngineer 12.0 - ReviewFinal Bid Documents ProcurementSpecialist

09-11/94 Bid Evaluationand WorkplanReview 14.0 - ReviewBid Evaluations Task Manager - InitiateWorkover Planning PetroleumEngineer - ReviewField Opdtmization TOR ProcurementSpecialist

12/94 WorkplanReview (Year 1) 14.0 - ReviewFinal Bid Evaluations Task Manager - ReviewLogistics Arrangements PetroleumEngineer - ReviewWell WorkoverPlans ProcurementSpecialist

04/95 SecondYear Equipment Review I 12.0 - ReviewEquipment List 2nd Bids Task Manager - ReviewFirst YearWorkover Results PetroleumEngineer - ReviewFirst Year FinancialPosition ProcurementSpecialist FinancialAnalyst

05-08/95 Bid DocumentReview PetroleumEngineer 14.0 -ReviewDraft BidDocuments ProcurementSpecialist

09-11/95 WorkplanReview (Year 2) 14.0 -ReviewFinal Bid Evaluations Task Manager - FinalizeWorkover Plans PetroleumEngineer ProcurementSpecialist

06/96 ProjectCompletion Review 6.0 Task Manager PetroleumEngineer ______t FinancialAnalyst 115 Page I of4

AggregateProject (ussmoon)

{Project Elements IBRD ECANs PA's Total Quant Units ______~~ICB Other_ _ _ _ C s ______l. Equtipment & Materiab 3S8.3 9.0 367.3 1.1 Rigs 57.9 57.9 | DrillI.1.1I Rig Purchiase 18.0 18.0 2 wuits 1.1.2 Drill RigEquipment 24.2 24.2 1.1.3 Workover Ris 15.7 . 1.75_ IS units li WellMateriall 52.5 52.5 1.2.1Wfellheads 3.2 3.2 91 units 1.2.2 X-MasTrees 2.9 2.9 80 units 1.2.3 Casing 26.8 26.8 691 km 1.2.4 Tubing 18.3 18.3 2.241 knm 1.2.5 Acssori 1.4 1.4 1.3 Lnfrasucture 63.0 63.0 1.3.1 LinePipe 50.5 50.5 831 In t 1.3.2Fittings and Valves 6.1 6.1 6.105 units 1.3.3 M e Eaui _ 6,5 6.5 16 unis 1.4 Pumping Equipment 97.3 97.3 I 1.4.1Rod Pumnps 2.6 2.6 174 units 1.4.2 ESP Pumpssc Cable 94.6 94.6 1,129 units 1.4.3 Assoc. PwnP ng Equip. 3 1.5 ProcesmgEquipmenlt 32.0 32.0 I.S.I Eguipment 32.0 32.0 4 units 1.6 EnvironmentalEquipment 12.4 12.4 1.6.1Spill Equipment 6.3 6.3 1.6.2 Labsand Monitoring 4.3 4.3 1.6.3 Pilot Cleanup Equim 1.8 _ 1.8 1.7 Support Equipment 26.4 26.4 1.7.1 OfficeEquipment 11.0 11.0 1.7.2 WorkshopEquip. 13.3 13.3 1.7.3 Camps/Vehicles 2.1 2.1 11 units 1.8 Misellaneous Equipment 16.8 9.0 25.8

2. Commodities 11.4 2.6 14.0 2.1 DrillBits 8.8 8.8 1,800 units 2.2 Chemicals 2.6 2.6 5.2 490 tons

3. Services 95.7 95.7 3.1 WellServices 26.1 26.1 3.2 RigServices 64.7 64.7 3.3 PipeLaying Services 4.9 4.9

4. Consulting 23.0 23.0 4.1 TechnicalAssistance 15.0 15.0 4.2 FieldStudy T.A. 8.0 8.0

S. Local Costs 87.3 87.3 5.1 Crews 23.6 23.6 5.2 Infrastutr 60.1 60:1 5.3 Ena. & Management 3.7 3.7 6. Local Transport 7. Import Duties 53.2 53.2 8. PhysicalCI ies

9. Funaning Costs ______37.6 37.6 ______10. Total 369.6 130.4 -- 178 678.27 CwmulativeEmrntrl Fi 369.6 500.0 500.0

07:32 PM- 06/09/94 116 Pag 2 of4

MODEM=NIARRAANME Megionneftegas (ussmillion)

Proect Elements IRD ECA's PA's ToW Qutty UniTS ICB Other . C n 1. Equipment & Materals 95.8 3.0 98.8 1.1 Rigp 10.1 10.1 l.1.1.1DrillRig Purcase units 1.1.2 DrillRig Equipment 7.4 7A4 1.1.3 Workover Ri 2.7 2.7 2 units 1.2 WellMateials 16.3 16.3 1.2.1 Wellheads 1.0 1.0 40 units 1.2.2 X-MasTrees units 1.2.3 Casing 11.3 11.3 345 km 1.2.4 Tubing 2.8 2.8 344 km 1.2.5 Accessories/Liners 1.2 12la . || 131nfastructe 15.9 15.9 1.3.1 Line Pipe 13.5 13.5 255 km 1.3.2 Finingsand Valves 0.7 0.7 700 units 1.3.3 M eringEinzmet 1.7 1.7 8 units 1.4 Pumping Equipmt 12.2 12.2 1.4.1 RodPumps u 1.4.2 ESP Pumps& Cable 12.2 12.2 151 units 1.4.3 Assoc. Pumping Eauip. I 1.5 ProcEing Eqipment 32.0 32.0 1.5.1 Eaui=met 32.0 32.0 4 units 1.6 Envhvme4.01r_ gu 4.0 1.6.1 Spill Equipment 1.9 1.9 1.6.2 Labs and Monhoriag I's 1.8 1.6.3 Pilot Cleanup Equimnnt 0.4 _ 0.4 - 11 1.7 SupportEquipment 2.6 2.6 1.7.1 Ofrice Equipment 1.0 1.0 1.7.2 Constr/Worksop Equip, 1.6 1.6| 2un 1.7.3 Caunps/Vehicies units 1.8 _e_M_ aneou_s E_i_ ment 2.7 3.0 5.7

2 . Co nmodies 6.6 1.2 7.7 2.1 DrillBits 5.4 5.4 1,160 units 2.2 Chemicals 1.2 1.2 1 2.3 220 tons

. Services 37.0 37.0 3.1 WellServices 2.9 2.9 3.2 Rig Services 29.7 29.7 3.3 Pipe Lavint Services 4.4 4.4

ConswltIng 6.4 6.4 4.1 TewhnicalAssistance 4.4 4.4 4.2 Field Study T.A. 2.0 2.0

S. Loca Costs 19.5 19.5 5.1 Crews 6.6 6.6 5.2 Infasrucue 11.6 11.C 5.3 Eng. & Manamem 1.2 1.2 Local Tranport . Import Duties 15.0 15.0 8. PbysicalCondngees 9. Fancig Costs 11.6 11.6 10. TOtal 102.4 47.6 46.1 196.1 CumudativExtemal Fwn 102.4 150.0 150.0.

07.32 PM - 06f09/94 117 Ann"z6.M Pap 3 of 4

rRQ AGEMENLAGEEME Tomskneft (ussmilion)

pjea ElemenLs IBRD ECA's PA's Total Qu-amit- Uni ICB Other _ Cost 1. Equpment & Materials 125.2 3.0 1282 1.1 Rigs 11.2 11.2 1.1.1 Dril Rig Purchs units 1.1.2 Drill RigEquipment 8.2 8.2 1.1.3 Workover Rio 3.0 _ __ _ 3.0 3 undu 1.2 Wel Matwiuls 9.8 9.8 1.2.1 Wdlheads 0.7 0.7 11 ilts 1.2.2 X-MasTrees 1.1 1.1 30 unis 1.2.3 Casing 1.4 1.4 36 kIn 1.2.4 Tubing 6.5 6.5 790 kn 1.2.5 Acussories/Liners 0.2 _ 1_ 0.2 I 13 1nfrst-cture 43.8 43.8 1.3.1 Line Pipe 37.0 37.0 576 bln 1.3.2 Fittingsand Valves 4.0 4.0 3.955 unls 1.3.3 MateringEauipme 2.9 2.9 S unts 1.4PumpingEquipment 35.1 35.1 .1.4.1Rod Pumps 2.6 2.6 174 units 1.4.2 ESP Pumps& Cable 32.5 32.5 362 wnits 1.4.3 Assoc.Punwing EquiP. 1.5 ProcessngEquipmen 1.5.1 Euinmenm_ units 1.6 EnvironmentalEquIpmt 4.5 4.5 1.6.1 SpillEquipmen 2.2 2.2 1.6.2 Labsand Montoring 1.7 1.7 1.6.3 Pilot C1anup Ecuim=t 0.7 0.7 1.7 Support Eqidpment 13.6 13.6 1.7.1 OfficeEquipment 5.0 5.0 1.7.2 WorkshopEquip. 8.0 8.0 units 1.7.3 CanmumVelides 0.6 0.6 3 uits 1.8 MgsceflaneousEquipment 7.2 3.0 10.2

. Commodides 1.7 1.7 2.1 DrillBits I.7 1.7 360 unks 2.2 Chemicals Itns

. Services 21.6 21.6 3.1 WellServices 8.6 8.6 3.2 RigServices 12.5 12.5 3.3 Pipe Layint Services 0.5 0.5

Consulting 8.5 8.5 4.1 Technical Assistance 5.5 S.S 4.2 Field Studv T.A. 3.0 3.0

.Lcal Costs 35.4 35.4 5.1 Crews 8.6 8.6 5.2 Infrastuctu 25.5 25.5 S.3 Enm. & Manautement 1.2 1.2

. Lcal Transport . Import Duties 17.9 17.9 8. PhysicalContingencies . Fiancing Costs 11.7 11.7 10. Total 126.9 33.1 225.0 Cmwnlatl E a Fanin 126.9 160.0 160.0

07:32PM - 06109194 118 Aun.zki@ Page 4 of 4

RUSStIASEC= Q__EA=l=PQC E%lCIARRMNEAR Yuganskneftegas (Ussmilio)

ProjectElements IBRD-- ECA's PA's Total Quandity Units .______. CD -erCost _- 1. Equipnmeat& Materials 137.3 3.0 140.3 1.1 Rip 36.7 36.7 1.1.1 DrillRig Purchase 18.0 18.0 2 units 1.1.2 DrillRig Equipment 8.7 8.7 1.1.3WorkoverRfs 10.0 10.0I 10 units 1.2 Wel Materials 26.4 26.4 I 1.2.1 Wellheads 1.6 1.6 40 units 1.2.2 X-MasTrees 1.8 1.8 50 units 1.2.3 Casing 14.1 14.1 310 Icn 1.2.4 Tubing 9.0 9.0 1,107 klm 1.2.5 Accessories/Liners 13 1nrsrtn 3.4 3.4 1.3.1 Line Pipe Ian 1.3.2 Fittingsand Valves 1.5 1.5 1,450 units 1.3.3 MaterirhuEquipnle _ 1.9 1.91.9 3 unih 1A4Purgpiqglpment 49.9 49.9 1.4.1 RodPumps Iunits 1.4.2 ESP Pumps& Cable 49.9 49.9 616 wnits 1.4.3 Asso. jUmpingEguip.__ __ 1.5Prcsig EquiipmentI I.S.1 E_uipme__ . units 1.6 EnvironmentalEquipment 3.9 3.9 1.6.1 SPillEqipenlem 2.3 2.3 1.6.2 Lals andMonitoring 0.9 0.9 1.6.3 PilotCleanup E4uimin 0.7 0.7 1.7 Sul,pportEquipmenlt 10.2 10.2 1.7.1 OfficeEquipment 5.0 5.0 1.7.2 WorkshopEquip. 3.7 3.7 units 1.7.3 CampslVehicles 1.5 1.5 8 units 1.8 Milaneous Eouipment 6.9 3.0 9.9

2. Commodities 3.1 1.4 45 2.1 DrillBits 1.7 1.7 280 units 2.2 Chemiials 1.4 1.4 2.9 270 tons

3. Services 37.0 37.0 3.1 WellServices 14.5 14.5 3.2 Rig Services 22.5 22.5 3.3 PioeLaying Services _

4. COnSUI"ng 8.1 8.1 4.1 TechnicalAssiste 5.1 5.1 4.2 FieldStudy T.A. 3.0 3.0

S. Leoal COStS 32.5 32.5 5.1 Crews 8.4 8:4 5.2 l easructur 22.9 22.9 5.3 Ent.& Muaenent 1.2 1.2

6.L#al Transport 7.ImportDuties 20.2 20.2 PhysicalContingencies 9. Fmancing Costs _ _ 14.4 14.4 10. Total 140.4 49.6 9 67.1 257.1 CumulativeExternal Financin* 140.4 190.0 190.0

07:32PM - OC/09/94 119

Annex 6-1Q Page 1 of 15 RUSSIA SECOND OIL REHABILITATION PROJECT ENVIRONMENTAL ASSESSMENT SU ARY

I. OVERVIEW

1. Despite a very well developed body of environmental protection legislationin Russia, there has been, until recently, relatively little concern for the environmental impacts of oil development and poor enforcement of this legislation. This has been due to a lack of financial support and access to up-to-date equipment and services available internationally in the oil and gas industry, as well as an overriding emphasis in the past on meeting gross production goals to support industrial investment.

2. Historic oil and gas activities in Western Siberia have had a very serious impact on all aspects of the regional ecology (land, forests, rivers, wetlands, groundwater, soil, air). Moreover, pollution migrating from the region via waterwaysand atmosphericdeposition pose serious problems for other regions.

3. Past and present oil and gas operations in the oil fields within the scope of this Project have significantly affected air quality, soil quality, water quality, ecological resources, and national minorities in the immediate area of these operations. The development of the associated infrastructure (cities, towns, utilities, transportation)has displaced and significantlychanged the life styles of national minorities and displaced fauna and flora.

4. Oil and gas production operations have released contaLminantsto the environment. Releases to the air include incompletecombustion contaminants due to poor flare design and burning of oil in pits and spill areas. Venting and fugitive emissions have released hydrocarbon gases to the atmosphere. Part of oil spilled simply evaporates, adding to the air pollution.

5. The proposed Project will generally result in improvements to the environment through actions which will prevent future releases of contaminantsto the environment. The proposed Project is limited to existing oilfields and should not result in incremental negative impacts with the exception of some increase in flaring of associated gas due to greater oil production. The Project also presents an ideal opportunityto begin the process of reversing past damage and to initiate better control of the myriad of environmentalproblems facing the Producer Associations. The Project will provide significant equipment, materials, services and training to assist the Production Associations to plan and execute future remediation projects to improve environmental conditions.

6. Environmental conditions in the oil and gas production operations of Western Siberia will require many projects of this type. It will also take time to reverse the trend of enviromnental degradation and attain realistic objectives for repairing past and present practices. As it is, the initiatives of this Project will only cover a relatively small part of the territory of Western Siberia. But it is important to see it as the start of a much larger effort at improvement. Initiating these improvements can have a dynamic impact on the solving of environmentalproblems elsewhere, and point the way for other programs in the region, thus multip!yina the initial effects. 120

Annex 6-10 Page 2 of 15

H. ENVIRONMENTAL LEGISLATION AND IMPACT ASSESSMENT IN RUSSIA

A. Environmental Legislation in the Russian Federation

7. The politicaland legislativebasis of new Russianenvironmental legislation is the Constitution of the Russian Federation and Constitutions of Republics that are part of Russian Federation. Development of environmental legislation in Russia is done in three ways:

(a) Developing modern environmental legislation, taking into account the required payments for natural resources on the basis of existing complex regulations; (b) Integration of environmental considerations in the existing natural resources and environmental protection legislation; and (c) Integration of environmentalconsiderations in economical, financial, administrative, state, civil, criminal and other branches of legislation.

8. Proprietorship, use and disposal of land, water, mineral and other natural resources, are regulated by the basic legislation, codes, laws of the Russian Federation, legislation of Republics, legal acts of autonomous provinces (Oblasts) and autonomous districts (Okrugs) that are part of the Russian Federation.

9. On the federal level the main legislative acts in this field are:

(a) Law on EnviromnentalProtection (1991); (b) Main Principles of Forest Legislation (1993); (c) Land Code (1991); (d) Water Code (1972); (e) Law on Mineral Resources (1993); and (f) Law on Atmospheric Air Protection, Protection and Use of Animal Resources (1982).

10. About fifteen new legislativeand non-legislativeacts of environmental regulation are being developed at the federal level. These laws will protect certain natural areas, institute land use legislation, regulate the use of flora and fauna, and integrate the criminal code and environmental protection laws.

11. In spite of the progress in creation of environmental legislation, the efficiency of legal regulation of environmentalprotection and use of natural resources is rather slow. There is a large gap between the ecological regulations and practical use of ecological legislative acts, especially in the sphere of economical activitiesof industry, including oil and gas industry, construction, energy and agriculture. The necessity of ensuring practical implementationof enviromnental legislative demands requires improvement of the legal system, improvementof management, administrativeand policy-making activities and increasing enforcement for environmental legislation violations. 121

Annex 6-10 Page 3 of 15

B. Environmental Protection Authorities in the Russian Federation

12. State policy on environmental protection and executive agencies to irnplement them was the exclusive responsibility of the Supreme Soviet of the Russian Federation, disbanded by the President's Decree in September 1993. A specialcommittee of environmentalprotection and rational use of natural resources acted as one of the Supreme Soviet bodies. Now it is supposed that these functions would be passed to Federal Assembly. Election of its members in the Khanty-Mansiysk Okrug will be conducted in April 1994.

13. The Russian Federation Government conducts the state environmental policy, drafts and implements state environmental programs and plans, coordinates the activities of ministries and agencies in the Russian Federation for environmentalprotection. The authority of the Government also includes the establishment of procedures for development and approval of environmental standards for emissions and discharges of pollutants into the environment as well as procedures for setting fees and maximum fee amounts for use of natural resources, environmentalpollution, waste storage and other types of harmful activity.

14. The Russian Federation Ministry of the Protection of Environment and Natural Resources (MPENR) is a duly authorized State organ in the area of environmentalprotection. The Ministry's functions include:

(a) Comprehensive managementin the area of environmentalprotection in Russia; (b) State control and monitoring of the use and preservation of land, subsoil resources, surface and ground waters, the atmosphere, forests and other natural resources, and monitoring the compliance with ecological safety standards; (c) General organization and coordinationof environmental monitoring and control; (d) Approval of standards and regulations, participation in the development of standards regulating natural resources use and protection of the environrnent; (e) Conducting state environmentalreviews; (f) Issuing licenses for the burial (or storage) of industrial and household wastes, emissions and discharges of pollutants into the environment; (g) Restriction or suspension of activities by enterprises that operate in violation of environmental protection legislationor licenses for the use of natural resources or in excess of limits on pollutant emissions and discharges; and (h) Lawsuits demanding compensationfor damages incurred as a result of violations of environmental protection legislation.

15. Functions of specially authorized agencies of the Russian Federation in the area of environmental protection on the federal level, in the constituent republics, autonomous Okrugs and territorial units (Krays and Oblasts) are determined in the "Law on Environmental Protection", adopted 19 December, 1991. The central link in the environmentalprotection structurein Russia and the main analytical and coordinating organ in the region is the territorial (republics within the Federal government, Kray, Oblast, or Okrug) Committeeof the Ministry of EnvironmentalProtection which normally has the following main divisions (departments): 122

Annex 6-10 Page 4 of 15 (a) Economicregulation of environmentalprotection. (b) Stateenvironmental review; (c) Analyticallaboratories and logisticssupport; (d) Stateenvironmental control and monitoring;and (e) Mappingof naturalresources areas.

16. Independentmunicipal and regionalcommittees for environmentalprotection have been organizedin the cities of Oblast and Kray level. Their functionsare coordinatedbetween local authoritiesand territorialenviromnental protection committees. In someregions there are also inter- Regional inspectionsand committeeswhich coordinateenvironmental protection and monitoring activity in several regions. Territorial (Kray and Oblast) Committeesfor the protection of enviromnentand naturalresources have authorityfor the following:

(a) Recordingand assessmentof naturalresources, record keepingof environmentally harmfulsites and enterprises; (b) Recordingand assessmentof the volumeof wastesproduced during productionand consumptionby enterpriseswithin their regions; (c) Coordinationof environmentalprotection activity by local authorities,enterprises, institutionsand organizations; (d) State environmentalmonitoring and decision making in regard to restriction, suspension or terminationof operations of facilities which do not meet the enviromnentalprotection legislation; (e) Conductingthe environmentalreview of the projectsimplemented in their territory; (f) Bans on constructionof environmentallyharmful facilities; and (g) Issuingof permitsgranting the right to use the environmentand its resources,to emit or dischargeharmful substances, or to store wastes.

17. Local self-governmentauthorities on the region level conductthe followingactivities in environmentalprotection:

(a) Recordingand assessmentof the current state of the environmentin the areas under their protection; (b) Arrangementof environmentalreview and state environmentalcontrol; (c) Recordingand assessmentof the volumeof productionwastes at facilitieslocated in their territories; (d) Issuing of licensesfor certain types of natural resourcesuse, for emissionsand dischargesof harmfulsubstances and for the burialof toxic wastes;and (e) Decisionmaking in regard to restriction,suspension or terminationof environmen- tally harmfulactivities.

C. EnvironmentalDepartments in Industry

18. Environmentaldepartments are often found in industrialenterprises whose activitiesare connectedwith the use and consumptionof natural resourcesand which affect the enviromment. Their main fimctionsinclude: 123

Annex 6-10 Page 5 of 15 (a) Verification of compliance of the enterprise activity with plans and measures for environmental protection and rational use of natural resources, (b) Ensuring the compliance with environmental quality stndards, compliance with the requirements of environmnentalprotection and orders and instructions of environ- mental protection authorities; (c) Environrmentalmonitoring and observation of the emissions, discharges and wastes produced at the enterprises; and (d) Collecting, analyzing and updating of data and information of the enterprise activity in the area of natural resources consumption and environmental pollution.

D. State Environmental Review

19. State Environmental Review (Gosudarstvennayaecologicheskaya expertiza) in Russia must be conducted before any economic decision is made that may have an adverse impact on the environ- ment. Financing and performance of work related to all prcjects on the territory of the Russian Federation is permitted only after obtaining a positive statement from the environmental review authorities of the Russian MPENR.

The State Environmental Review consists of the following stages:

(a) Preliminary coordination of future activity; (b) Review of project site evaluation, documentation, and coordination of conditions for the use of natural resources; and (c) Comprehensive review of feasibility studies and issuing the permit for the use of natural resources.

20. The enviromnentalreview is usually conductedby a specially organized interdisciplinaryteam of specialists from scientific and academic institutes, universities, officials from governmental ministries and agencies and representativesof the public. One can appeal to the court o- court of arbitration against the conclusions of the expert commission.

21. On the Federal level the Main State Environmental Review Board (Department) of the MPENR examines the documentationand conducts the review of feasibility studies and projects for construction, reconstruction of enterprises and facilitiesof federal importance (e.g., main oil and gas pipelines, railways, power and nuclear fuel cycle installaions, defence industry facilities, etc.); and feasibility studies and projects of the enterprises with foreign investmentand other projects for which implementationcan affect the environmentof two or more republics within the Russian Federation, Krays, Oblasts, autonomous regions and bordering states.

22. The State environmental review of projects at the Republican, Kray, Oblast or local level is conducted by the review units of the appropriate Committee for environmentalprotection. Projects of local significance are those which are financed from local budgets or have limited influence on the environment of the specific territory. 124

Annex 6-10 Page 6 of 15 E. Environmental Regulations for Oil Production

23. Regulation for the design and evaluation of industrial activities must also address enviroamental iinpacts (OVOS). This act is described in the Handbook on Project Definition under the "Environmental Protection" section for SNiP 1.02.01-85, which is still in force in the Russian Federation. In addition to this Handbook, OVOS for the oil industry must be determined by methods recommended by Minnefteprom of the Russian Federation in 1991-1992. According to these documents, OVOS (environmentalimpact assessment)must be conductednot only for the developing areas but for the ecology of the adjoining regions as well (cross-boundary problems). Means to mitigate or prevent negative consequences in the short-term and long-term perspectives must be determined. The oil and gas industry OVOS also includes additional investigationsconcerning the social consequences, complex environmental impacts, analysis of environmental cleanup and spill response measures, estimation of risks and order of magnitude and ecological and economical evaluation of enterprise activities. In general, OVOS corresponds to international standards.

24. Regulationsof Minpriroda (Ministry of EnviromnentalProtection) of the Russian Federation state that the OVOS is to be included in all projects of oil field facilitiesconstruction as a part of the environmental protectionsection. Moreover, registrationof new enterprises or joint-stock companies must submit data on the technical characteristics of the project and the environmental impacts (a "mini-OVOS") for State environmental review. During the evaluation of oil and gas facility environmental impacts, the maximum permissible criteria of different pollutants' influence on the environment must be taken into account. If approved, environmentalcertificates are issued which describe the current environmental situation and identify the necessary environmental actions for all projects according to the common federal standard.

F. Monitoring of the Environment

25. Monitoring of the state of the environment in Russia for pollution levels is performed both by institutionsof State environmental control and sometimeson the local level by special departments of the enterprises. The activity of all State institutions is coordinated by the Minpriroda of Russia, which is responsible for the common principles of the system of environmental monitoring, functioning, collection and generalizaton of information(on all levels, including each oblast) from all areas of activity, and providing the informationto the administrative institutions, enterprises and public. Enterprises can operate under individualagreements with state institutions regarding baseline information collected in the area of influence of their operations.

26. The Departments of Minpriroda of Russia provide to the public data on the emissions and discharges by the enterprises, and observations of nature reserves. They also monitor and coordinate the reports of nature protection activities of the enterprises which are granted to the statistical institutions.

G. Administrative Penalties for Noncompliance

27. On January 1, 1993, the Govermmentof the Russian Federation ordered fees for permitted environmental pollution, waste disposal, and other kinds of hazardous impacts. In accordance with 125

Annex 6-1Q Page 7 of 15 this Order two kinds of basic fee standards have been established:

(a) Emissions and discharges of pollutants, waste disposal, and other kinds of hazardous impacts within the limits of permissible standards; and (b) Emissions and discharges of pollutants, waste disposal, and other kinds of hazardous impacts within the temporarily coordinated standards.

28. Basic fee standards are established for each pollutant according to the degree of hazard to the environment and public health.

29. For some regions and river basins, special coefficients for the basic fee standards are estab- lished. These factors take into account the ecological factors, natural and climatic features of the territory, and the significance of natural and social-cultural resources. The coefficients in Tomsk Oblast range from 1.02 to 1.04, and in Tyumen Oblast from 1.02 to 1.05.

30. Enterprises have a powerful incentive to maintain pollutant discharges within the standards. The fees for maximum permissible emissions, equivalent to a discharge permit fee, for discharge of pollutants and waste disposal are charged at the expense of prime cost of production. Payments for exceeding permissible levels are charged at the expense of profits to the enterprise. The maximum fine for environmental pollution in excess of the maximum permissible standards is set as a percentage of the profits remaining at the associations.

31. The oil producing associations pay fees for waste storage in mud settling pits in accordance with the class of hazard for burying substances maximum permissible emissions and discharges. Penalties for accidental discharges and emissions are also charged.

32. Negotiation does take place between environmental controlling bodies and industrial enterprises over the legal basis of penalties, and in some cases the enterprises can pay reduced amounts for environmental pollution, especially if they take prompt action to localize and mitigate pollution impacts. However, payments for environmental pollution do not release the Associations from implementingenvironmental protection and rational use of natural resources. Associations are still liable for damage caused to the environment, health and property of citizens, and economic resources by environmentalpollution in accordance with current law. m. ENVIRONMENTALCONDITIONS IN WEST SIBERIAAND THE PROJECT AREA

33. Environmental concerns associated with oil drilling and production in the Western Siberia region are significant because of the fragile environment, the predominance of wetlands and the historic lack of concern for the environment. Moreover, poor drainage, large distances and the harsh climate make it a very difficult area to operate in. Without a firm commitment from the Producer Associations to properly implement mitigation activities and to carry out effective and systematic monitoring of environmental and social problems at every stage of oil production and distnrbution, severe environmental impacts will result. Some of the key Environmental issues 126

Annex 6-10 Page 8 of 15 associated with the oil production in Western Siberia and the proposed Project are discussed below.

34. SilUs and Leaks: Most of the pipeline spills in Western Siberia are occurring in the gathering systems which carry liquid consisting of a mixture of oil, water and gas. This mixture is moved long distances from the wells to the primary and secondary separating facilities. After separating oil and gas, the highly corrosive water, often without corrosion inhibitors, is recycled to the production wells. The recycled water contains bacteria, chlorides, hydrogen sulfide and other chemicals which are causing extensive damage to the carbon steel pipes. Pipes are being replaced frequently (every two to three years). The number of leaks in the gathering pipes are alarmingly high, with several thousand leaks reported every year. Spills and leaks contribute to the contamination of surface and ground water throughout the oil producing region. A suitable material for construction of gathering pipelinesand proper construction and operatingpractices must be found to minimize the problems of spills and leaks. The Project feasibility studies examined the technical, environmental and economic aspects of alternate construction materials and operating strategies for surface facilities. Particular issues included:

(a) ConstructionMaterials: Potential materials which couiclsuitably be used in the highly corrosive environment in Western Siberia include: fiberglass, titanium, carbon steel with titanium cladding, cast iron, carbon steel with internal lining and other materials. The most promising materials from a technical and environmental view point were found to be fiberglass and internally coated steel pipe. The cost of titanium pipe was found to be prohibitively high.

Co) Corrosion Protection: Internal corrosion of pipelines is extensive throughout the oil/water circuladng lines. External corrosion is also occurring in underground pipelines due to a lack of adequate cathodic protection. There is a need for pipeline operators to carry out internal pitting surveys to determine the extent of corrosion in the pipelines as well as periodic measurement of impressed current. Investigation is required to determine suitable corrosion inhibitors and bacterial chemical treatment to minimize corrosion. Use of aeration units could also help in reducing bacterial formation. The proposed Project includes studies of optimal means for corrosion protection.

(c) Design and Constructon: A large number of leaks are occurring not only because of poor materials of construction but also due to improper design and construction of the pipelines. Many pipelines are not supported properly and several are damaged by heavy construction and drilling equipment. A significant number of these pipelines are floating above water without any support, causing considerable damage. If permafrost is present special precautions such as proper line insulation will be required. It is important that design and construction of the pipelines be thoroughly investigated to determine the optimal strategies for operation in the harsh environment of Western Siberia. A design/build contract will be utilized for pipeline replacement in Megionneftegasto generate alternate designs.

(d) Lavout: At present, there are a few primary separator facilities and only one or two 127

Annex 6-10 Page 9 of 15 secondary separator facilities to recover oil from a mixture of oil, gas and water. These facilities are located several miles from the oil wells. Millions of gallons of corrosive water, mixed with oil and gas, are recirculated daily through carbon steel pipes to the separating facilities located far from the oil production facilities. Rationalizationof the overall system is required to reduce the length of recirculating water pipes and thereby minimize leakage throughout the region. These issues will be investigated under the Field Optimizationstudies but should also be addressed in a preliminary manner during the feasibility studies for linepipe reconstruction.

(e) Automation: Automationof separators and oil field facilities is important to mnimize operating problems and emergency shut-off in the event of accidents. Automation will also improve production rates.

35. Minimization of Well Pad Extensions and Roadways: In the proposed Project, the oil production activities are already well established, therefore, the nature of any unique environmental concerns are usually well known and appropriate operating procedures established. Nonetheless, particular attention should be focused on minimizing gravel pad extensions and new roadway development and maximizinguse of existingwells, roads, and facilities in order to avoid further loss of wildlife habitat. The use of horizontal wells in the Project will minimize the need for new well pads as these wells can be drilled from existing pads.

36. Sand Dredging: Sand is used for road beds, well-pads and oil spill management. The sand is normally dredged from large water bodies, especially along river banks. This practice has disrupted fish breeding and increased the amount of suspended solids in water. According to the Ministry of Environmental Protection, dredging is prohibited in most areas except those which are specially designated for this purpose, so that the fish breeding will not be disturbed.

37. Air Pollution: A large share of the gas associated with oil production in Russia is burnt in large flare pits. This large scale flaring releases a significant amount of greenhouse gases and particulate matters to the atmosphere. Oil pipeline accidents also contribute to air pollution because the oil spill and leaks have historically been burned, producing significant amounts of harmful emissions. These releases create health and safety concerns to the local and regional population, contribute to the reduction of vegetation, forests and other natural resources, and contribute to global warming. Due to the extreme cold climate, thermal plumes from open pit flaring may not rise high enough to be dispersed quickly into the atmosphere. Acid gases (sulfur and nitrogen oxides) could remain at the ground level producing harmful acids (sulfurous, sulfuric, nitrous and nitric acid) when in contact with water. These acids are precipitated in the form of acid rain causing significant damage to the enviromnent. This problem can be partly overcome by appropriate flare system design. Gas flaring is a major concern in only one of the PA's in the Project, Tomskneft. The other PA's have lower gas content or already dispose of approximately90% of associated gas to the gas network. One of the Project components in Tomskneft is a study to determine alternate uses for associated gas and improved flare design. Air emissions from discrete sources in the three Associations during 1992 is given in the Table below. 128

Annex 6-10 Page 10 of 15

Table 1 Air Emissions from Discrete Sources in 1992 (Metric Tona per year) Production Association Polutant Megionneftegas Yuganskneftegas Tomskneft Sulphurous anhydride 288 726 200 Carbon monoxide 10,963 15,919 128,110 Nitrogen oxides 489 1,072 1,917 Hydrocarbons 23,919 183,027 49,671 Particulate matter 332 1,962 5,426

38. In addition to air pollution from discrete sources, volatile organic compounds enter the atmosphere from valves, regulators and flanges on pressure-raising pump stations of oil wells, gas well testers, and separators on group measuring devices. No estimates on fugitive emissions of volatile organic compounds is available. Evaporation losses occur from areas where oil is open to the atmosphere, which includesoil-water separators, storage areas, transfer points, pumps, and spills.

39. Water Pollution: The proposed Project will cause a net decrease in water pollution. More than half of the oil fields area consists of surface water. Gathering system pipelines routinely cross lakes, rivers, streams, marshes and swamps. Many of the gathering system leaks occur in surface waters. By reducing the number of gathering system leaks by replacing the old pipe with newer and improved pipe, the number of leaks will be significantly reduced in the Producer Associations. The reduction of pipeline accidents in these Associationsdue to replacement of linepipe is estimated to reduce oil spilled by approximately 0.9 million tons per year. Further, the environmental study components of the project will be used to improve well site techniques, cleanup capabilities, remediation and monitoring so that oil releases into the environment are better controlled and minimized.

40. hnproved well site technology envisioned by the Project should also include improved waste handling technology to contain and process the wastes associated with oil drilling. At present, the Producer Associations would not meet standards for cleaning well site wastes found in the drilling operations in other countries, such as Canada and the United States. Even without new technology, the Associationscould do a better job of cleaning well site wastes just by exercising more care and concern with the fate of these wastes.

41. Effects on Flora and Fauna: Oil field development in taiga and tndra environments is disruptive to wildlife. The well pads, roads, pipelines, heavy vehicles, drilling rigs and noise cause animals to abandon the zones near the oil fields and seek new areas to live. Since neither taiga nor tundra are highly productive in terms of bioniass, there is great competition for what little biomass is produced. Thus, removal of native vegetation for roads, well pads or other infrastructure is 129

Annex 610 Page 11 of 1S detrimental to wildlife. Further, spills which are either buried by sand or burned eliminates wildlife habitat. Often the fires used to clean up oil spills are unattended and the fire goes beyond the spill area. Unlike more temperate zones, the vegetation in Western Siberia does not grow quickly, so replacement of deslroyed vegetation takes a long time.

42. Most of the wildlife within the oil fields of the Producer Associations has already left the areas of intense development. Since the Project will not support drilling in new oil fields, the negative effects on wildlife will not be significant. The negative effects have already occurred and the Project should not add to the existing problems.

43. Some of the damage to wiidlife is caused by illegal hunting by oil field workers. The Project should not cause a significant increase in oil field workers so the level of poaching should remain essentially the same. Managers in the Producer Associations are also becoming increasingly aware of the damage that oil developmenthas caused in these fragile northern environments. Many of the labor force, especially at managementlevels, are beginning to make Western Siberia as a permanent home. If this trend continues, there will be more effort made on preserving or conserving natural resources while producing oil. NGOs, are also playing an inportant role in increasingenvironmental awareness all across Russia, including Western Siberia.

44. Native vegetation is destroyed for access roads and well pads. If the disruption were limited to these areas, the losses could be considered acceptable. However, it is not a common practice in any of the three Producer Associationsto limit transportation to defned access roads or to maintain the access roads to international standards. As a result, vehicle tracks are found all over the oil field and between fields instead of being limitedto one path. If the access road washes away in ont, spot, vehicles just swerve aside widening the destruction rather than repairing the road. Because the vegetation grows so slowly, these vehicle tracks persist for years or decades. As in the case of the mismanagementof the well site sump wastes, simple carelessness is mostly responsible for the poor environmental conditions related to access roads. During the winter when the ground and surface water is fully frozen, it is just too easy to travel cross country rather than limitingvehicle movement to defined routes.

45. Erosion and Revegetation:Uncontrolled water runoff in Western Siberia is the most important cause of erosion. Any new construction should avoid or minimize erosion and disturbance of vegetation. There is a need for erosion control guidelines to protect the pipelines from damage. Continued maintenance of access roads and the work pads is also required to prevent erosion. After performing remediation and cleanup of spills revegetation should be carried out to restore the area to near its original condition. Pilot clean-up programs in the Project will attempt to identify optimal strategies for future clean-up operations in the Associations.

46. Indi2zenousPeople: Although the Project as defned will not increase encroachment in the traditional areas of the approximately 125 indigenous people living near to the Project area, it is important to underscore the damagethat has already been inflicted on indigenous populationsby the oil and gas industry in Western Siberia so as to emphasize the need to be concerned that more damage is not inadvertentlypassed on to these long-suffering project area residents. 130

Annex 6-10 Page 12 of 15 47. The indigenous people of Western Siberia (the Khanty, the Mansi and the Nents) who comprise just under 1 % of the population of the region, have been significantly affected by oil operations over the past three decades. These seasonally migrating people depend completely or to a large degree on renewable natural products from the taiga and tundra ecosystems. Their large domestic reindeer herds require a vast undisturbed grazing area in order to survive. The reindeer depend on lichens that are very sensitive to both air pollution and oil spills and transportation infrastructure. The indigenous people also derive a large amount of protein from fish and other wildlife sources. In addition to nutrition, clothing and housing, the natural products from these sensitive ecosystems also provide important sources of income for the local people. Inflows of foreigners, starting in the 16th century and acceleratingwith oil development in the early 1960s, has also had adverse social effects on the local populationssuch as exposure to new diseases, alcoholism related to predatory trading practices of outsiders, the process of urbanization and the destruction of natural habitats, with the associated declines in the renewable resource base.

48. In the Khanty-MansiiskiiAutonomous District about 100,000 tons of oil and oil products have been spilled over 200,000 hectares of fishing grounds. In the process, 17,700 hectares of fish sp!,wning grounds have been polluted, spoiling 28 spawning rivers. The immense and vitally important Ob' River is badly polluted, with concentrations of some harmful substances being 25 to 30 times in excess of admissible levels. During summer months in the district, over 300 fires per month are commonly recorded. These fires, often caused by flared gas or burning oil spills, destroy woodland and grazing areas of lichens and mosses which are vital to successful reindeer rearing. Over II million hectares of reindeer grazing lands (out of an original 22 million hectares) have been withdrawn in Western Siberia for oil and gas production. Over 17 million hectares of hunting lands have been seriously compromised through oil and gas production. The three Producer Associations are located in the traditional hunting and fishing areas.

49. These losses have dealt a severe blow to the indigenous economy. Reindeer herds of over one thousand individualshave been reduced below 100 survivors. Fish catches have been seriously reduced and wildlife has disappeared from a large part of the region. Compensationfor these losses is irregular and questionable when it occurs, often in the form of providing low quality housing, snowmobiles, schools and medical facilities. The oil and gas industry has not seen it necessary to offer employment to local people as a form of compensation. In short, the indigenous people have borne severe economic penalties while the benefits have accrued to distant urban populations.

50. To some degree, the Producer Associationsrecognize the needs of the indigenouspopulations and attempt to assist in meeting those needs. Unfortunately, their investment programs aimed at indigenous people are unfocussed and have had little long term positive im 'acts. Nonetheless, communication between the Associationsand the indigenous populations is not unidirectional. The local populations are not hesitant to make their views clear to the managementof the Associations and to local govermnent but the net result has been limited. The political power of the indigenous populationshas been increasing as a result of international,national and regional meetings concerning the rights of indigenouspeoples and may increasefurther through new legisLation.Local NGOs bave also begun to articulate the special needs of indigenouspeoples. In April 1992, Presidential Decree N397 was signed which placed particular emphasis on protection of the rights and interests of national minorities of the North in order to preserve and develop their traditional forms of living, 131

Annex6-10 Page 13 of 15 as well as to ensure enviromnentalsafety in the areas of industrialdevelopment. Indigenous communitiesare being granted a preferential right to obtain licenses to use natural resources in the places of their traditional activities (approximately50% of the land in the region) although they do not possess formal documents defining these boundaries and in the autonomous regions the question of ownership has not been fully resolved. The indigenouspeople have also been granted preferential access to a portion of the shares of the oil companies to be privatized, but the means are yet to be established.

51. It is clear that the past, present and future well-being of the Khanty and Mansi peoples are intimately intertwined with development of the oil sector. The past is a sad and sorrowful tale of exploitation. The present shows some important improvements with the creation of exclusive traditional grazing and hunting areas and an increased sensitivity to the needs of indigenous people. New and protective legislation is expected to provide the indigenous people with more protection if the legislation is adopted and enforced. The future will show even greater improvement if the Producer Associations take a more active role in assisting in the economic development of the indigenouspopulations. A mitigationplan has been prepared to give greater protection to the natural resources so necessary in the traditional economy. The Project can not be expected to atone for all the past impositions that the industry has inflicted on indigenous populations, but a serious effort must be made to ensure that no further damage occurs to further jeopardize the livelihood of the local people. It is also vital that the Producer Associationsmake greater effort to seek the counsel of the people which are most directly affected by oil field activities and employ people who are sensitive to tribal cultures and economies. The Project will include technical assistance (approximately 4 person-months of an international specialist and 8 person-months of local experts) to support the Associations in developing and implementing programs to safeguard the interests of indigenous people in the region. In addition, a proposed EU funded program is under consideration to help develop a regional action plan for improving the living conditions of national minorities.

IV. ENVIRONMENTAL MITIGATION, MONITORING AND EMERGENCY RESPONSE

52. The proposed Project includes a number of operational measures to reduce the impact of drilling and production activities on the environment. In addition, a significant program of direct technical assistance, training and equipment provision is planned to improve environmental management and mitigation capabilities in each Association. One element of these programs will development of comprehensive Emergency Response plans to deal with oil spills, fires and other emergencies associatedwith oil production and transmissionincluding provision of proper equipment and personnel training. Air, water and oil monitoring programs around the oil fields, water recirculating lines and separators facilities will be developed through training and equipment provision. Studies will be undertaken and programs developedto minimizeoil spills, notably through reducing the incidence of pipeline corrosion. Finally, pilot clean-up programs will be undertaken to identify opfimal strategies for future cleanup of past oil spills, which, across in Western Siberia, will be a major task likely requiring hundreds of millions of dollars. The environmental management program is oudined below and the estimated cost of each component summarized in Table 2. 132

Annex 6-10 Page 14 of 15

(a) Environmental Cleanup and Emergency Spill Response (i) development of emergency response plans and provision of environmental cleanup and spill response equipment and training to respond to crude oil releases on land and water and to clean up mud pits and soils.

(b) EnvironmentalMonitoring (i) installation of field sampling and monitoring equipment and stationary and mobile (truck-mounted) laboratory analysis equipment to monitor environmentalimpacts and undertake environmentalanalyses; (ii) development of operations manuals for use of the equipment; and (iiii) baseline studies of fields covered under the Project and establishment of geographical information system database.

(c) Spill and Pipeline Corrosion Prevention (i) provision of mobile laboratory for corrosion assessment and undertaking of a program of internal corrosion sampling and analysis including material samples, produced water samples and produced gas samples; (ii) studies to determineoptimal corrosion inhibitors,corrosion-resistant materials and liners; and (iii) assessment of optimal field design to mininize lines exposed to corrosion from formation waters.

(d) Pilot Clean-up and Mitigation Programs (i) implementationof pilot clean-up programs to identify optimal techniques for remediation and revegetationunder local conditions; (ii) assessment of alternate types of gas flare design and installation of experimentalflare systems (Tomskneft and Yuganskneftegas);and (iii) study of alternateuses for low pressure associated gas including thermal soil remediation units.

(e) Environmental ManagementPlanning. Development and Training (i) development of environmental management and training plans according to commonly accepted Russian and international standards for environmental management; (ii) technical assistance to support development of programs to safeguards the interests of indigenous peoples in the region; and (iii) training in environmental management at the Production Association and NGDU level. 133 Ann-x 0-1i0 Page 15 of 15

Table 2: Costsof ProposedEnvironmental Protection Programs (US$ thousands) Category Yugansk- Tomskneft Megion- Total neftegas neftegas EnvironmentalCleanup and Spill ResponseEquipment & Training 2,150 2,450 2,400 7,000 Monitoring, Lab Analysisand Training ChemicalLaboratory 300 650 500 1,450 Mobile Laboratory __- 600 300 900 BaselineData / GIS 200 170 150 520 Total Monitoring 500 1,425 950 2,870

Corrosion Inhibition 400 - 0 - - 0 - 400 Corrosion Laboratory 500 300 400 1,200 Total Spill Prevention& 900 300 400 1,600 Monitoring Pilot Program Remediation/Revegetation 800 800 800 2,400 Flare Assessment 200 70 -0- 270 Total Pilot Program 1,000 870 800 2,670

EnvironmentalManagement and Training Plan 200 200 200 600

MiscelLaneous _ _._._-_-_ _ _ ProgramManagement 170 170 170 510 Translation 80 80 80 240

Total Miscellaneous 250 250 250 750 Total ProjectCost 5,000 5,490 5,000 15,490 134

Annex 7-1 Page I of 6 RUSSIA SECOND) OIL REHABILITATION PROJECT ECONOMIC ANALYSIS

1. The key assumptions used in the economic evaluations are listed below. Pages 3 and 4 summarize the economic results by Association and component while Page 5 summarizes the sensitivity analyses by field. Project cost details are provided on Page 6 and in Annex 6-3 (Project Costs) and Annex 6-7 (Procurement Arrangements).

A. Project Benefits

2. Project net present values are based on a IS % real discount rate.

3. Economic benefits are based on Urals Blend oil prices of $113 per ton ($15.5 per barrel Europe Mediterranean) less port handling and transport costs of $19 per ton (covering 3500 km) from West Siberia to the Black Sea and tanker transport to Europe assumed to total $5 per ton. No real price changes have been included in the base evaluations. Evaluations have been carried out for a range of crude oil prices from $12.5 per barrel to $18.5 per barrel over the life of the Project.

4. Incremental production estimates are based on recent well histories. A 50% productivity improvement has been assumed for wells with less than 10 tons per day production prior to shutdown due to lowering of sub-surfacepumps, recompletionand stimulationservices. Productivity gains for higher yield wells have not been assumed. A 10% failure rate on workovers (incorporated as an average 10% loss of production per well) has been assumed to reflect potential abandonment of complicated operations.

5. Production decline is estimated to be 20% per annum for new wells for the first two years then 10% per annum thereafter with a productive life of 10 years requiring minor workovers ($72,000) every two years.

B. Project Costs

6. Workover times, based on internationalworkover rigs using Russian crews, are estimated to average 10 days over the Project life. Workover rig purchase costs include six months of training and advisory services. Drilling rig costs include foreign advisors throughout the Project life. Two years of an assumed 5 year rig amortization period have been assigned to Project costs.

7. Workovers are generally assumed to require replacement of tubing, pumps and require logging, cementing, perforation and simple stimulation services. Approximately two-thirds of the specializedwell services are assumed to be carried out by the Associationor local contractors. Local well services (cementing, logging, perforation) have been assumed to cost one-third of international prices on average. New horizontal wells require MWD services in addition to those listed above.

8. Workovers are assumed to require some rehabilitation of roads, well pads and power facilities. The total cost of these services and other local costs are estimated to total just over 20% 135

Annex 7-l Page 2 of 6 of the overall workover cost. New wells are assumed to require I km of hard roads and 4 kan of soft roads plus 5 1an of 6 kV power lines for every 4 wells. The local cost component of new wells is estimated to total just under 15% of the total cost.

9. Equipment inspectionand transport costs are estimated to total 12% of equipment costs based on cost estimates from the First Oil Rehabilitation Project and current and proposed projects undertaken by international oil companies.

10. Variable operating costs, in addition to minor workovers, are estimated to average approximately $18 per ton produced based on an assumed 30% real increase in current operating costs over the near term. 136

Page 3 of 6

RUSSIASECOND OIL REHABILITATIONPROJECT ECONOMICEVALUATION (milliontons per annumand millions end 1993$) Total Project

Total 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 1 2 3 4 5 6 7 8 9 10 11 Operations(Year 1) Wells Completed 1137 1137 Oil Production 30.9 2.8 4.8 4.1 3.7 3.3 3.0 2.7 2.4 2.2 2.0 Gross Production 190.8 9.3 17.4 16.5 16.4 16.7 17.3 18.5 20.6 24.6 33.4

Operations(Year 2) Wells Completed 998 998 Oil Production 27.2 2.4 4.2 3.6 3.2 2.9 2.6 2.4 2.1 1.9 1.7 Gross Production 167.5 8.2 15.3 14.5 14.4 14.7 15.2 16.2 18.1 21.6 29.41

Total Production Wells Completed 2134 1137 998 Oil Production 58.1 2.8 7.2 8.3 7.3 6.6 5.9 5.3 4.8 4.3 3.9 1.7 Gross Production 358.3 9.3 25.6 31.8 30.9 31.1 32.0 33.7 36.8 42.7 55.0 29.4

CapitalCosts Rigs 64.6 34.4 30.2 Well Costs 252.9 134.7 118.2 Facilities/ Infrastructure 77.7 41.4 36.3 Services Contract 62.2 33.1 29.1 Services Local 3112 Total Capital Costs 528.1 281.2 246.9

°IOperatiogCosts Workovers(per 2 yrs) 451 56.4 56.4 56.4 56.4 56.4 56.4 56.4 56.4 VariableO&M Gross 932 44A ll I U331 i171 15O 24.29, A 76-2 62.2 62.2 22 Total Operating Costs 1,383 44.4 115.5 189.5 173.6 161.8 151.3 141.8 133.3 125.6 118.7 27.7

EconomicEvaluation Total Costs 1,911 325.6 362.4 189.5 173.6 161.8 151.3 141.8 133.3 125.6 118.7 27.7 TotaoBenefits 5,183 247.2 642.6 740.2 651.6 586.5 527.8 475.0 427.5 384.8 346.3 153.9 Net Benefits 3,272 (78.5 280.2 550.7 478.1 424.6 376.5 333.2 294.3 259.2 227.6 126:2

Net Present Value 1,531 Cil Value SJbbl S/ton Benefit-CostRatio 2.4 Brent $16.5 $120 UTC Total Costs $37 $5.1 ($/barrel) QurI Discount $1.0 $7 UTC Capital Costs $15 $2.0 ($/barrel) Tanker $0.8 $5 Port $0.5 $4 Value of Oil ($/ton) $89 $12.3 ($/barrel) Pipeline $11 DiscountRate (real) 15% Net Welhead $12.3 $89 137 Annex 7_1 Page 4 of 6 RUSSIA SECOND OIL REHABILITATION PROJECT ECONOMIC EVALUATION SUMMARY (milliontons per annum and millions end 1993S) Project Project BIC UTC Opex Prodi. IWorkove In-fill Pipeline Capex Prodn. Prodn. NPV Code Ratio $/ton $/ton Avg. tpd # # km $1Oper. Total Peak $ mn

NW MegionIn-fill 1 2.0 $44 $22 90 4 2.30 0.6 0.1 16 Main Megion In-fill 2 1.8 $48 $20 72 10 2.30 1.3 0.2 27 SE MegionIn-fill 3 2.2 $41 $19 90 8 2.30 1.3 0.2 30 MegionWorkovers 4 2.2 $41 $29 14 38 0.23 1.1 0.2 27 MegionPipeline 5 2.2 $40 $18 3 150 0.08 0.9 0.1 22 Total MegionField 6 2.1 $43 $21 13 5.3 0.8 122 7 PokamasovskoyeIn-fill 8 2.9 $31 $18 84 54 1.32 9.1 1.3 268 PokamovskoyeWorkovers 9 2.6 $34 $24 18 37 0.24 1.5 0.2 40 PokamovskoyePipeline 10 2.0 $45 $17 2 105 0.08 0.5 0.1 10 Total PokamovskoyeField 11 2.8 $32 $19 28 11.0 1.6 318 Total Megion PA 12 2.5 $36 $20 20 16.3 2.3 440 13 Sov. ESPWorkover 14 2.2 $41 $27 14 117 0.26 3.5 0.5 84 Sov. Rod Pump Workover is 1.9 $47 $27 7 58 0.18 0.9 0.1 19 Sov. HorizontalWell 16 2.8 $32 $20 75 4 1.11 0.6 0.1 18 Sov. Pipeline 17 3.1 $29 $17 4 263 0.07 2.3 0.3 71 Total SovietskoyeField 18 2.4 $37 $24 8 7.3 1.0 191 19 Per. ESPWorkover 20 2.2 $40 $27 14 117 0.24 3.5 0.5 851 Per. Rod Pump Workover 21 2.0 $45 $27 7 58 0.16 0.9 0.1 20 Per. HorizontalWell 22 2.5 $3; $20 75 3 1.39 0.4 0.1 13 Per. Pipeline 23 3.1 $_9 $17 5 141 0.08 1.4 0.2 44 Total PervomaiskoyeField 24 2.3 8 $25 9 6.2 0.9 161 25 Vahk. ESP Workover 26 2.2 $40 $27 14 117 0.24 3.5 0.5 85 Vahk. Rod Pump Workover 27 2.0 $46 $27 7 58 0.17 0.9 0.1 20 Vahk. HorizontalWell 28 2.6 $34 $20 75 4 1.25 0.6 0.1 18 Vahk. Pipeline 29 2.5 $36 $17 4 173 0.10 1.5 0.2 41 Total VahkskoyeField 30 2.2 $40 $25 8 6.5 0.9 162 Total TomskneftPA 31 2.3 $39 $24 8 19.9 2.8 514 32 Mam. Workover 33 2.4 $38 $27 14 476 0.20 14.1 2.0 363 Mam. HorizontalWell 34 1.9 $48 $17 45 24 1.55 1.9 0.3 41! Mam. Pipeline 35 0 Total MamantovaField 36 2.3 $39 $25 15 16.0 2.3 404 37 Sre. W/O Fracturing 38 2.7 $33 $21 23 100 0.28 3.7 0.5 106 Sre. HorizontalWell 39 0 Sre. Pipeline 40 0 Total SrednyeAsomkiniskoye F 41 2.7 $33 $21 23 3.7 0.5 106 42 Pri. Workover 43 0 Pri. Horizontal Well 44 2.7 $33 $13 90 16 1.87 2.3 0.3 68 Pri. Pipeline 45 0 TotalPrirazlomnoye Field 46 2.7 $33 $13 90 2.3 0.3 68 Total Yu_nskneft PA 47 2.4 $37 $23 18 21.9 3.2 577 48 otal Pro3ect 49 2.4 $37 $23 13 58.1 8.3 1,531 138 AnnesA Page 5 of 6

RUSSIA SECOND OIL REHABILITATION PROJECT ECONOMIC SENSITIVTY Beefit-Cost Ratios Scenario- Meonnefteps Tom_ ntYtnll Total Me8ion Pokom. Total Sov. Per. Vahk Total Mamo Sre. Pri.

Base Case 1 2.5 2.1 2.8 2.3 2.4 2.3 2.2 2.4 2.3 2.7 2.7 LowOilPrice$13.5/bbl 2 1.9 1.6 2.1 1.7 1.8 1.8 1.7 1.8 1.7 2.0 2.0 Median Oil Price $16.51bbl 3 2.5 2.1 2.8 2.3 2.4 2.3 2.2 2.4 2.3 2.7 2.7 High Oil Price $19.5/bbl 4 3.1 2.6 3.5 2.9 3.0 2.9 2.8 3.0 2.9 3.4 3.4 Capital Costs (Base) 5 2.5 2.1 2.8 2.3 2.4 2.3 2.2 2.4 2.3 2.7 2.7 Capital Costs +25% 6 2.2 1.8 2.5 2.1 2.2 2.1 2.0 2.2 2.1 2.5 2.3 Capital Costs +50% 7 2.0 1.7 2.3 2.0 2.0 2.0 1.9 2.0 1.9 2.3 2.1 Capital Costs +100% 8 1.7 1.4 2.0 1.7 1.7 1.7 1.6 1.7 1.7 2.0 1.7 Operating Costs 9 2.8 2.3 3.1 2.6 2.7 2.7 2.5 2.7 2.6 3.1 2.9 Operating Costs +25% (Base) 10 2.5 2.1 2.8 2.3 2.4 2.3 2.2 2.4 2.3 2.7 2.7 Operating Costs +50% 11 2.2 1.9 2.5 2.1 2.1 2.1 2.0 2.1 2.0 2.4 2.5 Production +0% (Base) 12 2.5 2.1 2.8 2.3 2.4 2.3 2.2 2.4 2.3 2.7 2.7 Production -10% 13 2.4 2.0 2.6 2.2 2.2 2.2 2.1 2.2 2.1 2.5 2.5 Production -25% 14 2.1 1.7 2.4 1.9 2.0 2.0 1.9 2.0 1.9 2.2 2.2 Production-50% 15 1.6 1.3 1.9 1.5 1.5 1.5 1.4 1.5 1.4 1.7 1.6 Production Decline 10% 16 2.5 2.1 2.8 2.3 2.4 2.3 2.2 2.4 2.3 2.7 2.7 ProductionDecline 15% 17 2.4 2.0 2.7 2.2 2.3 2.2 2.1 2.3 2.2 2.6 2.6 ProductionDecline 20% 18 2.3 1.9 2.6 2.1 2.2 2.1 2.0 2.2 2.1 2.5 2.5 139 Annex 7-1 Page 6 of 6

RUSSIASECOND OIL REHABELITATIONPROJECT PROJECT PARAMETERS -_;_-_ I Scheduling Capital Costs per Operation OperatingCosts Project Wells Percent of Total Capex Rig $ Infras Services Workover Opex OpCod& ______j _Yr I Yr2 Cost $ Alloc. Cost$ Local Contrac. CostS $/ton 1,2. TomalProject 49 2134 53% 47%j 118 30 36 33 29 40 12.8

NW Megion In-fill 1! 4i 100% 1349 628 79 52 190 72 $14.7 2 |Main Megion In-fill 21 101 40% 60% 1 1349 628 79 52 190 72 $14.7 2 iSEMegion In-fill 31 81 5% 95% 1349 628 79 52 190 72 $14.7 2 MegionWorkovers 41 381 50% 50% : 151 30 51 3 72 $14.7 1 MegionPipeline Si 150 50% 50% 79 $14.7 3 Total Megion Field 61 210 42% 58% 169 71 65 15 21 21 $14.7 7 PokamasovskoyeIn-fill 8 541 53% 47%l 745 261 74 127 117 72 $13.3 2 PokamovskoyeWorkovers 9 371 50% 50%I 147 31 50 10 72 $13.3 1 PokamovskoyePipeline 10 1051 50% 50%i 80 $13.3 3 Total PokamovskoyeField 11 196| 53% 47%| 233 78 63 44 34 33 $13.3 Total MegionPA 12 406 49% 51% 200 74 64 29 27 27 $13.7 13 , Sov.ESPWorkover 14 1171 50% 50%' 154 8 56 37 72 $13.3 1 Sov.RodPwnpWorkover 15 58: 100% 79 8 56 37 20 $13.3 1 Sov. Horizontal Well 16 41 100% 552 317 76 167 72 $13.3 2 Sov. Pipeline 17 2631 50% 50% 66 $13.3 3 Total SovietskoyeField 18 442 60% 40%1 56 6 40 24 15 22 $13.3 19 Per. ESP Workover 20 117, 50% 50% 143 8 51 37 72 $13.3 1 Per. Rod Pump Workover 21 58 100% 69 8 51 37 20 $13.3 1 Per. Horizontal Well 22 3; 100% 634 515 78 167 72 $13.3 2 Per. Pipeline 23 141; 50% 50% 78 $13.3 3 TotalPervomaiskoyeField 24 319! 61% 39% 71 9 35 29 20 31 $13.3 25 Vahk.ESP Workover 26 1171 50% 50% 146 8 51 371 72 $13.3 1 Vahk.Rod Pump Workover 27 58 100% 71 8 51 371 20 $13.3 1 Vahk. Horizontal Well 28 4 100% 570 434 75 167 72 $13.3 2 Vahk. Pipeline 29 173 50% 50% 105 | $13.3 3 Total Vahkskoye Field 30 352 62% 38% 67 9 52 27 19 28 $13.3 Total Tomskieft PA 31 1112 61% 39% 64 8 43 26 18 27 $13.3 32 Mam. Workover 33 476 50% 50% 115 13 47 30 72 $13.0 1 Mam. HorizontalWell 34 24 50% 50% 775 379 98 47 250 72 $10.8 2 Ma'n.Pipeline 35 50% 50% 3 TotalMamantova Field 36 500 50% 50% 147 31 5 47 41 72 $12.7 37 Sre. W/O Fracturing 38 100 50% 50% 138 18 47 74 72 $10.5 1 Sre. Horizontal Well 39 50% 50% 2 Sre. Pipeline 40 50% 50% $10.5 3 Total Srednye AsomkiniskoyeF 41 100 50% 50% 138 18 47 74 72 $10.5 42 Pri. Workover 43 50% 50% 1 Pri. Horizontal Well 44 16 50% 50% 860 534 121 107 250 72 $8.8 2 Pri. Pipeline 45 50% 50% $8.8 3 TotalPrirazlomnoye Field 46 16 50% 50% 860 534 121 107 250 72 $8.8 TotalYuganslueftPA 47 616 50% 50% 164 42 7 48 51 72 $11.7 48l Totirniject 49 2134 53% 47% 118 30 36 33 29 40 $12.8 140

Annex 8-1 Page I of 14

RUSSIA SECOND OIL REHABILITATION PROJECT FINANCIAL ANALYSIS

1. The assumptions used in the Project fnancial analyses are outlined below. The Project components have been evaluated under June 1994 price and tax conditions which are described on pages 1 to 5. Detailed cash flows for the aggregate Project and a summary of the sensitivityanalyses carried out are shown on the remaining pages.

A. Inflation and Exchange Rate

2. The facial analyses have been carried out in constant US$ prices. Ruble costs were converted to US$ using the late 1993 exchange rate of 1,200 R/$ which was considered near equilibrium. This assumptionaffects the analyses only to the extent that, if depreciationcharges are not adequately adjusted with inflation, profit taxes will be higher. Rates of return have been based on discounted real 1993 dollar cash flows with a real after-tax return requirement of 15% assumed.

B. International and Domestic Oil Prices

3. Prices for Russian oil at the export terminal have been based on a $1 per barrel discount from Brent less $0.75 per barrel tanker costs from the Black Sea to Europe Mediterranean and $0.5 per barrel port handling charges'. Forecast prices for Brent in 1995 are $16.5 per barrel implying an average fob export price for Russian crude oil of $14.25 per barrel or $104 per ton2 . No real price increases have been assumed for the base evaluations. Instead, evaluations have been carried out within a band of Brent prices from $13.5 and $19.5 per barrel over the life of the Project.

4. Prices for domestic crude oil sales are assumed to rise from approximately one-half of international prices in late 1993 to ful parity with internationalprices by late 1995.

C. Project Capital and Operating Costs

5. Project capital and operatingcosts are described in Annex 7-1. Base variable operating costs of approximately$18 per ton of oil produced ($2.5 per barrel) have been assumed plus payments to the Social Reserve Fund equal to 40% of salaries ($2.8 per ton). Additionaloperating costs include: depreciation charges which are based on project costs, with allowance for revaluation; and minor

/IThe average price discount for UralsBlend crude to Brentover the past 5 yearshas been$1 per barrel. In recent years the discounthas been greater,reflecting uncertainty in Urals deliveryand illegaloil sales. Counteringthis trend has been an increasingshare of higherquality Sibenan crude in the blend which has reducedthe discountto Brent. Limitedexport salesof West Siberiancrude, whichsell at near parityto Brent, are also possible.

2/ Source:staff esdmates. i41

Annex 8-1 Page 2 of 14 workcovercosts assumed to be required every two years at a cost of $72,00 per operation3 .

6. The operating costs outlined above do not include capital charges for previous oil development expenditures. Historically, depreciationcharges have significantlyunderestimated costs due to the low value of assets on the Producer Association's books. Over the past two years the Producer Associationshave been allowed to revalue fixed assets periodically to reflect price changes. While this is a positive step it is not clear whether the resulting asset values are realistic. Formal procedures for asset revaluation under inflationary conditionsare part of the proposed changes to Oil and Gas taxation.

7. Current operating costs also understate likely longer term operating costs due to two additional factors. Social investments, which are typically funded from after-tax income, really represent labor costs. As social investments such as schools are shifted from the Producers to municipal jurisdiction, wages will need to rise to cover the local taxes which will be levied to fund these services. These costs have not been incorporated into the evaluations since this process will likely occur over an extended period in Western Siberia. The operating costs outlined above also exclude oil exploration or other finding costs which in 1991 averaged $3 to $5 per barrel of oil found for internaional oil companies4 . Finding costs will be high in Western Siberia due to the distance from suppliers, harsh climate, limited operating season and difficult terrain.

8. Total operating costs for Producer Associationsoperating in Western Siberia are not signifi- cantly different from international oil company estimates of expected operating costs. The international oil company estimates are based on substantiallyhigher unit costs for labor, equipment and materials but greater labor and capital productivity. Valuing Russian labor and other inputs at internationalprices would result in production costs of almost $100 per ton. The implication of these rough estimates is that Russian oil production costs will not only experience adjustment due to general price escalation but will also undergo significant structural change. As discussed above, Russian production costs are likely to be high by internationalstandards due to the difficult operating environment.

9. Imports of oilfield equipment and materials were exempted from Import Duties in April 1993 under Decree No. 441. However, this exemption was cancelled in January 1994 and Producers are now expected to pay approximately 15% duties on imported equipment.

10. Transportation tariffs are now being renegotiated on sections of the former Glavtransneft system. Transportation costs from West Siberia currently range from approximately $1 per barrel to $3 per barrel. Port handling charges of approximately$0.5 per barrel are levied. Export agents

3/ Operatingcosts including current workover and maintenanceexpenses but excludingsocial welfare payments are estmatedto be $13-615per ton($1.9 per barrel)in late1993 prices for the threeborrowers. Realincreases of 30% have been assumedto occurover the near term. Operatingcosts for internationaljoint venturesin WestSiberia .- ierage $3 per barrel.

4/ Sources:John S. HeroldPetroleum Outlook and DOEIEIA,December 1991 Form EIA-28Filings. 142

Annex 8-1 Page 3 of 14 charge a 1% commission. An average price of $2 per barrel or $15 per ton has been assumed in the analysis for the 3,500 kn movementfrom Western Siberia to the Black Sea plus $0.5 per barrel ($4 per ton) for port handling charges. These prices are expected to remain relatively stable over the project life.

11. Project debt service calculationshave been based on a Currency Pool Loan with an average interest rate of 8 % per annum and a term of 10 years with two years grace on principal repayments. Existing Association debt is small and involves short term revolving credit, denominated in Rubles.

D. Current Price and Tax Conditions

12. Government decrees in May and Sept. 1992 abolished the early 1992 system of oil sales (60% at state controlled prices, 30% at free market prices and 10% for export) and replaced it with a quasi-unified domestic market. Since then the market has continued to liberalize such that all domestic sales are now negotiated between buyer and seller. The Government has relatively minor influence on domestic sales, other than through open market purchases for centralized exports. In April 1994 producers were formally given the right to cut off delinquent customers5 and in September 1993 price caps related to production costs were abolished. Generally, Producers were unable to sell oil to the domestic market in 1993 at full (allowed) markup because of customer price resistance. As a consequence, and due to mounting payment arrears, Producers began to shut-in production and pull oil from the domestic market. By some estimates 20 million ton of production, representing 6% of total production, was voluntarily shut-in during 1993.

13. The Government still exerts pressure on domestic prices through control over access to the export market. During 1993 Producers were given a base export quota then required to obtain additional export quotas for particular projects based on a series of Decrees intended to promote investment6. These incentives are still in place and for which the proposed Project should qualify. Exports to non-CIS countries in 1993 totalled 80 million tons of which Producers controlled 43 million tons or 12% of production.

14. Domestic wholesale prices are subject to one key revenue tax; a differentiated Excise tax7 (Decree #847 November 1, 1992 and September 1993). The Excise tax default rate was set at 14,750 Rubles per ton in April 1994 (Resolution N320, April 14, 1994) which was equivalent to approximately $10 per ton. The tax will be indexed to the Ruble/dollar exchange rate and adjusted

5/ Presidendia'Decree #307, April8. 1994

6/ Two decrees promulgatedby the Governmentin March 1993 providedexport incentivesfor major oilfield investment.Resolution #179 allowsproducers to exportincremental production resulting from majorrehabilitation and workoverprograms, sufficientto recover costs. Resolution#180 provides export quotas for 60% of incremental productionfrom newfield development for the firstS years. Theseexports are alsoexempt from export taxes (Resolution #218)and mandatorycurrency conversion (Resolution #374).

7/ The Price RegulationFund tax was abolishedin mid 1993. 143

Annex 8-1 Page 4 of 14 quarterly. It is unknown whether the tax will increase in real terms as the domestic crude oil price rises to parity with international prices. The tax is also differentiated by field, depending on production costs. MNG is currently charged 11,000 Rubles/ton (equivalent to approximately $7.3 per ton), while TN and YNG are charged 8,500 Rubles/ton (equivalent to $5.7 per ton). Export sales are charged Excise tax at the comparable domestic rate.

15. Royalties under the Law of the Subsoil are set at a minimum level of 8% of gross wellhead prices with ranges of 6% to 16%.

16. Producers are subject to two additional revenue taxes; a fee paid to the Geologic Fund for resource replacement, equal to 10% of equivalent domestic revenues and a 2% royalty paid to the Ministry of Fuel and Energy InvestmnentFund. As of March 1993 Producers were able to reduce their payments to the Geology fund where an equivalent amount was spent by the Producer on new field exploration. New field developments will be exempt from this payment where the developer has incurred the exploration costs.

17. Value Added Tax is currently charged at 23 % on all domestic and imported purchases. VAT paid on capital goods are recoverable 6 months after the asset is put into operation. The net cost of this tax has been assumed to total 5% of operating costs for the analyses.

18. A number of other Government Funds which entail mandatory contributions are outlined below. (a) Science Fund, Land Use and EnvironrmentFunds: 5% of the cost of production (b) Insurance Fund: 2% of Gross Revenues (c) Road Users tax: 0.4% of Gross Revenues. (d) Asset Tax: 2% of Net Fixed Assets.

19. Producers are currently allowed to deduct the full amount of current year investmentsagainst income as a means of reducing profit taxes, subject to a maximum reduction in taxes payable of 50%. However this InvestmentFund deduction is likely to be removed in the near term and has not been included in the analysis.

20. Current depreciation charges are generally based on a 15 year period. However, a 5 year period is expected to be introducedshortly for workover rehabilitation investmentsas a tax incentive.

21. Balance profit, (defined as net revenues less production costs) was previously subject to a Profitability Ceiling equal to 50% of production costs but this was abolished in late 1993.

22. Exports sales were subject to Mandatory Currency Conversion according to Decree #335, dated December 30, 1991 and Instruction #3 from the Central Bank, dated January 22, 1992. Under these decrees 50% of export proceeds (net of transport costs) must be sold to the Government at the market exchange rate. Currency conversion at market rates result in an approximate 1% tax on revenues due to transaction costs. As of March 1993 oil producers have beein granted exemption from mandatory currency conversion (Resolution#374). 144

Annex 8-1 Page 5 of 14

23. Decree #91, dated December 31, 1991, establishedan Export Tax for crude oil exports which was initially set at ECU 26 per ton (approximately$35 per ton). The tax is payable in Rubles, 60 days after presentation of oil for customs inspection. This tax was increased to ECU 44 ($60) by mid 1992, reduced to ECU 21 ($28) in Sept. 1992, increased to the 1993 level of 30 ECU and will be reduced to 15 ECU/ton by mid 1994. Producers have been granted a credit for this tax where equivalent investment in oilfield development can be demonstrated (see for example, Resolution #179) and an exemption until project payout for major rehabilitation and new field investments.

24. Interest on some long term debt is not currently deductible from income for tax purposes. This is expected to be modified under changes to Oil and Gas taxation.

25. In an attempt to dampen wage increases the government requires Associations to add back wages in excess of 6 tiIne the minimum wage. This penalty results in a 10% increase in taxes payable.

26. Losses are available for 5 year carry forward to reduce taxable income. No limitationsare assumed on deductions for particular years.

27. Under the Profits Tax Law, Income is taxed at a flat rate of 35% to 38% (shared between federal and local governments).

28. Exterral profit distribution is subject to a 5% WithholdingTax. This tax does not apply to domestic producers.

29, Table 8.1 summnarizescurrent tax conditionsfor three categories of oil sales; domestic sales (85% of total sales), export sales with export tax (2% of total sales) and export sales exempt from export tax (13% of total sales). Overall tax take (percent of operating profit), excluding the indirect tax due to price subsidies, is 78% at June 1994 crude oil prices for domestic sales and approximately 70% for export sales. Including price subsidies the take for domestic sales is approximately 90%. With lower crude oil prices the take increases significantly (over 80% at a price of $13.5 Brent) reflecting the inflexibility of the current system, which relies primarily on flat revenue taxes. Figure 8.1 summarizes the level and compositionof Government take over the past two years. Since early 1992 Govermnent take as a percent of operating profit has declined from well above 100% to tne current levels.

30. While the Government take on flowing oil has been reduced to a level which leaves the Producers with sufficient cash flow to maintain production this is not the case for new oilfield development. At average excise tax levels, tax take on new fields would result in a real rate of return well below 15% which is not sufficientto attract major foreign investment. The solution is to include a flexible, profit sensitive, tax (instead of the Excise Tax) in the license.

E. Payment Arrears

31. A majorfinancial problem currently facing the industryis paymentarrears. Producerswere collectivelyowed in excess of 6.4 trillionroubles or near US$3.5 billion by end February 1994. 145

Annex 8-1 Page 6 of 14

Table 8.2 summarizes the working capital position of the Producers as of the third quarter of 1993 which shows the dramatic increases in payment arrears from customers (US$620 million) and the consequent buildup of payables to the Government (USS300 million for budget and non-budget payments) and suppliers (US$500 million). This problem arises from a number of factors including; friction in the banking sector which results in 2 to 6 months delay for payment settlement; a dis- incentive to pay under high inflationconditions; financial difficulties of customers, and until recently, limited scope for Producers to cutoff customers. Producers are now authorized to cut-off supplies to delinquent customers but are reluctant to do so for fear of losing market share and due to political pressure. While producers could face cash flow problems stemming from arrears for a few years, the ability to cutoff supplies should sharply reduce the arrears problem. Under the export incentives of Resolution #179 this problem is not a factor for the exportable incremental production from the proposed Project. Ten year projections of the overall production and cash flow positions for the Associations are shown in Table 8.6. Even with an assumed 10% revenue loss due to bad debts for the next two years, the Associationsshould be in a position to generate sufficient cash flow to at least maintain production at 1993 levels. This level of cash flow will also provide ample debt service capacity. Three key risks to near term financial viability are that the Associations are: (i) unable to control cash flow including, in particular, working capital; (ii) allow operating costs including wages to rise faster than productivity increases; and (iii) undertake uneconomicinvestments, wasting scare funds. The proposed financial advisory services will help the Associations establish strategic cash management procedures, improve management information systems and develop capital budgeting procedures and criteria. The proposed Field OptimizationStudies will help establish least cost means for future development of existing fields.

E. Conclusions

32. The overall after-tax real rate of return for the Project exceeds 40 % and all components show strong returns. The four key risks to Project viabilityare oil prices, both international and domestic, tax levels, access to the export market and well productivity. The overall Project is still viable at international prices as low as $13.5 (Brent) throughout the Project life although a few components would not be viable. A 100% increase in the Excise Tax rate can be absorbed at internationalprices of $16.5 per barrel although some Project components would not be viable. However, at international prices of $13.5 per barrel the Project cannot absorb any increases in the Excise Tax. The Project can sustain productivity declines of 25% from expected levels and still exceed a 25% rate of return. 146 Anntex9-1 Russia Petroleum Taxation Table 8-1 Taxation for Upstream Domestic Sales June 94 DomesticPrice Stage Price Tax Comments l (R/ton) Rates % _ 1). RefineryPrice IncludingVAT & Trans. 144,096 1 57% of Intl.Price (excl VA1) - VAT 22,525 23% % of WholesalePrice (2) -Transport 23,635 $1.62 $/barrel 2). DomesticWholesale Price i 27_ 97,9351 - ExciseLevy (0% to 30%, avg. 18%) 20,935! 21% i of DomesticWholesale Price (2) 3). Price BeforePrice RegulationDeduction 77-0! -Price RegulationFund (Avg.) ). Supplier'sPrice (GrossWellhead) 77o000fl 8 -Royalty(6% to 16%, avg. 8%) 6,1601 8%l % of Pricebefore Price Reguladon (3) - GeologyFund (10%, 5% creditpossible) 1 7,7001 10% %of Pricebefore Price Regulation (3) - Net VAT 1,800 5% %of ProductionCost - RoadUsers Tax 392l 0.4% %of WholesalePrice (2) -Social Payments 1,2001 40%1 % of Wages,3000 R/ton - InvestmentFund %of Pricebefore PRF (3) -InsuranceFund 1 1,540 2% %of Pricebefore PRF (3) - Envir./Land/ScienceFunds 1 5% % of ProductionCost 5). Sub-TotalGovt. Fundsand Charges 20,592 - ProductionCosts 40.00 $20.0 per ton 6). Prime Cost I Govt.Funds (5) plusProduction Costs 7a). BalanceProfit on DomesticSales X 16,408 _ l (4) -(6)

Taxation for Export Sales on Flowing Oil - - ExportPrice Stage Price Tax Comments I (RJton) Rates % I ExchangeRate (R/$) 2,000 2,000 monthaverage rate 1). Export Price ($ per ton) $107 $107 averageof UralsBlend and heaviercrudes - Export Duty 18 18 15 ECU/ton,credit for qualifiedinvestment. - Transport $15 $2.1 ). Net Exportafter ExportTax & Trans. $Z4l 3). Net ExportPrice in Rubles 148,125l - ExciseLevy (0% to 30%, avg. 18%) 20,935 21% of equivalentDomestic Price - Price RegulationFund l ). Supplier'sPrice (GrossWellhead) 127.190 - Royalty(6% to 16%, avg. 8%) 11,850 8% % of ExportPrice (l) - GeologyFund (10%, 5% creditpossible) 7,700 10% % of equivalentDomestic Price - Net VAT 1,800 5% % of ProductionCost - Road UsersTax 859 0.4% % of WholesalePrice (2) - SocialPayments 1,170 39% % of Wages,3000 RJton - InvestmentFund % of Pricebefore PRF (3) - InsuranceFund 4,295 2% % of Pricebefore PRF (3) - Envir./Land/ScienceFunds 1 5% % of ProductionCost 5). Sub-TotalGovt. Fundsand Charges 29,474 - ProductionCosts 40$ S20.0 perton 6). PrimeCost Govt.Funds (5) plus Production Costs 7b).Balance Profit on FlowinaExport Sales 57,715 $28.9 per ton 147 Annex8-1 Russia Petroleum Taxation Table 8-1 Taxation for Export Sales on NewOil (cont.) !:ExportPrice Stage Price Tax Comments ! ______(R/ton) Rates % I | Exchange Rate (RI$) 2,000 2.000 month averagerate 11). Export Price ($ per ton) $107 $107 averageof Urals Blend and heavier crudes - Export Duty 15 ECU/ton, credit for qualifiedinvestnent. - Transport $15 $2.1 i2). Net Export after Export Tax & Trans. 3). Net Export Price in Rubles 184.125 - Excise Levy (0% to 30%, avg. 18%) 20,935 21% of equivalentDomestic Price - Price Regulation Fund 4). Supplier's Price (Gross Wellhead) 163.190 - Royalty (6% to 16%, avg. 8%) 14,730 8% o% of ExportPrice (1) - Geology Fund (10%, 5% credit possible) 7,700 10% % of equivalentDomestic Price - Net VAT 2,700 5% % of ProductionCost - Road Users Tax 859 0.4% % of WholesalePrice (2) - Social Payments 1,170 39% % of Wages, 3000 Rfton - Investment Fund % of Price before PRF (3) - Insurance Fund 4,295 2% % of Price before PRF (3) - Envir./Land/Science Funds 1.800 5% % of ProductionCost 15). Sub-Total Govt. Funds and Charges 33,254 - Production Costs 60.000 $30.0 per ton f6). Prime Cost 2 Govt. Funds (5) plus ProductionCosts i7c). Balance Profit on New Export Sales 69,935 _ _ $35.0 per ton

Net Income Upstream "TaxableIncome and Govt. Take Amount Tax Comments (R/ton) Rates % _

17a). Balance Profit on Domestic Sales 16,408 85.3% 1j7b).Balance Profit on Flowing Export Sales 57,715 1.5% |7c). Balance Profit on New Export Sales 69,935 13.2% % of exportsnew oil 90% 18).Total Taxable Income (Average) 24,081 100%

9). - Income (Profit) Taxes 9,151 38% % of TaxableIncome + Investment Funds 10). Net Income on Total Sales 14,930 $7.5

Government Take on 1la). Domestic Sales (excl. price subsidies) 47,762 82% % of Avg. WholesalePrices-Prodn. Costs lIb). Domestic Sales (incl. price subsidies) 133,952 93% % of Export Price-Prodn.Costs I Ic). Export Sales Flowing Oil, with duty 108,342 75% % of Export Price-Transport-Prodn.Costs lI d). Export Sales New Oil, w/o duty 80,765 65% % of Export Price-Transport-Prodn.Costs Ile). Govt. Take Average 53,008 78% % of Avg. SellingPrices-Production Costs t l If ). Govt. Take Average (incl price subsidY) 126,554 89% % of Avg. SellingPrices-Production Costs 148 Figure8-l

Producerand Govt. ProfitSharing Combined Oil Prodn. @S20/tonProdn. Cost

125%

75%

X 25%_

-25% Jan.92 Feb 92 May92 Sept.92 Jan.93 June93 Jan.94 June94 Date

- Consumer Subsidies MSRevenue Taxes a ProfitSensitive Taxes Producer Profit

Compositionof Govt.Take CombinedOil Prodn.@$20/ton Prodn. Cost

I-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~l ID100% ~ . x 80%

680%

40%

20%

0% Jan.92 Feb.92 May92 Sept92 Jan.93 June93 Jan.94 June94 Date

m Export Taxes I Revenue Taxes m ProfitSensrtve Taxes 149

Table8-2 Russia Ofl Payment Summary (millionrubles)

Total Receivables 1 MNG (Q4) 215 68,908 186,140 TNG(Q3) 286 29,116 150,161 YNG(Q3) 252 69,113 407,814

Total Payables MNG(Q4) 275 55,181 221,456 TNG (Q3) 349 29,537 207,278 YNG (Q3) 1,016 76,060 525,717

Current Ratio MNG(Q4) 1.33 1.85 1.46 TNG(Q3) 1.07 1.08 0.93 YNG(Q3) 1.18 1.24 0.86

Receivablesas % of Sales MNG(Q4) 14% 34% TNG (Q3) 21% 27% i YNG(Q3) 8% 29%

1Budget& Non-BudgetP yables i MNG(Q4) 35 22,3791 96,1821 TNG (Q3) 26 8,931 54,366| | YNG(Q3) 219 33,941 210,4821 ij j|Receivablesto Payables MNG(Q4) 78%1125% 84% ii TNG (Q3) 82%f 99% 72% YNG(Q3) 25% 91% 78% 'Budget& Non-Budgetas % of Payables MNG (Q4) 13% 41% 43% LTNG (Q3) 7% 30% 26% YNG (Q3) 22%, 45%. 40% 150 RUSSIA SECOND OIL REHABILITATION PROJECT AnnexA. Base Case (full export quotas) Table 8-3 COMPONENT FINANCIALEVALUATION_ Real IRR PeakProdn. NPV Govt. TakeoProducerRev

Percent $min ______% mln tons nuln$ Field _ . NW Megion In-fil 1 24% 0.11 2.0 78 4 Main Megion In-fill 2 16% 0.19 0.7 83% 5 SE Megionin-flu 3 26% 0.21 4.0 78% 8 MegionWorkovers 4 41% 0.16 3.1 82% 5 Megion Pipeline 5 23% 0.13 2.4 73% 7 otI MegionField 6 23% 0.77 11.8 79% 29 7 Pokamasovskoye In-fill 8 65% 1.30 69.4 70% 85 PoamnovskoyeWorkovers 9 85% 0.21 8.6 75% 10 PokamovskoyePipeline 10 15% 0.07 0.1 75% 3 TotalPokamovskoyeField 11 61% 1.58 77.9 71% 98 Total Megionneftegas 12 43% 2.35 89.3 74% 127 13 Sov. ESP Workover 14 40% 0.49 10.6 81% 17 Sov. RodPumpWorkover 15 27% 0.13 2.5 79% 5 Sov. Horizonta Well 16 72% 0.09 5.0 70% 6 Sov. Pipeline 17 62% 0.33 17.6 68% 24 otalSovietskoye Field 18 47% 1.02 35.8 75% 52 19 Per. ESP Workover 20 46% 0.49 11.9 80% 18 Per. Rod Pump Workover 21 32% 0.13 3.2 77% 5 Per. Horizontl Wel 22 50% 0.07 3.1 72% 4 Per. Pipeline 23 60% 0.21 10.8 68% 15 otl PervonuaiskoyeField 24 47% 0.88 29.1 76% 42 25 Vahk. ESP Workover 26 45% 0.49 11.7 80% 18 Vahk.RodPumnpWorkover 27 31% 0.13 3.1 78% 5 Vahk. HorizontalWeU 28 60% 0.09 4.6 71% 6 Vahk. Pipeline 29 30% 0.22 6.6 71% 13 otalVahkskoye Field 30 39% 0.91 26.0 76% 42 TotalTomskneft 31 44% 2.80 90.9 75% 135 32 Mam. Workover 33 64% 2.01 62.2 78% 82 Mam. HorizontalWeH 34 18% 0.28 2.5 80% 11 Mam. Pipeline 35 otal MamantovaField 36 48% 2.29 64.1 78% 92 37 Sre. W/O Fracatring 38 95% 0.54 28.1 72% 34 Sre. HorizontalWell 39 Sre. Pipeline 40 TotalSrednye AsonmkMskoye Field 41 95% 0.54 28.1 72% 34 42 Pri. Workover 43 Pri. HorizontalWell 44 47% 0.34 19.8 68% 26 Pri. Pipeline 45 omalPriazlomnoye Field 46 47% 0.34 19.8 68% 26 TotalYganskntes_ 47 53% 3.16 112.0 76% 152 48 Tota ProJect 49 47% 8.30 292.6 75% 415 151 RUSSIA SECOND OIL REHABILITATIONPROJECT Am, I PROJECT FINANCAL EVALUATION -Media Oa Pri2- Table 84 ______~~~~Fimei 2 3 4 5 67 Production(of maximum)anddecline re 10% 27% 69% 80% 72% 65% 58% 52% Production 10.4 2.8 7.2 8.3 7.5 6.7 6.1 5.4 CumulativeProduction 64.0 3 10 18 26 32 39 44

CapitalExpenditure Profile $16 53% 47% CapitalCosts (mid 1994 $) incl Duties $588 313 275 DepreciationPool Facilties 13% 41 74 66 58 50 42 35 DepreciationPool Wells 87% 271 456 354 252 150 48 Losses Pool Oil Prices Export Oil Price (fob) 108 108 108 108 108 108 108 Oil Price (domesticas % of international) 56% 70% 100% 100% 100% 100% 100% 100% Oil Price (domestic)(years to foulprice) 1.5 75 108 108 108 108 108 108 GrsesRevenues Oil Revenues(exports - no duty) 100.0% 299 776 894 805 724 652 587 Oil Revenues(exports - duty) Oil Revenues(domestic) Total Revenues 100.0% 299 776 894 805 724 652 587 Transport Costs $19.0 L31 1.5 142 122 llS l Net WellheadRevenues 246 640 737 663 597 537 483

RevenueTaxes Export Duties 18 Excise Tax (avg. for PAs) Flat Excise $/ton $6.0 17 43 S0 45 40 36 33 Royalties 8.0% 18 48 55 49 45 40 36 GeologyFee 10.0% t4 60Q 62 (a 56 5 45 Total Revenue Taxes 42 11 i1 5i6 I VA I Ne Revenues 197 489 563 507 456 411 370

Other Taxesand Payments 25 fil 62 8 75 65 56 -NetVAT 4.5% 5 11 11 13 13 10 7 -RoadUsersTax 0.4% 1 3 3 3 2 2 2 - SocialPayments 40.0% 10 25 29 37 35 32 30 - InsuranceFund 2.0% 5 13 15 13 12 11 10 -Envir./Land/ScienceFunds 4.5% 5 11 11 13 13 10 7

Producto Costs $17 1i 214 252X 26 2 21 152 Labour (50% of Opex) 9 24 62 72 93 87 81 76 DirectOpex 9 24 62 72 93 87 81 76 Dpreciation Facilities(years) 10 4 8 8 8 8 8 8 DepreciationWells (years) 5 54 102 102 102 102 48 in $/ton $35 38 33 31 40 42 36 29 Bad Debts (% of domestic salesfor 2 years -10% ______11 ross Margin 66 193 241 131 98 128 154 Losses Carried Forward plus excess wages(25% of wage bill) 25.0% 6 16 18 23 22 20 19 Less Invest Deduction(max 50% reduction ProfitTaxes 38.0% 22 72 98 52 46 52 66 Net Income 38 114 142 72 53 72 88 plus Depreciation 58 110 110 110 110 55 8 Net Cash Flow 97 224 252 182 163 127 96

Cash Flow after Invest (@15% real) 293 (216) (51) 252 182 163 127 96 MR Real 47% Profit Margin Drbuimd ovm.Reenue perton $41 37 40 41 39 39 41 43 OpeaftingMargin 1,663 140 405 483 367 314 320 324 ConsumerSubsidies tal Govt. Paymems 75% 101 291 341 295 261 248 236 Export Tax Exise Tax 11% 17 43 50 45 40 36 33 Royalty 12% 18 48 55 49 45 40 36 Geology 15% 14 60 69 62 56 50 45 MiscellaneousNonBudget. incl Soci 18% 25 61 69 80 75 65 56 Corpoate loome Tax 19% 27 79 98 59 46 57 66 oTalProducerTaI 25% 38 114 142 72 53 72 88 RUSSIA SECOND OIL REiHABILITATIONPROJECT Tbe8-5 FINANCIAL SENSITIVITY

Internal Rate of Return ___

Senario Project -cgonfea rn tgs-YuganskreiGCas7 ______Total Total Megion Pokcom. Total. Soy. Per. Valik Total Mamon. Sre. Pri.

BaseCase (ful exportquotas) 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% AverageExport Quotas (I 5% of prodn.) 33% 32% 18% 43% 31% 33% 32% 27% 36%7 32% 56% 36% Low OilPrice $13.5/bblBrent 15% 14% 6% 23% 8% 11% 9% 5% 17% 13% 31% 22% MedianOil Price $16.5/bbiBrent (Base) 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% HighOil Price$19.5/bbi Brent 88% 78% 45% 111% 84% 89% 91% 74% 103% 96% -_ 100% 77% Bad Debts0 % of domesticsales 47% 3 3 1 4 7 7 9 3 8%95 % 4% Bad Debts 10% of domesticsales (Base) 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% Bad Debts20% of domesticsales 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% ExciseTax $6/ton (Base) 47% % 23% 6% '44% 7 47% 39% 3 4% 95 ExciseTax $9/zon 42% 39% 20% 55% 39% 42% 42% 34% 47% 41% 85% 43% ExciseTax $12Iton 36% 34% 17% 50% 34% 37% 36% 29% 41% 35% 75% 39% ExciseTax $15/ton 32% 30% 14% 44% 29% 32% 31% 25% 35% 29% 66% 36% ExciseTax $9/ton.Low Oil Price $13.5 5% 10% 18% 3% 5% 2% 3% _ _ 23% 19% CustomDuty 0% 56% 51% 28% 72% 53% 56% 56% 46% 65% 58% 119% 55% CustomDuty 1S5%(Base) 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% - CustomDuty 20% 44% 41% 22% 58% 42% _45% 45% 3b% 50% 45% 89% 44% ' Capital Costs (Base) 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% Capital Costs +25% 35% 33% 17% 47% 32% 34% 35% 28% 39% 35% 67% 37% Capital Costs +50% 27% 26% 12% 37% 24% 26% 26% 20% 30% 26% 51% 30% Capital Costs +-100% 16% 16% 6% 25% 14% 16% 15% 11% _ 8% 15% 32% 21% OperatingCosts +0% 62% 56% 32% 78% 59% 63% 64% 53% 70% 66% 121% 54% OperatingCosts +35% (Base) 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% OperatingCosts +50%/ 40% 38% 19% -54% 37% 40% 40% 32% 46% 39% 85% 44% Production No Prodn. Losses 5% 0% 2% 71% 5% 5% 5% 4% 6% 5% 17 5 Production-10% Losses(Base) 47% 43% 23% 61% 44% 47% 47% 39% 53% 48% 95% 47% Production-25% 25% 26% 11% 38% 23% 26% 25% 19% 2b% 21% 50% 29%: Productio-5% 2% 9% 16% 3% 11% 13% ProductionDecline 10% (Base) -- 47% 43% 2% 6% 44 47 47%. 39%i 53 48 95% 47 ProductionDecline 15% 42% 39% 19% 57% 40% 43% 43% 34% 49% 43% 92% 43% ProductionDecline 20% 38% 35% 14% 54% 36% 39% 39% 30%, 44% 38% 88% 40% RUSSIA SECONI) OIL REIIABILITATION PROJECT Anlfx 8:1 ASSOCIATION FINANCIAL FORECASTS - McdianOil Price Table8-6 (millionend 1993$)

CombinedAssocatiots _ 99 995- 199-6 '-9- ---- =1999 -_2000 2001 2002 2003- _ 2 Production (mrittons) 5 .5 55.4 53.3 53.1 53.3 53.4 53.6 53.6 53.7 53.7 53.8 of which New Production 2.9 6.7 10.2 13.4 16.4 19.1 21.6 24.0 26.2 incrementalNew Production(non-project) 20 0.3 2.9 4.0 3.9 3.9 3.9 3.9 3.9 3.9 3.9

Nei Cash Flow before Investment 71.3 713.5 981.6 958.0 958.2 951.9 945.3 945 4 945.6 946.1 Debt SctviCe 3.0 9.0 30.8 29.3 27.8 26.3 24.8 23.3 21.8 20.3 Debt ServiceCoverage (times) 24.8 80.3 32.9 33.8 35.5 37.3 39.2 41.7 44.5 47.7 InvestmentProgram (I of New Wells) $1.8 40 400 551 537 538 534 530 530 531 531 InvestmentProgramn .based on Cash Flow 146.3 == .988.5 , _ 981.6 958.0 958.2 95,19 _ 9453 945 4 945.6 9461

IHengonnefteg__ 1993 1996. ' 9 -99' 2I1 200 2002 200303 2994 Production (ninlotns) 13.5 333 13.7 14.0 140 14.0 14.0 13.9 13.9 138 138 of which New Production 0.8 1.8 2.7 3.5 4.3 4.9 5.6 6.1 6.6 incrermentalNew Production(non-project) 20 0.1 0.8 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Net Cash Plow before Investment 31.6 200.8 255.4 248.4 247.4 241.8 235.8 234 6 233.7 232.9 Debt Service 2.9 8.9 30.8 29.3 27.8 26.3 24.8 23.3 21.8 20.3 Debt ServiceCoverage (times) 11.7 23.4 9.3 9.S 9.9 10.2 10.5 11.1 11 7 12.5 lnvestmentProgram (I of New Wells) $S.8 18 113 143 139 139 136 132 132 131 131 Invesmnt Pr egramgWd on Cash flow) _ 105.3 27?72 25.4 248.4 2474 241.8 235.8 __ 234.6 2337 _ 2329

romskneft .-w 19-7'. - Production (mintons) 11.6 11.8 32.5 12.9 32.9 12.9 12.8 i2.7 12.6 32.5 12.4 of which New Production 0.8 1.7 2.5 3.2 3.9 4.5 5.0 5.5 5.9 incrementalNew Production(non-project) 20 0.2 0 X 1.0 0.9 0.9 0.9 0.8 0.8 0.8 0.8

Net Cash Flow before Investment 39.8 193.4 240.3 222.2 220.0 212.2 206.3 204.0 202.0 200.2 Debt Service 3.7 9.7 3u.8 29.3 27.8 26.3 24.8 23.3 21.8 20.3 Debt ServiceCoverage (times) 11.9 21.0 8.8 8.6 8.9 9.1 9.3 98 103 30.9 InvestmentProgram(IofNewWells) $1.8 22 108 135 125 123 119 116 114 113 112 mnvetentProeram (basedon Cast Flow) __. = _ 31 1 252.0 240.3 222 2 ,220.0 ,212.22 203 204 0 _ 2020 ___200.2

IYu nsknefieas s9~i 1 9933 199h99S_ ( 1999 _ 2000 _ 2001_ 2002---03' _0'T4 0 Producaion(mlnlons) 33.4 3i.1 31.6 33.8 3.9' 331.8 3.8 31.7 --3-1.6- '' 3633 31.5 of which New Production 1.8 4.0 6.0 7.9 9.5 11.1 12.5 13 9 15.1 incrementalNew Production(non-project) 20 0.2 1.8 2.4 2.3 2.3 2.2 2 2 2.2 2.2 2.2

Net Cash Flow beforelnvestment 54.9 434.2 579.8 554.0 552.1 543.6 5350 544.5 543 0 541.7 Debt Service 4.3 19.2 46.8 44 4 42.0 39.6 37.2 23.3 21 8 20.3 DebtService Coverage(tmes) 13 8 23.6 13.4 13.5 14.1 14.7 15.4 24.4 260 27.8 InvestmentProgram (# of New Wells) $3.8 31 244 325 311 310 305 300 305 305 304 InvestmentPo2ram(ased on Cash lon9 =_. = -..31638 541 I 579.8 554 0 552-1 543.6 535.0 544.S 543.0 541.7 154

GOVERNMENT OF THE RUSSIAN FEDERATION

MOSCOW June 8, 1994 0881p-P4

Mr. Russell J. Cheetham Director Europe and Central Asia Region World Bank

Dear Mr. Cheetham: Re: Second Oil RehabilitationProject

This is to inform the International Bank for Reconstruction and Development (Bank) that the Government of the Russian Federation agrees with the proposed Oil RehabilitationProject to be fmanced under the Bank's loan in the amount of US$ 500 million on conditions set out in the documents agreed between the Russian delegation and the Bank during consultationsand negotiations in Washington May 16 to May 27, 1994.

At the same time, the Government is pleased to advise the Bank of recent policy actions with respect to the oil sector and to confirm its intentions to irnplement additional policies in 1994-1995 with a view to strengthening and further developing economic reforms in the Russian oil industry.

Oil trade has been substntially liberalized by Presidential Decree No. 1007, dated May 23, 1994, which abolishes all quotas and licenses for exports of goods and services except those which are exported in compliance w:th the international commitmnentsof the Russian Federation.

The Government will continue to improve procedures regarding oil producers' access to the oil transportation system. The Government is actively involved in improving the system of economic regulation and legislativesupport to oil production and transport and the draft Law on Oil and Gas recently submitted to the Duma is evidence of this. It is the Government's intent to provide detailed plans for the establishment of a regulatory framework for crude oil transport by January 1995, including economic tariffs and other adequate provision for non-discrirninatoryaccess.

The Government will continue to promote investments in rehabilitation and development projects in the oil industry. As part of this policy the Government is committed to effective implementationof the Goverrnent Resolutions No. 179 and 180, dated March 1, 1993. It is the intent of the Government that any recent or planned decrees should deepen or at least preserve the incentives provided by such resolutions.

With a view to strengthening the fiscal framework for joint ventures with foreign participation, the Govermnent has taken steps to ensure that oil investments by joint ventures with foreign participation, registered prior to December 31, 1993, are provided with export tariff privileges by issuing DecreeNo. 497, dated May 19, 1994.

Continued reform of oil taxation is a priority of the Government as exemplified by 155

Annex 9-1 Page 2 of 2

GovernrmentResolution No. 320, dated April 14, 1994, which converts the variable excise tax on oil from a percentage ad valorem tax to an equivalent ruble per ton tax. This change is expected to increase tax compliance. Care was taken in introducing this reform to avoid any increase in the statutory burden of the tax and to maintain its variable character which is responsive to the underlying profitability of different producers.

The Government supports a policy of shifting oil taxation from revenue-basedtaxation towards profits-based taxation. Presidential Decree 2285 issued December 24. 1993, "Concerning Issues Related to Production Sharing" establishes the possibility of a simple tax system based on three components (the corporate profits tax, a royalty and a production share) which would be essentially profits-based. The Government is actively developing a series of normative documents for the implementationof this production sharing system with the expectationthat all necessary steps w;ll be complete by late 1994/early 1995. A series of major projects would come under this these new principles. At the same time, the Government, as noted above, is adjusting the tax system on existing production to be more sensitive to profits and has planned additional studies to facilitate a move to profits-based taxes.

In addition to taxation aspects, the Governrnent is in the process of elaborating a complete legal framework for petroleum operations, which should be complete by end-1994 or early 1995. A number of regulatory acts, includinga model form agreem,entfor petroleum operations will be prepared and submitted to the Government by its experts in July 1994. As noted, the draft law on Oil and Gas has been submitted to the Duma and additional legislationwill be submitted in the coming months, including Amendmentsto the Law on the Subsoil and the Law on Concessions and Contracts.

The Government is aNwareof certain difficulties arising in the current economic environment as regards the implementationof a number of planned investment projects in the oil sector, including the imnplementationof the Bank's First Oil RehabilitationLoan. These difficulties are mainly encountered in paying customs duties on imports of oil equipment and materials and in facing delays in the recovery of VAT payments on such irnports. The Government is examining a number of possible remedies, including those proposed by Bank representatives to the Russian Delegation in Washington.

As it proceeds with its work on oil sector reforms, the Government expects to maintain its program of regular policy consultations with the Bank, begun in the context of preparation of the First Oil RehabilitationProject.

Yours sincerely,

A. Shokhin Deputy Chairman of the Government of the Russian Federation 156

Annex 9-2 Page 1 of 2 RUSSIA SECOND OIL REHABILITATIONPROJECT SELECTED DOCUMENTS AND DATA AVAILABLEIN THE PROJECT FILE

I. POLICY RELATEDDOCUMENTS

A. Petroleum Pricing

1. Presidential Decrees on Petroleum Pricing 1992-1994.

B. Taxation

2. Corporate Income Tax Law as Amended 1993

3. Customs Law 1993

4. Presidential Decrees on Oil Taxation 1992-1994

C. Petroleum Legislatio.:

5. Law on the Subsoil 1992

6. Statute on Licensing 1992

7. Draft Law on Oil and Gas 1994

8. Draft Amendments to Subsoil Law 1994

9. Draft Law on Concession and Contracts 1994

10. Decree 2885. 1993

11. Minutes of Workshop on Russian Oil Legislation and Taxation (April 1994)

D. Institutional and Enterprise Reforms

12. Presidential Decrees and Government Protocols 1992-1994

E. Tendering

13. Promotional Brochures 1993-1994

F. Bank Materials

14. Aide-Memoires and Consultant Reports 1992-1994 157

Annx 9-2 Page 2 of 2 II. PROJECT RELATED DOCUMENTS

15. RussianFederation Petroleum Development and Production:Background Infonnation (March, 1992) -- Gustavson Associates; Spears & Associates.

16. Project IdentificationMission Aide Memoire (July, 1993).

17. Project Preappraisal Mission Aide Memoire (October/December, 1993).

18. Project Appraisal Mission Aide Memoire (March, 1993).

19. Russia Second Oil RehabilitationProject: Draft EnvironmentalAssessment (February, 1993)

20. Project De.finitionStudies, Tyumen Task Force (December 1993) IBRD24146RI

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