LE E 11~ - 11 UiW3E1101r-~EL H .IE-uE 4 uy ~~j[~~EJl[jj 0 f, s Q 0- 0 0 9 0 LJ _A 0 W ri Nd EJ 2 1]L m a E m E n 0- 0 u E 6- El W i 1e El L-- EA 0 u BEvmg S¢o.torr Maiixagemcut Bsirtance Pr ogKainuwve Th~e Ftire xn Eastserna Euro pe Report No. 149-92 Ajoint report with the Europe & Central Asda and Middle East & North Africa Reglonal Offices JOINT UNDP / WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) PURPOSE The Joint UNDPlWorld Bank Energy Sector Management Assistance Programme (ESMAP) was launched in 1983 to complement the Energy Assessment Programme, established three years earlier. ESMAP's original purpose was to implement key recommendations of the Energy Assessment reports and ensure that proposed investments in the energy sector represented the most efficient use of scarce domestic and extema resources. In 1990, an international Commission addressed ESMAP's role for the 1990s and, noting the vital role of adequate ano affordable energy in economic growth, concluded that the Programme should intensify its efforts to assist developing countries to manage their energy sectors more effectively. The Commission also recommended that ESMAP concentrate on making long-term efforts in a smaller number of countries. The Commission's report was endorsed at ESMAP's November 1990 Annual Meeting and prompted an extensive reorganization and reorientation of the Programme. Today, ESMAP is condncting Energy Assessments, performing preinvestment and prefeasibility work, and providing institutional and policy advice in selected developing countries. Through these efforts, ESMAP aims to assist governments, donors, and potential investors in identifying, funding, and implementing economically and environmentally sound energy strategies. GOVERNANCE AND OPERATIONS ESMAP is governed by a Consultative Group (ESMAP CG), composed of representatives of the UNDP and World Bank, the governments and institutions providing financial support, and representatives of the recipients of ESMAP's assistance. The ESMAP CG is chaired by the World Bank's Vice President, Operations and Sector Policy, and advised by a Technical Advisory Group (TAG) of independent energy experts that reviews the Programme's strategic agenda, its work program, and other issues. The Manager of ESMAP, who reports to the World Bank's Vice President, Operations and Sector Policy, administers the Programme. The Manager is assisted by a Secretariat, headed by an Executive Secretary, which supports the ESMAP CG and the TAG and is responsible for relations with the donors and for securing funding for the Programme's activities. The Manager direct-: ESMAP's two Divisions: The Strategy and Programs Division advises on selection of countries for assistance, carries out Energy Assessments, prepares relevant programs of technical assistance, and supports the Secretariat on funding issues. The Operations Division is responsible for formulation of subsectoral strategies, preinvestment work, institutional studies, technical assistance, and training within the framework of ESMAP's country assistance programs. FUNDING ESMAP is a cooperative effort supported by the World Bank, UNDP and other United Nations agencies, the European Community, Organization of American States (OAS), Latin American Energy Organization (OLADE), and countries including Australia, Belgium, Canada, Denmark, Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden, Switzerland, the United Kingdom, and the United States. FURTHER INFORM4ATON For further information or copies of completed ESMAP reports, contact: The Manager or The Executive Secretary ESMAP ESMAP Consultative Group The World Bank The World Bank 1818 H Sreet N.W. 1818 H Street, N.W. Washington, D.C. 20433 Washington, D.C. 20433 U.S.A. U.S.A. The Future of Natural Gas in Eastern Europe A Joint Report Eupe 8& Centl Asia and ESMAP Operations Division Middl East & North Africa Regional Offices Foreword This report was prepared for a seminar, "Natural Gas in Eastern Europe - Regional Issues and Options," hosted by the World Bank. The seminar, which was held in London on January 17-18, 1992, brought together key decision-makers, whose names appear at an appendix, from the gasconsuming countries in Eastern and Centml Europe, major gas-producing countries and intemational organizations. The World Bank wishes to express its appreciation to the Overseas Development Administradon of the UK for cosponsoring the seminar. The repoit is being published in its original form The recent political changes that have taken place in the region and in the fmer SovietUnion have, therefore, not been reflected in the report This background report for the seminar was prepared by consultants Arthur D. Little and funded as a joint report by the Europe & Central Asia and Middle East & North Africa Regional Offices (Country Depaments ECI, EC2, EC3, MNI, & EMT) and the ESMAP Operations J)lvision. Bank staff who initiated and supported the compledon of the report included Messrs/Mines.: A. Mashayekli (Division Chief), C McPherson (Principal Energy Economist), Z. Alahdad (Prncipal Energy Speciali), P. Nore (Senior Energy Economist), M. Shirazi (Senior Gas Specialist), P. Law (Energy Specialist), H. Hahm (Economist), and B. Svensson (Energy Economist(rask Manager). Large reserves of natural gas in some countries and growing import requimnents for efficient and environmentally benign fuels in other countries create a potential for growth in natural gas trade within Eastern Europe and between this region and other regions. This activity is a part of the Bank's continuous efforts to encourage efficient and economic development and trade of natural gas in Europe, Centml Asia, and the Middle East and North Afnica RLRazavi H.E. Wackman Chief Chief Opeaions Division Industry and Energy Operations Division Energy SectorManagement Assistmace Prgamme Technical Deparment Europe & Central Asia and Middle East & North Afrca Regional Office Table of Contents Foreword S umumary .......... * ..000000.004.0 Key Issues ................. .... *.. ..........*.......i Dei and .................................................II ............................................I EIn Committed Supply and the Supply Cap ....... ... ........................................... lii Supply Options: Tw P jects ............................................................... ... ii Futur Challenges ........................................................................V I. Key Issues In Implementation of a New Natural Gas Supply Strategy ...... 1 A. lntroduction* .........................................* ........I.... B. Aissumed Policy Objectdves .............................................................I C. Potential Policy Mechadisn ................................................................ 3 D. Jiiportance of fe Domestic Regulawry Fnmework ...................................... 4 E. The Role of Govermmient ................................................................... 8 F. The Role of the Private Sector ......................................8............. .... 8 0. The Need for a Con1ezialtAdtf de ......................................................10 H1 T he R ole of O ther A genceits ................................. I1 L Tlhe Role ofFinancial Institutions .................. .................. ... ........ .... 1I J . The Inst tutonal .a .ewok.. ..... ......................... .............. ............... 12 K: O]pp>ortunitiews fonr CoUlalbo dn ...............................Ie 13 L. Conutracuetl Isusues ......................................I13 Mi. Key Issues ................................................................................. 14 II. Current Energy Balances and the Role of Gas ............................... 16 As. lDruary Enrg Sup ply a nd lDea ndmu ............................ 16 B. Historical Natural as Supply and Dlemand .............................................. 19 C. Gas Infrastructure ... 0 D. GUasPiS rctu e Cs ........................ .. ................. . ............. I 21 F. P otentialContribution of Nad GralGastoEnvirnmenrblU f3tal lIIIIrIoIIent III.. 21 0. Ps for Inc Indigenous Gas Production. ............ ...... ........... 22 H. (ConsuinerEncrgylricing I'olicies 230 I. I Froi c C.*oinecon to Iai.... . . .............. 23 III. Future Gas Demand and Supply ...00... 000.. 0..... 00000..00.00..0.02 6 A. FutureGas DemandinELswmEurope 27.................................................27 P Planned Expansion of Infiasrcui ................................. 28 C. Short T1ermi and IL.ong Taerm Gas Availability .............................................. 29 D. Supply Sctuity ............................................................................. 35 E . Suqpply CoDst Cdc M n ...... .......o.......... ...o............. ..... 3 9 F . S u pply Co)st CurIvers ...........................................I 4 1 G . F uwmu G as S upply anld DCemand...............................I 4 3 Tables 2.1 Priary Energy Demand by Fuel............................................. 18 2.2 MalRjor Gas l?Mchase Contracts with the Soviet Union ......................................... 20 2.3 USSR Export Gas Prices...... ..............................................2........ . ..21 2.4 Potential Increase in Gas Demand in Power Generation ........................................ 22 2.5 The Gas Import Bill of EasternEEurope .......................................................... 24 3.1 East European Gas Demand Forecast ........................................................... 27 3.2 East European Gas Demand Forecasts by Country (Base Case) .............................. 28 3.3 Investnent in Wrafnstrmucturne .............................................................. 2 9 3.4 Indicative Capital Investment Required to Increase Export ..................................... 30 3.5 Indicative Capital Investment Required to In ase Norwegian Export Capacity ........... 31 3.6 Indicative Capital Investment Required to ncrease Alerian Export Capacity ............... 32 3.7 Indicative Capital Investment Required to Increase Liby an Export Capacity.... .33 3.8 Indicative Capital Investment Required to Increase Qats Export Capacity ................ 34 3.9 Indicative Capital Investment Required to Increase Iranian Export Capacity ..... .. 34 3.10 Comparson of Soviet Security of Supply with otherPotental Suppliers ....................37 3.11 .P..ojected Euopean.. .......................Ga.t 44 Charts 2. 1 Primary' Energy Demuand Per Capita .......................................................... 1 6 2.2 Primary Energy Demand by Fuel ................................................................. 17 3.1 Gas Supply Options for Eastern Europe ...................................................... 38 3.2 Supply Cost Curve for Eastern Europe - Gas Delivered to Closest Border/Landing Point .... .. ............................ ..... 42 Appendices I Bulgaria .............................................................. 48 2 Czechoslovak.ia ............................... 5. 3 Hungary ............................ 60 4 Poland .............................................................. 66 5 Rormania ............................................................. 72 6 Yugoslavia ............................................................. 78 7 Overview of Forecasts and Assumptions Used ........... 86 8 List of Participants ....... ................... ............................ 92 Summary 1. As part of the process of economic development, the countries of Eastemn Europe need to consider how to structure their future energy supplies in order to satisfythe demands of a growing economy. In most of these countries, gas has so far played a relatively minor role, with coal being the dominant source of energy. Duc to an urgent need to improve the environment, several of the countries are now con g an increase in their namal gas consumpdon. Eastern Europe is thus facing a significant a .gate gas demand increase and needs to negotiate contracts for incremental supplies. Histortcay, all imported gas came from the Soviet Union. However, there is now a wish to diversify away from this source, pardy to reduce the risk of supply curtailment due to technical reasons. Key Issues 2. In considering future gas supplies for Eastern Europe, the following key issues need to be addressed: * The availability of costs of the supply options. e Consumer pricing and its effect on the economic viability of thb supply options. * The merits of a regional versus an individual approach to gas import projects. * The costs and benefits of supply diversification. * The availability and mobilization of project investment funds. 3. Natural gas could potendally be imported from several other suppliers, such as Norway, North Africa, or the Middle East. Each supply area has its own characteristics, largely determined by geology and geography. Some offer the possibility of gas reserves which can be developed at low cost, others have higher cost reserves because of their distance from the European market, or because the gas fields are relatively small or offshore. Some suppliers are perceived as very reliable in both the technical and commrcial aspects of a long term gas purchase agreement, others are perceived as less secure because of labor problems, technical difficulties or geopoitical conflict 4. East European buyers are likely to face very strong competition for available gas volumes from West European gas comanies, which have larger supply gaps to fill and are able to offer substantally higher prices. In ord to access additional volumes, East European buyers will need to make realistic assessments of the size of their gas markets and the levels of gas prices which users can afford to pay. The degree of supply diversification, as well as the premium which can be paid for it, should be detmined before the gas purchase negotiatons begin. 5. In developing energy policies the governments of Eastern Europe are confronted by tsks which are very complex and may be too difficult and dme-consuming to resolve. In forming their natural gas purchasing strategies, opportunities for cross-border cooperation should be exploited whenever possible. This may serve to reduce costs by increasing the opportunities #.o benefit from economies of scale and by increased negotiating power towards suppliers. The formation of one or more regional gas purchasing consortia may be desirable, and opportunities for cooperation with upstream partners may b desirable. 6. While the wish to achieve diversification of gas supplies is reasonable, it should be appreciated ftat gas from the Soviet Union is likely to continue to be the lowest cost supply available. The addition of new supply soures, while the bulk of supplies continue to be impored -ii- from the Soviet Union, may, from an economic point of view, be better than a major shift in supplier preferences. 7. Increased security of supply may be achievable not only thrugh diversification of supply, but also through construction of gas storge facilities. In addition to investment in new indigenous gas production and gs storage facilides where possible, it is essential that an appropriate gas pricing philosophy is adopted and that consumer prices accurately reflect the underlying economic COSts associated with the provision of gas supply. A rational pricing policy is likely to be a necessary condidon in order to atta Anvestment fron Western lenders, whether these are loans fom commercial or non-commercial sources, or equity funds. Western investors will require that new projects can ean an appropriate rate of return in a wide variety of economic circumstances and thus ensure that the best investnent decisions are made. Demand 8. Three demand scenarios have been created for each country, of whi the base case represents a "best estimate" given current plans and economic oudook, and the high and low cases indicate a reasonable range of uncerinly. In the base case scenario, it is envisaged that overall demand in Eastern Europe will decline inidally but return to its 1990 level of 80 BCM by 1995. The decline in demand is expected to take place in the industrial sector due to a combination of factors such as closure of noncompetitve and/or environmentally hazardous industries, increased energy conservation and initial end-use efficiency improvements. The decline in the industrial sector will be somewhat offset by growing demand in the residential/commercial and power generation sectors. After 1995, demand wil grow by 2.8 per cent per annum during the 1995- 2000 period and by 3.6 per cent per annum during the 2000-2010 perod. 9. Over the long term, the power generation and industrial sectors will account for the largest volume of gas demand. growth, though the residential and commercial sects will have the largest percentage increase in demand. 10. In the low scenario, economic stagnation ap to 2000 is envisaged, followed by economic growth after 2000. This scenario also assumes little improvement in energy end-use efficiency and lmited replactment of coal-fired capacity. 11. The high scenario, by contrast, assumes strong economic recovery from the mid 1990s and onwards, improvements in end-use efficiency and some replacement of coal-fired capacity by gas. No scenario assumes additonal development of nuclear capacity. East European Gas Demand Forecast (BCM) 1990 -TW~ W 2W05 UT0 Average Growth LoW 80.1 7.0 KW 973 1.5 1. Scenario Bawe CasMf 80.7 79._10.5 131.02. High 1020 133.0T 172.F : Scenrio _________ -Iiii Committed Supply and the Supply Gap 12. Indigenous gas production seems likely to decline very rapidly after the mid 1990s, without addiional discoveries. Curent output of 37 BCM p.a. will decline to 10-15 BCM p.a. around 2000, unless the intr3duction of better technology and higher wellhead prices encourages further exploratory efforts which are successful. 13. The Soviet Union can be expectd to extend its current contracts at levels similar to today, approximately 40 BCM p.a., and there are small volumes of imports contracted from Algeria and Irn In total, Eastem Europe may face a potental deficit of 35 BCM by 2000, rising to more than 50 BCad by 2005, and over 70 BCM by 2010. Westem Europe's potential deficit could be even greater, and calls into question the ability of the oil and gas industry to in'-.vst sufficient funds on a timely basis to enable demand to rise to the levels indicated. Failure to do so will result in scarce supplies and higher prices; Western European buyers are likely to outbid those of Eastem Europe for access to additional supplies. For the purposes of illustratng the deficit, a scenario of constrained demand in the second half of the 1990s has been used. Projected European Gas Supply and Demand Balance (BCM) __. .gT W 295005 T5TB |Western Europe . I . l Demand (Low Case) 260 296 309 329 350a Supply (Committied),,,_- ._l Indigenous 121 127 125 100 75 Norway 28 27 35 35 35 Soviet Union 55 64 64 64 64 Algeria 28 38 40 40 40 Netherlands 28 40 40 40 40 N'i en' 0 0 5 5 5 .Deficit O04$9l Eastern Europe: Demand (Base Case) 81 80 92 110 131 Supply (Comnmittedj ) Indigenous 37 36 12 13 14 Soviet Union 44 38 40 40 40 Algeria 0 2 2 2 2 Iran 0 3 3 3 3 Deficit 0 0 3 5 52 72l TOTAL D0 0 3 5 19 7 l a. Highc dand would be 460 BCM by 2010, and fte conding oa deficit 273 BCs Sup?ly Options: New Projects 14. There are many poltntial projects which could be developed to supply Eastern Europe, including: v A new pipeline flom West Siberia. * A pipelne from Ian viaTey. * A pipeline fom Norway to Poand via Germany or via the Baltic Sea. * A new pipeline fm Algeria via Italy. wiv o A new LNG teinal in the Baldc Sea to po gas fiom Noway. * A new LNG teinal in the Adriadc to import gas from North Africa or the Middle East. 15. The costs of several now projects which could deliver incremental volume of gas to Eastern Europe have been assessed. Necessarily, the cost levels must be regarded as indicative only and are regarded as bing accume to wilthin ± 30 per cent because they are not based on detailed pipeline Toute surveys, etc. Nevereless, they give an indicadon of the likely economic viability of the projects, and the large amounts of capital required Supply Options to Eastern Europe source Supply Options Up to 20Vt Investment Volume Requireda (BCM) (sbn) Soviet Lcremntal West Siberian gas through existing 1 10 Union network. Incrmental West Sibwian gas through new 14 35 Algenia Plpeae gas utough ansitooe. 7 S LNG from new plant to proposed terminal in Yugoslavia 6 5.5 Libyta LNd to proosed trminal in Yugoslavia6 to termina in YuLo avwa T____ Soviet Barents Sea gas delivered via new pipeline to 6 11 Union Polish border Norway Noth Sea gas via Emden and Md./Stea to 6 10 Litnov. Tromsoflaket gas (Snohvit) as LNG to Gdansk. 6 5.5 fran New pipeline from Iran through Tukey to 9 20 _Bulariasnborder ___ a. Inludes invetment required in unsmision/distribution In ature (includin Eastem Eorope), inremenal producton facilities liquec r ficon and sping 16. Of all the supply options studies, incremental gas volumes form the Soviet Union delivered through the exisng pipeline system would appear to represent the lowest cost option. At present, only 10-15 BCM of spare pipeflie capacit ieved to be available. Beyond this new production capacity must be developed and additional pipelines built. 17. Of the non-Soviet supply options, ranian gas would seem the least castly, but is not likely to be available before 2000. The cost of new Algerian pipeline gas or LNG is above $2M tu, which is sdtl considerably lower than the cost of Norwegian gas. .V. Supply Cost curve for Eastern Europe $1 '000 m3 160 12 13 $IMMDtu -4.0 140 120 O 11_I 100 56 7 9 3.0 80 2 2.0 40 11 | | _ - - L _ 1.0 0 20 40 60 80 100 120 150 *SCM p.a. Supply Options Dellveles from: I Iranian gas at Bulgarian border U 1994 2 USSR gas at Uzhgorod 3 USSR gas at Beregdaroc 01996 4 Algerian gas at Monfalcone 2000 5 USSR gas at Ismail 6 USSR gas at Brest-Litovsk 02005 7 North African LNG at Omisalj 8 Qatar LNG at OmisalJ 9 Norway Polpipe 10 USSR (Barents Sea to Brest-Litovsk) 11 Norway via Emden 12 Norway LNG at Gdansk 13 USSR Barents Sea LNG at Gdansk 18. When looldng at potential new supply sours, seious consideion should be given to Algeria and Iran. Both have large gas reserves and substantial volumes which could be developed for sale to East European buyers at a cost which is close to curent Euroe border prices, Algeria in the short to medium term and Ian in the longer tem Norway, en the other hand, seems to be a less attractve potential supply source bOCause of the high co of developing gas fields offshore Norway. 19. The Ianian gas pipeline project, which is presently being considerd, would need a price (at the Bulgarian border) of approximately $2/ tu t be cmiay viable. However, m order for new Norwegian North Sea gas pojects to be developed borda gas of between $2.85 and $3.20/MMBtu would have to be offered. -vi- Future Challenges 20. The economics of Easten Euope appear to face an impending gas supply deficit. For reasons of techical and commercial isk management it seems desisable for them to diversify their gas supplies by purchasing from suppliers other than the Soviet Union, thus developing a porfolio of gas purchase contracts from a variety of sources. However, for technical and other reasons, gas supplies from North Afdca, the Middle East and in particular Norway are likely to cost more than gas supplies from the Soviet Union. This is firsdy because the costs per cubik meter of gas of developing te fields and pipelines are higher, secondly because the gas companies will be obliged to pay in hard cuency, and thirdly because "sellers market" conditions may prevail over the next decade, and border prices are expected to be "bid up". 21. Accordingly, the gas companies of Eastern Europe face sevl challenges, and need urgently to consider their strtegies. Huge amounts of capital must be invested to mak-e incremental gas supplies available. It seems unlikely that sufficient funds can be generated within Eastern EDurope. Some external funding is, therefore, likely to be required. While institutions such as the WYorld Bank, EBRE, EIB, IFC, etc. clearly have a role, private sector sources of funds are also likely to be required, both from the financial community and also in the form of equity finance from Western companies. To the extent that financing cannot be obtained on attractive terms, or cannot b obtained on a tmely basis, Eastern Europe's gas market will be supply constrained, with potentially severe implicatons for the environment and for the region's economic and industrial develcopment. 22. There are a number of other imporiant items, in addition to financing, which must be addressed by Eastern Europe's gas companies as they seek to secure gas from non-Soviet sources: namely, whether cooperaion with other regional gas companies, or with Westem oil and gas companies is desirable in order to facilitate gas purchase and/or infrastructure development; whother the premiums, which are likely to have to be paid for supply diversification, can be supported by gas uses; whether high levels of take-or-pay commitment can be supported by gas users; and whether consumer prices for gas accurely reflect the true economic cost of gas supply. L Key Issues In Implementation of a New Natural Gas Supply Strategy for Eastern Europe A, Introduction 1.1 In this report, we aim to describe the current role that natural gas plays in the energy balances of Eastern Europe, and to identify its future potential. We will also consider the key policy issues that need to be addressed in developing natural gas supply strategies, both at the regional and national level. For such issues to be developed within an appropriate context, it is vital that national policy obiectives are clearly understood and made clear to potential investors, and that the full implications ofpcy measures to be implemented in order to meet set objecdves are considered. 1.2 To facilitate the review of these issues, the central importance of the regulatory framework in which the (public and private) gas production, transmission and distribution entities will operate is considered, together with the role of govenmment in creating the environment in which a gas policy can be successfully executed. The role of the private sector as well as other agencies and financial institutions is also addressed, as is the Potential for private ventures. At the regional le-el, the need for greater cooperation is discussed, together with the importance of a proper institutonal framework in which regional issues can be reviewed and opportunities for collaboration established. Finally, some areas for potential regional initiative are indicated. B. Assumed Policy Objectives 1.3 In seeking to consider the key issues in implementation of a new natural gas supply strategy for Eastern Europe, it is assumed that all governments in the area will set as their policy objectives a combinadon of: • A§surance of stable, long-tenm supply sufficient to meet expected gas demand inceases - Minimization of cost, both capital and operating costs, particularly in terms of foreign exchange * Maximum reliability of supply in tms of both physical and political interruptions e Rationalization of supply stategies in the European context. 1.4 Not all governments will give identical weight to each of these elements, but the differences are probably minor, since the structural variances in terms of supply autonomy within the gas economies are relatively modest (with the exception of Romania). Clearly, it wiU be essential that specific policy initiatives are undertaken that both rectify current weaknesses (for example by providing appropiate incentives for energy conservation via the price mechanism) and create conditions in which these policy objectives can be ealized. 1.5 Whilst many such policy ini'tiatives can and should be taken at the national level, there are likely to be significant potential benefits in cooperation at the regional level, not least in terms of: a) Minimization of transportation and storage costs via access to the economies of scale which are likely to be available to regionally oriented projects; b) Maximizaton of supply security via arrangements for supply back-up, as a means of sharing the "insurance premium" associated with supply diverification (an issue which is discussed more fully in Chapter 3, Section D). -2- 1.6 Such benefits would contribute greatly to the rationalizadon of gas supply strategies within the context of the European gas industry as a whole. It seems inappropriate for a single supplier to dominate the gas availability of Eastern Europe when that supplier may not be the lowest cost supplier. Each of the main suppliers to the European gas industry undoubtedly has a "natural sphere of Influence", based on distance to market, which is a significant determinant of costs. But within Western Europe, cooperation between gas companies has permitted a large element of supply diversificatdon to occur in most area and countries, and there is no reason why the same phenomenon should not occur in Eastern Europe. The integration of Western and Eastem gas infastructue by physdcal connection would permit an overall rationalization of gas supply strategies to be implemented. 1.7 Gas companies and the relevant competent authorities must recognize, however, the potential for conflict between short- and long-termn objectives. For example, a cost-effective method of enhanced gas supply secuity is to invest in dual-fiing capability in power plants and for large industrial users, thus improving security in the event of a shortage caused L, technical or other reans. But dual-firing tends to reduce the market value of gas in the country in question, by removing part of the premium which might otherwise be charged for gas, and giving it a value equivalent to thermal paidt with uel oil. Ihis undermines the ability of the gas company to offer an attractive price to suppliers at thd country's border, and therefore hinders them in achieving the longer term objective of greater supply security ia additional suppliers. 1.8 Success policyimlementation is likely to require: * Clear and coherent ardculation of the intended strategy to the entities charged with implementation. * Consistency of policy, with few, if any, changes in objectives, strategy or regulatory fameworiL * An appropriate approach to project financing, and, if relevant, to the involvement of private and/or foreign invests. 1.9 Since the focus of tis port is on natural gas, issues of general energy policy are not addressed in depth. Clearly, however, it is essential that gas policy is consistent with policies on other energy-related issues, such as, for example, energy pricing policy, which needs to be internally consistent. 1.10 In an open economy, tie energy pricing policy should ercorage a !evel of efficiency in energy use comparable with those of competitive economies. This is partcularly important where inefficient use of energy has dit balance-of-payments consequences. Naturally, however, such policies annot be pursued solely in relation to natural gas without the risk of significant distortion in the compettive position of otier fuels. Thus, a consistent energy pricing policy amongst all fuels is necessar iynw gas is to play its proper role within the domestic economy. 1.11 It is recognized a dtis raises complex issues, particularly in relation to domestic fuels. This is especially true for solid fuels, the production and use of which usually have important soCio-economic mplications. Nonetheless, failure to provide energy consumers with economic incentives tat encourage rational use of energy will only, in the long run, exacerbate economic difficulties. Thevey hl.h specific energy consumpon levels which characterize the econornies of Eastern Eumpe to a signicant extent reect the insulator of their economies from the competitive pressures of intnatonal energy pices. There is, therefore, the need to put gas policy within an overall energ policy context which is supportive of both broad economic goals as well as a specific role for gas. -3- C. Potential Policy Mechanisms 1.12 Clearly, the achievement of energy polcy objectives, such as the ones outlined above, raises a number of purely domesdc poiy issues including: a) Reduction in demand by promodon of energy efficiency (for example, through development of new housing insuladon standards, retrofitting of space-headng contols. elimnaton of heat loss, etc.) and through development of apprpriate energy pricing systems which provide consumers with proper mformation on relative and absolute energy costs and avoid direct or indirect subsidies. b) Enhancement of domesdc supply options through, where appropriate, development of natural gas exploration and production activity. This will require development of appropriate contal and regulay termm incsuding issues of: i) Prices paid to indigenous producer; and ii) Access to maket (including issues of access to infrastructure). 1.13 This is clearly one of the most irrortant policy issues. In order to attract investment in exploration and production, the expected revenue of producers must be attractive enough to co'npensate (and reward) them for costs incurred and risks taken. To implement these policy or,tions it may be necessay not only to increase gas prices paid to producers to levels comparable so those in other countries (to ensure that oppotunities for domestic production are not inpeded by inadequate financial incentives) but also to allow producers to contract directly with transmission and distribution companies, based on freely-negotiated terms. Failure to do so will inevitably impede the attainment of basic policy goals. 1.14 One possible pricing model would be to let prices paid to producers reflect the market value of gas to end-consumers, costs of transportaton, distribudon and storage (plus a reasonable margin to distributors and transpos). This model ensures dt producers are paid the maximum pice possible while maintaining the competitveness of gas against other fuels in the end-consumer market. 1.15 Another possible pricing model would be to base gas prices on recovery of costs of exploration and production, plus a reasonable return on capital invested. Producers tend to favor the first of these two pricing philosophies, since it allows them to assume the price risk, for which they are rewarded in times when prices on competing fuels are high. 1.16 Contractual and regulatory terms to be developed should also serve to reduce vulnerability to external supply interruptions via: * Increased fuel-switching capability and/or prioritization of use, in order to provide a response capacity to ensu continuation of economic acdvity in the face of supply interruptions, whether accidental or otherwise, and, * Development, where feasible, of enhanced storage capacity for nanural gas as well as, possibly, for other fuels. 1.17 In the same way, economic signals or other processes must be crated to enhance these policy options. In particular, the need to enhance fuel-switching capability can be achieved either by use of the price-mechanism (interruptible sales carrying a discount), by fiscal incentives (allowing accelerated depreciation of such investments), or by legislation (requiring certain categories of consumers to have the capacity to switch fuels). The choice of implementing mechanism may also have important implicaton for other policy objective For example, an -4- obligation to switch fuels under certain environmental condidons could, in effect, require certain types of users to install dual-firing capacity. 1.18 However, achievement of the broad policy objectives set out above may also require consideration of external issues. Cooperative action between countries may, for example, enhance the prospects of achieving policy objectives in a more cost-effective manner than is possible through the pursuit of purely national policies. 1.19 Such measures would include, for example: a) Optimization of infiastructure, both to increase utilization of economies of scale (for example, in the use of larger diameter gas transmission systems dtan would be available to a single economy) and in optimization of the use of existing transmission and distribution grids in order to mnimze the cost of system inter-'onnections. b) Development of increased regional supply security through: - Reduction of reliance on Soviet resources through the development of a diverse supply portfolio, including, potentially, Dutch, Norwegian, and Algerian gas; - Enhancement of the capacity to make up any reduction in existing Soviet supply, for example, by providing reverse flow capacity on the existing transmission systems from the Soviet border and the development of improved connections to enable new supply sources to be made available throughout the region; and e Agreement to provide back-up or stand-by supply in the event of unanticipated reductions in availabilites. 1.20 Whilst these effects might result from negotiations based on normal commercial interests, it seems likely that, in the first instance, government initiatives may be requirea to catalyze their development. In this context, the Pentagonal/Hexagonal initiative is particularly noteworthy. We anticipate that other collaborative ventures will be established. 1.21 Inevitably, the tensions between the objectives of minimizing the cost and maximizng security of gas supply have to be addressed. Whilst many of the internal policy actions aimed at reducing import requirements can be evaluated drimarily or exclusively in economic terms, other policy measures aimed at enhancing security of supply necessarily impose an additional cost on regional gas economies. Typically, supply security imposes a need for redundancy in infrastructure and supply capability. The incentives for cooperative acdon will be greatest where a demonstrable case can be made that the cost of such redundancy can be, in aggregate, reduced through coordination of activities. As is suggested below, it wSi be essential, if significant progress is to be made on idendfying and implementing such issues, that a clear framework is established in which such evaluation of the potential benefits of collaboration can be identified. D. Importance of the Domestic Regulatory Framework 1.22 In considering the development of a new gas supply strategy for Eastern Europe, it is difficult to overstate the imponce of the domestic regulatory fimework, as the main determinant of activity, profitability and risk within the domestic gas industry. The regulatory framework will: (a) Determine the stucture of the market and thus the opportunities for both domestic and foreign entities to enter individual sectors of the business. For example, a horizontal segmentaton into produ' tion, transmission and distribution funcdons (as is the case in Germany) would lead to a totally different market structure to the vertical integradon - - which characterizes France and the UK The extent to which the distribution function serves the residential sector, for example, as a quasi-regulated utility, while the industrial sector is served by the production and/or import system using 'open access' transmission systems, will create a very different market structure to one which is based on geographical exclusivity as in, for example, the German demarcation system. Thus, fundamental issues of market structure and inter-fuel competition will be determined by the framework of regulation set by government. It is important to note that, as is implied above, there is no single pattern of industry structure in western Europe. A vertically integrated industry structure, as is the case today in France, and has been the case in the UK, has been seen to create an imbalance of commercial strength between producers and the transmission/ distribution company. Thus, during the 1960s and 1980s, many UK's (UK Continental Shelf) gas producers felt that British Gas' monopsony (single buyer) position allowed it unilaterally to set prices, to the detriment of the exploration and production function. Against this, it is argued that it was not the vertcally integrted structure of the industry which permitted this, but the "landing requirement", which, in effect, required UKCS gas producers to sell exclusively to British Gas. Whatever the potential drawbacks of vertical integration on domestic producers, it is also argued that, where the industry is fundamentally reliant on a single major supplier (as is today the situation in Eastern Europe), vertical integration can balance the monopoly power of the foreign supplier with correspondihg domestic monopsony power. Horizontal integration to achieve the same objective might require coordination with the transmission sector to a degree which can give rise to concerns. Moreover, it implies a degree of regional segmentation which might be undesirable in some countries. Horizontal integration in the sense used in, for example, Belgium, where regional entities distribute gas and, typically, electricity and water, also raises concern over the effectiveness of inter-fuel competition. Clearly, gas and electricity compete in all applications except motive power and lighting, and creating integrated gas/electricity suppliers could impede the natural development of either fueL (b) Determine the ability of the transmission and distribution sectors (including, where relevant, imporers) to bear economic risk and so determine the contractual terns which they will be able to offer to suppliers. Accodingly, the capacity of individual entities to act as viable buyers in their own right and, so, to meet internationally-competitive obligations in respect of take-or-pay for natural gas, ship-or-pay for pipeline capacity and so forth, will be determined by the abitity of such resellers either to bear economic risks directly or to pass them through to the market. Traditionally, market risk has been assumed by buyers of natural gas, whereas price and production risk has been retained by sellers. For this system to remain viable in Eastern Europe - recognizing that a move towards open access systems in Western Europe might directionally diminish 'competitve' levels of take-or-pay - either the buyers of first instance would need to be viable obligors for the residual iability, or some other form of undertaking would be required to underwrite this commitment. It is in this area that the potential trade-off between competition and cost is perhaps most visible. An industry able to offer a high level of off take guarantees to a producer, and thus seek to negodate lower prices, will tend to be both highly integrated and have limited intemal competition. For consumers whose ability to switch fuels is restricted, this situation is clearly a matter of concem. On the other hand, a highly internally competitive industry, unable to offer internationally comparable levels of off take -6- security, is likely, in a peiod of potntial supply deficit, to be relatively unattractive to a supplier as a potential customer. Accordingly, East European buyers will face intense competition from westem gas companies who maybe abetter position to offer high levels of take-or-pay, and who may be able to pay premium prices. This issue is presently being debated within the Eurpean Community where, as part of the process of market integration, there is a strong political desire to increase competition within the gas industry. This is leading to measures intended to prohibit national import mono olies, to require pipeline owners to make capacity available to third parties, and to functionally segregate activities such as transmission, storage, distribution, etc. The cuirent saus of the issue of Thid Party Access in Western Europe is that a limited form of access seems likely to be introduced in 1993, when nominated companies (mostly gas transmission companies) will have access to transit rights through other transmission companies pipelines. This limited form of open access will be progressively widened, though the precise timetable is not yet clearly defined. By the late 1990s it is possible that many other groups, including indigenous producers and many large users or groups of users, may have access to the transmission gnd. This is a highly-contentious issue and there is a wide range of opinion on the matter. Generally, large industrial consumers and some distributors appear to be in favor of third party access, while transmission companies and some producers are not in favor of it because it would appear to increase business risks without the prospect of increased rewards, and may lead to a higher level of regulation. The consequences of this on the future of the gas industry within the Community are uncertain and widely debated. It may be that in a period of balanced or excess supply, producers would compete for a greater share of what is widely recognized to be a rapidly growing market, and bid down prices to the benefit of the uldmate consumer. On the other hand, it may be that the process will lead to increased prices (reflecting higher financing costs to sate for greater market risk), reduced supply security (reflecting a reduced capacity of te industry to support new projects) and consequendy lower growth in the market (c) Be a primary determinant of the attractiveness of each market both to suppliers and investors. Under a gas supply scenario of potential constraint, suppliers will regard as most attractive those markets which combine the capacity to flow maximum economic rent back to the wellhead with the capacity to bear the highest level of market risk. Suppliers will, therefore, be interested in the way that the regulatory framework affects the value of natural gas in the marketplace, the tariffication of transmission and distribution systems, their capac to uence sales volumes, and so forth. Equally, potential foreign investors in the transmission and distribuon sectors will be interested in the relationship between economic risk and reward which is implicit in a regulatory framework, as well as other fundamental dynamics of market growth and economic competitiveness. The issue of consumer price formation is clearly critical in determining the attractiveness of a market to producers and reseller, who typically prefer to be allowed to link gas prices to the prices of the fuels with which they compete - the so-called "market value principle'. Consumers, however, tend to regard such 'value-based' pricing as incompatible with competition. Equally, ransmission system owners and users tend to disagree on the rea economic ris associated with sucA investments and -7- therefore the approprate level of reward; the dispute is particularly acute in relation to the treatment of economies of scale. Given the volume of the gas industry, the tension between the tendcacy towards "natural tmonopoly" and the need to engender effective competidon needs to be addssed. However, such a balance needs to be reached in the context of broad economic policies: a high degree of price regulation in the gas industry could, for example, be inconsistent with liberal free market principles. 1.23 The role of government (national, regional or supra-regional) will be to correct any imbalance between the economic obligations required to meet broad policy objectives and the ability of the gas industry (whether publicly or privately-owned) to meet these requirements. Clearly, to the extent that, for example, buyers are unable to provide adequate off take guarantees or to assure payment in foreign exchange up to the level of 'competitive' supply agreements, others will be required to do so. Thus, to this extent, government acts as the 'balance wheel' of the gas industry. In this context, "government" could mean international agencies such as the EEC, EFTA, IEA, UNECE, etc. 1.24 In detennining an appropriate regulatory framework, the following questions need to be addressed: • What is the mission of each phase of the domestic gas industry (production, transmission, storage and distribution), and how is this mission translated into specific responsibilities and objecdves ? W What economic and non-economic risks does each segment bear and what rewards are appropriate to these risks ? - Are the current 'players in the gas industry' fully equipped to meet their mission and to bear the relevant risks ? I not, m what ways are they deficient ? If deficient, what steps need to be taken to overcome this ? o Is the allocation of risk and reward inherent in the proposed regulatory framework compatible with suppliers' concerns? * Can the economy in question offer a basis for a contractual arrangement which is attractive in the light of the anticipated supply/demand balance and other opportunities open to the supplier in question? If not, what changes are politically, economically and socially acceptable to remedy this deficiency? 1.25 Clearly, the historical development of the gas economies of Western Europe have led to a number of such models emerging. On the one hand, for example, France has traditionally operated its gas industry in effect on a cost recovery basis, creating a fully integrated monopoly/monopsony entity in Gaz de France, whereas the German system of private sector companies operating in a horizontal segment within a demarcated area on a profit maximizing' basis represents the antithesis to this approach. In the UK, it was widely regarded as implicit policy that, until the early 1980s, British Gas would charge opportunity-cost based prices to industry and simply recover the balance of its costs in the residential sector, in Belgium, on the other hand, there is some evidence that the residential sector has been regarded as being able to bear a high proportion of investment costs in order to keep industrial competitiveness at a high level. With the move towards completion of the internal European energy market, a degree of convergence appears likely, in the sense that the combined effect of a reduction in import monopolies, coupled with tax harmonization and moves towards open transit pipeline systems, is likely to remove some of the more basic differences between market structures. However, some differences are likely to persist. -8- E. The Role of Government 1.26 Classically, in developing a natural gas supply strategy, there are four types of governmental action which have an important bearing on industry structure and gas market penetradon. These are government actions to: * Set terms for natural resource development, in particular for gas exploration and production. * Determine the regulatory framework within which the gas industry operates in the context of national economic policies and programs, and determine the relative competitiveness of fuels through fiscal levies. * Consistent with the above, bear social/political risks and costs to the extent that it is not the mission of the gas industry to bear these costs. * Influence specific commercial decisions by the gas industry in a mamer consistent with overall national economic priorities. 1.27 As such, these government funcdons are not different to those in other sectors of a market economy. Differing implementation reflects the longer term commitments typically entered into by the natural gas industry, and the historical allocation of risks and rewards which have sten the market nrsk essentially borne by gas buyers. F. The Role of the Private Sector 1.28 The role of the domestic private (i.e. non-state) sector is likely, in the furst instance, to be limited both by lack of financial capability and, to a lesser extent, by the absence of an effective competitive framework. Both these deficiencies can, in time, be remedied, if attention is given to financial and organizational restructuring, coupled with management development programs. 1.29 As such, the domestic private sector can develop as the basis for a strong domestic gas industry, provided it is given a clear mission and objectives, and the resources to achieve them. Clearly, the domestic private sector is likely to reman, in the first instance, in the ownerslip of local, rather than central, government, unless ambitious privatization programs are followed. Whilst, in certain instances (e.g. TransOas in the C5FR), privatizatiof. may be achievable in the near term, in other cases the intoduction of private capital could take much longer. It is here that the role of the foreign private sector is of interest, both as a provider of capital and as a source of technology and management expertise. 1.30 Under attractive regulatory frameworks, considerable interest is likely to be shown in privatization of East European transmission and distribution operations. However, it will be necessary to draw a judicious balance between the national interest and the need to create terms which are attractive to foreign investors. 1.31 In Western Europe, the role of Govemnment varies considerably between countries. In France, Italy, Spain and Denmark the Govemment has a large role in the gas industry as the owner of the gas transmission company and as regulator of the gas industry has a high degree of influence over such issues as gas pricing. In Germany the gas transmission industry is largely in private hands, though local Government is involved in the gas distribution industry. The Netherlands features a parnership between private companies and Government in the transmission phase. Each country has a unique structure, reflecting the history of the gas industry in that country, the amount of indigenous production and the level of import dependence, the maturity of the industry, the general business culture and other fators. Accordingly, each gas company tends to have a unique -9- culture and mission, exemplified in its commercial relationships with other parties. Some see themselves as a "national utility", seeking to minimnze costs. Others see themselves as merchants, seeking to maximize profits. This tends to reflect the degree of Government involvement in the industry, via ownership and the degree of competition in the energy industries generally. 1.32 In Western Europe, otiy the United Kingdom has so far privatized the national gas company (i.e. transferred it from state to private ownership). Other countries in Western and Eastern Europe, and on other continents, are considering whether, and if so how, to privatize their gas industries. Drawing on experience in the UK, it is clear that it is necessary for the shareholder (usually the Government) to establish a clear set of conditions (or regulatory regime) for the newly- privatized company (or companies). The shareholder must also consider carefully the desired structure of the gas industry. Should gas producton, transmission and distribution be handled by different companies, or by a single company? Should transmission, storage and distribution be integrated functions, or segmented? Should companies cover the national territory or be given regional responsibilities? What monopoly rights should be pernitted and how should such monopolies be regulated? 1.33 The regulatory and institutional structure of te.e gas industry should preferably be defined before privatization takes place, as attempts to modify the regulations or industry structure post-privatzaton can be extremely complex, both from a legal and from a practical point of view. Some countries may wish to remove legal (de jure) monopoly privileges: this may not be sufficient tzo remove de facto monopoly situations in areas where a particular company has a dominant position. Governments must consider such issues carefully. 1.34 With respect to methods of privatization, there are several potential models. Firstly, G3overnments must consider whether they wish to partally or wholly privatize the gas industry. If partial privatization is the chosen option, does this mean that Government will retain an interest in each aspect of the gas industry, or will it privadze entirely one phase of the business (e.g. gas production) while retaining full ownership of other phases (e.g. transmission, or distribution)? Having decided what to privatize, the Government must then decide how to privatize. Several models are available. The Government could "auction" the industry, as a whole, or in parts, to the highest bidder, or it could negotiate with a selected list of companies in order to achieve a satisfactory outcome (but not necessarily to maximize price). Alternatively, shares could be sold to private individuals, financial institutions and trade investors. In selecting the most appropriate method of privatization, Government will wish to consider its attitude to foreign ownership (including repatriatdon of profits and dividends), corporate control and other related issues. 1.35 A particularly important issue in the context of the East European gas industry, and one which requires resolution prior to any potential privatization, is to establish which party, or parties, owns the gas industry today. In some- countries, the working hypothesis may be that the state or regional Governments own the gas industry: in others, the employees may be considered to be the owners. This issue is important because of the need to determine which party, or parties, should receive the proceeds of privadzaton. 1.36 Restructuring the gas industry, including possible privatization, may have many benefits. There may be considerable benefits in creating a number of companies specializing in a particularphase of industry, to facilitate management and the appropriate allocation of corporate resources financial, human and technical. This would allow companies which may currently be monolithic, but having a large number of diverse activities, to specialize in a small number of highly-related activities. For example, gas pipeline construction and engineering activities could be carried out by a specalist company acting as a contor to the transmission company, rather than being conducted in-house. By pedalizing and focusing, experience will be gained more rapidly and costs can be reduced. Restucturing may also bring benefits such as avoidance of duplicated activities; reducing the number of layers of managers between the operating companies and the executive functions; managerial and financial autonomy - being able to raise finance independently - 10- and not having projects being conditional on internal funding. Privatizadon may bring benefits - not only of restructuring - but also by facilitating technology transfer from foreign shareholders, and improving the ability of the gas industry to fund investments. Depending on the regulatory regime, it may also allow companies to determine sales prices more freely, and to manage their costs more effectively. G. The Need for a Commercial Attitude 1.37 In this context, the interface between, and possibly conflicting aims of, social and economic policies are of i. erest and need to be addressed. One such issue is the often quoted need to foster a more commercial attitude among East European gas industry participants. 1.38 The question arises: what is a "comnmercial attitude", is it desirable and how can it be promoted effectively and how can it be promoted effectively? By commercial attitude we are referring to the endeavors of: Companies (whether publicly or privately owned) to maximize the benefit to the organization and its owners (normally in profit terms), to operate and allocate own resources as efficiendy and effectively as possible (thus minimizing costs, maximizing benefits and maintaining a professional corporate image), and most importantly to respect the objectives and policies pursued by business partners and by the government (in so far as these are known or can be anticipated). Government to maximize the benefits to society at large, to allocate national resources and to implement policies as effectively and as efficiently as possible, and to respect and support the objectives and policies pursued by industry, where these do not conflict with the inteests of society. 1.39 The key ideas here are not only "maximizaton of own benefit" but also "respect for the objectives and policies of others". Only in an environment where such respect is present can fuitful negotiations be held, common ground established and solutions which benefit all parties be found. 1.40 The quesdon of whether a commercial attitude is desirable or not is clearly a political one. In the end, the answer will depend on whether its potential consequences are regarded as attractive or not. According to economic theory, the answer to this question is clearly "yes" -in a perfect market economy the fact that companies and consumers all strive to maximize their own benefit, while the government looks after the needs of society at large, results in progress - everybody gets better off all the time. Few of us are, however, living in perfect economies. Economic realities and relationships are mostly too complex to be transparent .nough to permit a simultaneous maximization of benefits on all sides. In addition, the economic environment is not static but subject to change, reducing our possibilities to comply with the theoretical economic behavior of rational individuals and organizations even further. In so far as there is a risk of expected commerciel developments deviating from the overall interests of society (the nature and contents of which will be decided politically), it may be necessary for the government to assume a balancing role to safepard those mnterests, carefully weighing the benefits and drawbacks of free enterprise and competition against those of increased regation and controL 1.41 To summarize, a commercial atdtude is, in principle, desrable from a societal point of view. Its actual and potential impact on economic, industrial and social development should, however, be monitored, and appropriate action be taken to encourage desirable, and discourage undesirable, consequences as and when necessary. - 11- 1.42 If it is decided that a more commercial attitude is desirable, the next question is, obviously, how it can be developed. In addition to longer-term actions like education and supportng legislation, the Governent can encouage its development by providing the necessary industrial and environmental conditions as well, as itself adopting and displaying a commercial attitude through: o Active promotion of competition and free enterprise X Active promotion of private and decentralizedownership * Encouagement of free commercial negotiations once the legislative and regulatory framework is in place o Refraining from market interference and re-regulation. H. The Role of Other Agencies 1.43 An important role can be played by other agencies (such as the EEC, EFTA, EBRD, IFC, UNECE, etc.), as a potential source of funds for projects which have a strong national interest. However, such projects may have limited commercial appeal (for example, system inter- connections to improve security, reverse flow capability for the same reasons, strategic storage projects and so forth). In addition, such agencies can provide a neutral forum for discussion both of inter-regional projects and public/private sector developments. I. The Role of Financial Institutions 1.44 Discussions with financial institutions suggest dta the commercial lending agencies are becoming increasingly concerned about project financing for gas developments, particularly for production projects and transportation projects which are in areas of current, or likely future, regional conflict. Accordingly, although commerci funds may be available to support large scale investment in Norway, with a relatively low level of equity investment therefore being required, it is unlikely that such institutons will be willing to support large scale investments in the USSR, parts of the Middle East, and possibly North Africa Comnmrcial sector support for a Yugoslavian LNG terminal and pipeline would be extremely unlikely to be forthcoming. This suggests that alternative sources of finance must be required. There are several possibilities: 1.45 Equity. If the banking community is unwilling or unable to advance the necessary funds for such projects, additional equity will be required. To the extent that local currency investment is required in Eastern Europe, the necessary equity funds can probably be made available relatively easily. If hard currency investments are needed, Hunganan entities may be obliged to turn to Western partners such as Total, BP, Shell etc. Such partners may be willing to invest but may seek access to local markets in return: for example, they may seek part of the shares of MOL or other Hungarian entities in return for becoming involved in the project. The costs of financing projects will clearly be higher where a larger amount of equity finance is required, because the investor bears more of the project risk. The level of risk borne tby investors will also be influenced by the degree of assurance of off take which buyers are able to offer. As the Hungarian tansmission system now permits third party access, MOL may not be in a position to offer high levels of take-or-pay to supplier, who may therefoe seek a higher price for the gas. 1.46 Mulfilteral aid agencies Severl agencies may be in a position to offer support to the East European gas industry in its efforts to enhance the level of supply security via diversity, including the World Bank. Perhaps the most obvious other candidates are the European Bank for Reconstruction and Development, and the European Investment Bank. These agencies have - 12- traditionally lent to state-owned enterprises. Others, such as the Internadonal Finance Corpomtion, have lent only to the private sector. This restriction is beginning to break down, with the World Bank now being able to support private sector initiatives. 1.47 Export credits. Many Western Govermnents are willing to provide a measure of fmancial support for projects by guaranteeing payment to equipment suppliers. Project investors have therefore been able to purchase equipment on less onerous terms than would otherwise have been the case. The best-known European export credit agencies are EWD (United Kingdom), Coface (France), Saice (Italy) and Hermes (Germany). Various non-Euroean countries have Ex- ImBanks which also offer support such projects. 1.48 Direct and indirect Government support. In the absence of other parties which are able and willing to accept risk, the party of last resort is likely to be Government. Only Governments tend to have the necessary financial strength and influence to be able to support certain projects: for example, they can "internalize" some of the commercial risks via appropriate regulatory mechanisms, such as by intervening in gas pricing issues they can remove market and/or price risk. Or they can directly invest in projects: the Belgian Government invested directly in the Zeebrugge LNG terminal, for example. 1.49 European energy charter. The current discussions with respect to the European Energy Charter, which are expected to continue through the early part of 1992, may provide the basis for facilitating technology transfer and inward investment into energy projects in Central and Eastern Europe and the USSR. This may enable grcater amounts of private capital to be mobilized to support the development of the necessary gas infrastructure and to underwrite the financial risks associated with long-term gas purchase agreements. In this way, the creditworthiness of Central and Eastern European gas companies would be improved and they would become more atcive customers for the suppliers. 3X. The Institutional Framework 1.50 A number of formal and informal groupings have developed in recent months to address a number of these issues, usually in the context of specific projects. Whilst such discussions are helpful and constructive, a broader institutional framework is likely to be necessary to address a number of key interregional policy issues. Such an institution could arise from the Hexagonal Initiative, for example, or have a quasi-permanent secretariat charged with responsibility for energy or gas issues. 1.51 These are likely to focus on consideration of two key issues, namely: * How inter-regional supply costs can be minimized and security of supply maximized, and e The extent to which goverments in each economy are likely to use common criteria in addressing such options and choices. 1.52 Clearly, the first set of issues is broadly one of information gathering and dissemination. The second, however, is more fundamental to policy determination, since opportunities for collaboration are likely to be determined by the extent to which common policy goals and objectives exist and can be evaluated on the basis of common criteria. 1.53 Such an institudon might be in a position to assist its members deal with issues relating to coLaboration in new gas purchase and infrastructure projects, and permit the necessary trade- offs to be acieved in order to balance the costs and benefits between the pardcipants on the buying - 13- side. On such a basis, a rational set of import options could be assembled, gas swaps arranged, gas transmission systems and supply arrangements optimized, etc., to the benefit of all. 1.54 Furthermore, such an institutional framework might allow governments to do more than facilitate the process of developing a new gas supply strategy, and allow pro-active consideration of regional projects of considerable social and political interest (such as strategic storage) which might have limited economic appeal to private capital. The structure, procedures and responsibilities of such an organization would require further review. It would be inappropriate to seek to identify how such trade-offs as may be necessary should be evaluated and resolve This is clearly a matter for the pardes concemed. K. Opportunities for Collaboration 1.55 It is apparent that a significant number of powentially collaboradve opportunides exist. These include: a) Joint infrastructure development, including: - Seasonal and strategic storage, possibly in depleted gas fields, aquifiers or salt domes. * System inter-connections, both to improve the flow of gas from existing sources, and to enhance the supply option from new potential sources (for example, by providing reverse flow capacity). o Blending and treatment facilities, to allow admixture of different gas streams. b) Joint purchasing, to achieve potential economies of scaie in infstructure (in the case of ING, receiving terminals and pipelines) and to provide !he rapid build-up to substantial volumes which new suppliers will regard as desirable in justifying new supply projects. For example, gas companies could form ad-hoc consortia for the purchase of Norwegian or Algeian gas, such as the Hexagonal Iitiative. c) Intra-regional trade and security agreements, under which fuel substitution programs would allow gas to be diverted under pre-determined conditions, to areas which might face supply interruptions, whether for accidental or other reasons. 1.56 However, certain other key issues will need to be addressed, including: * The possibilities for intra-regional competition to atta foreign (external) capital and technology, and e Intrinsic differences in industry structure, profitability or creditworthiness, which might impede intra-regional collaboration. L Contractual Issues 1.57 Gas purchase contacts are a means of allocating risk and reward between buyer and producer. There are dtree principal types of risk: v Geological risk, which is taken by the buyer in a "depletion contact" (the buyer agrees to buy all of the gas in a particula field), and which is taken by the seller in a "supply contrt" (the seller agrees to deliver a specified volume of gas over a given number of -14- years). Potential suppliers to Eastern Europe can be expected to sel gas under "supply contracts". * Marketrisk, which is noay taken by the uyer, who islely to berequWred to agree to a high level (80 or 90%) of a-Pay: in other words, to guarantee payment for a substantial proportion efsthe ps of whether there is a market for it when it is delierable. * Price Aisk, which is normaly taken by the seller. Various contractual mechanisms have been devised to share risks. For example, in the 1970s, buyers were tequesod t take most of the price risk by supplies, by agreeing to a "floor-price" - a minimum prie for the gas. 1.58 The type of contacts likely to be sought by Newin Algeian or other suppliers can be expected tO differ sigficantly from those historically available from the USSR to Easten European buyes Such suppliers are likely to requirthe following types of terms: * 20 years supply ageements * High levels of "take-or-pay": probably 80-90% * iigh load factor off take (7000-8000 hours p.a) * Payment in US dollars or Deutsch Marks * Three-yeady price reviews * Escalation of the gas price on a quarterly or monthly basis, reerenced to petroleum products M. Key Issues 1.59 It is suggested that the key technica issues to be adressed include: e What technically and economically feasible supply options exist with broad regional appeal ? * What realistic capital, technical and human resources constraints exist on the development of regional gas expansio ? 1.60 The key political issues which rmght be addressed include: * What level of "insurance premium" is approprate and reasonable, to achieve supply diversity ? * How might this be allocated on a colaborative intra-rgiona basis ? * What steps need to be taken to proceed bet to explore such oprnities ? 1.61 Each company and country has unique characteristics, but each shares the wish to enhance gas supply security, probably via diveriy. It is not the purpose of this document to recommend pardtcular strategies: rather, it is intended to prvide a basis for establishing the extent to which coflaboration is desired and is cor.-idered feasible, and to identify the necessay next steps. This may involve the formulation of gas purchasing onsotia, or consorta for developing infrastructre. - 15 - 1.62 The main supply diversification options are to purchase gas from Algeria (via pipelinc or in the form of LNG) and from the Middle East (via pipeline or in the form olfLNG). Each of these options (and others) is discussed in more detail elsewhere in this document, in the context of individual countries. - 16- IL Current Energy Balances and the Role of Gas A. Primary Energy Supply and Demand 2.1 This section discusss, energy supply and demand in six East European countries (Bulgaria, Czechoslovakia, Hungary, Poland, Romania, Yugoslavia) as a region. First, we will examine enar demand per capita, then analyze historical energy demand by sector and energy supy by fuel, and finally specifically assess the hlstorical role of gas. C langes in energy demand Tlbye described and differences between countries emphasized. 2.2 y energy demand per capita. The six East European countries are very different in terms of industy sucture, indigenous energy resources, PoPulation, etc. It is therefore difficult to analyze the historical energy demand of the region as a whole, without makdng references to the characteristics of individual counties, or to compare individual countries. However, an estimate of historical energy demand per capita provides an indicadve measure of energy use adjusted for the size of the country and its economy (in terms of populton). Chart 2.1: Primary Energy Demand Per Capita TOElCapita 5,_ 4 -. . ... . ..... ..... 3 ---- Bulgaria Czech. Hungary Poland Romania Yugo. E. Ebope OECO 19_ 0 to 1989 sovrce: International Energy Agency 2.3 Czechoslovakia and Bulgaria have the highest energy demand per capita, the former consuming aLmost 4.7 tonnes of oil equivalent (toe) per capita and the latter about 4.6 toe per capita. Poland and Romania rank next at about 3.1 toe per capita, while Hungaiy is slighty lower at 2.9 toe per capita Fially, Yugoslavia has the lowest energy consumption per capita at about 1.9 toe. Over time, none of the East European countries have showed significant changes in per capita energy consumption relative to Western Europe, indicating that there is scope for energy conservation. A modest increase in energy consumpdon per capita was seen in Yugoslavia from 1980 to 1989, while only slight increases were registered from 1980 to 1989 in Bulgaria, Czechoslovakia, Hungary an Romania. A decline in energy consumption per capita was egistered in Poland. - 17 - 2.4 In comparison with OECD Europe, the per capita energy consumption of the six East European in total m 1989 was approximately the sme, at 3.2 toe. The similarity in per capita consumption is explained not by comparable energy use but by the considerably lower use of transport fuels per nhabitant (0.6 toe per capita in OECD Europe compared with 0.3 toe per capita in Eastern Europe). Per capita energy consumption has remained relatively constant in both areas during thie 1980s. Chart 2.2: Primary Energy Demand by Fuel =Coal 1Oil 9 Gas MNuclarit1ydio 100% - - - 100% 75% . 25% 50%- 0% 80 89 80 89 8089 808o9 808 89 I 80 89 Bulgaria Czech. Hungary Poland Romranba Yugo. OECD Europe Source: intmational Energy Agency Ststics, Unied Naions 2.5 The six countries show several similarities to each other in terms of their energy fuel mix, in comparison to OECD Europe and the way in which it seems to be developing. Among these similarities are a continued reliance on coal, which in most cases has a share of primary energ demand well above that of OECD Europe. The share of oil, which reaches levels similar to those of OECD Europe only in Romania, has been declining in all countries from 1980 to 1989; while natural gas has inmcreased slightly (except in Romania, where it is declining due to the drop in indigenous gas production). 2.6 Three factors help to explain these trends. Firsdy, coal is an indigenous resource and reeves are large. Hence, use of coal does not require hard currency expenditures. Moreover, the dominance of coal has further been enhanced by a lack of pollution control, an issue which is now beginning to be addressed. The use of coal also satisfies social and political employment objectives and has provided a least cost alternative to nuclear power, which, since the Chernobyl accident, may have become less acceptable. 2.7 Secondly, oil use has declined as a result of the continued stagnation and general contracdon of the East European economies. In paricular, growth potential in tansport fuels such as motor gasoline, jet and diesel has been limited by the employment of consumption restriction measures. In addition, supplies have been constrained, since the Soviet Union has capped or reduced oil supplies to Eastern Europe in favor of increased supplies to Western buyers. - 18- 2.8 Thirdly, the share of natural gas in primary energy demand has increased slightly despite constant indigenous production. An overall gowing demand has led to increased imports from the Soviet Union. 2.9 Coal demand and supp,. Coal use and trade in Eastemn Europe is dominated by Poland. About 80 per cent of Polands own total energy needs are satisfied by coal, a protion that has remained constant since 1980. bn addidon, Poland, along with the Soviet Union, is a significant hard coal ex porer to other East European countries and the West. Poland's coal exports are mostly bigh qualit hard coal, and, as such, have the potential to help both Poland and the surrounding countes to meet future growth in energy demand and in improving the environment. lbe coal used within Poland has, so far, however, been of low quality. Exports to both Eastern Europe and the West ar cected to continue in order to provide Poland with a major source of hard currency. 2.10 The Czechoslovakian eneW supply mix is also dominated by coal, which accounts for around 60 per cent of total supply. However, Czechoslovakian coal is almost entirely low quality, and recent environmental concerns may prowmpt a reduction of coalrs share of energy supply in the future. In an effort to alleviate quality concerns, Czechoslovakia trades brown coal or lower sulfur hard coal from Poland. Table 2.1: Primary Energy Demand by Fuel MTOE Oil- Gas Coal MuclearM -TOT I ______________ H ydro 1980 |Bulgka1. 3.2 14.8 2.2 3. CzechosIovlda 18.6 7 45.7 1T. 73.4 Hn 171.S r 9.2 28 6 Poland3 8.8 97.6 - 0.3 1X4.6 Romn WV9 32.4 --S.3 1 68.9 -Yugoslavia -16.1 X Io0 =120 2.4 33.3 l1989_ Rulg 13n 3T 1_ 4.4 41.2 Czechoslovaldka 15.2 9.2 41.2 72.6 Hun=n Y: 7.2 4.6 3. an 1 93.2 O.S 18.9 s Roma iT17. 32.3 21.6 72.7 YuFoslaia 1 6. .8 18.5 3.2 44.0 Souwce iRa Sitad 2.11 The other four countries (Bulgaria, Hungary, Romania and Yugoslavia) have a more balanced energy supply mix in which the share of coal ranges from about 25 per cent to about 40 per cent. The quality of coal in these countries is a major concern, as the use of it causes significant problems with sulf and ardicul*te emissions. All Eastem European countries have indigenous coal productin, with onlyBulgaria being a net importer of coal. 2.12 Oil demand and supp(. Broadly speaking, East European countries during the 1980s acted to increase the use ofnatral gas (imponrted from the Soviet Union) and to develop nuclear power stations. The reasons were on the one hand the intention to reduce the reliance on relatively expensive Soviet oil imports, and on the other the absence of a real altnative, since the supplies of oil fiom the Soviet Union were constained, and often temporaily curtailed in favor of - 19- Western buyers. However, after the Chernobyl accident the majority of nuclear plans were dropped and oil imports (particularly for use in power generation) continued. 2.13 East European countries are unprepared for any significant growth in oil demand. While selected countries have limited indigenous crude oil resources, the refining and distribudon systems have generally not been well maintained and will require substantial investment. Furthermore, the lightenng of the demund baml (characteristic of the growth of transportadon fuel demand), and increased use of natural gas, will require refinery upgrading and investment in new downstream residual processing units. Additional investment will also be required at the distribudon and retail levels. 2.14 The countries which appear most prepared for changes in oil demand are Hungary and Romania. Both countries have indigenous oil reserves and are currently producing oil, though neither is self sufficient. Moreover, Hungary has seen a decline in oil demand during 1980-89, a trend which is expected to continue, albeit at a slower rate in the future, thereby reducing dependence on declining and unpredictable Soviet supplies. 2.15 In fact, oil demand has declined in the whole region, except in Romania, where domestic reserves and production are quite large. The decline in oil demand occurred almost entirely in the early 1980s, and has since 1986 remained relatively constant. 2.16 Hydro and nuclear electricy. Hydro and nuclear power accounted for about 6 per cent of the region's primary energy supply during 1989, up from 2 per cent in 1980. Selected countries such as Yugoslavia have significant hydro resources but are severely limited by development and infrastructure investment costs. During the next ten years, hydro developments are expected to increase somewhat (dtrough the help of institutional loans) but capital constraints will continue to place downward pressure on any significant expansion. The future of nuclear power programs m many East European counties is uncertain and mozatoria have been placed on new construction projects. Apart from the public opposition resulting from the Chernobyl accident, many countries would have technical and economic difficulty with expansion of nuclear plants without fte assistance of the Soviet Union. B. Historical Natural Gas Supply and Demand 2.17 Eastern Europe has become increasingly reliant on natural gas resources both from indigenous and imported sources. Although the share of gas in primary energy demand has not increased significantly overall (only rising from 17 to 19 per cent from 1980 to 1989) gas demand increased by an average of almost 2 per cent per annum. This suggests that gas demand growth has sadsfied incremental demand rather than displaced other fuels. More importantly, incremental demand was satisfied by additional imports from the Soviet Union, which rose by an average of 7 per cent per annum during 1980 - 1989. During the same period, indigenous production in the region as a whole declined from 45 to 40 BChf 2.18 East European gas consumption is concentrated in the industrial (including petrochemical) and power generating sectors. Pipeline transmission and distribution systems are established in most of Eastern Europe, permitting the residential and commercial sectors to consume about 20-30 per cent of total gas demand. 2.19 The Soviet tJnion exported over 60 BCM of gas through Eastern Europe to Western Europe in 1989. In addidon to that, the countries which originally constructed the pipelines were comwpensated with gas which served as a transit fee. Now that the pipeline infrastructure is in place, there is limited potential for many East Eurpean countres to increase gas imts fo te Soviet Union to the leve that is required to meet future demand unless existing pipeline capacityis expanded or new in c added. . -20- C. Gas Infrastructure 2.20 The natural gas pipeline networks of Eastemn Europe show varying degrees of development and market coverage. The gas markets of Czechoslovakda, Hungary and Romania are relatvely well covered while Bulgaria, Poland, and Yugoslavia have relied more heavily on other fuels and therefore have less developed gas pipeline networks. In some countries, infrastucture was developed to distribute indigenously pduced gas, while in others networks were developed mainly to import or transit Soviet exprt gas. 2.21 In all countries, there is a need to invest heavily in refurbishing existing pipelines and replacing compressors, and extending the tansmission and distribution systems. In particular, it would st1m desirable to construct a series of relatively short pipelines to link the systems of neighboring countries where these are not already in place, provid, of course, that the economics of such projects are favorable. The purpose of such pipelines would be to provide additional supply security in the event of technical difficulties as other parts of the system age and are refurbished. D. Major Gas Purchase Contracts 2.22 In 1990, Eastem Eilrope imported 45 BCM of gas from the Soviet Union. Gas import contracts between former Comecon countries and the Soviet Union differed from their Western European equivalents in that they were rolling contracts, i.e. valid for five year periods after which they were automatically renewed, although with price and volume adjustments. Imported gas was usually payable either in transferable rubles, which in some cases could be translated into bartered goods. We believe that the rates at which rubles were Wanslated into barter goods differed between the individual countries. Table 2.2: Major Gas Purchase Contracts with the Soviet Union Annual Deliveries Deliveries Duration Country Contracts Volume Began to End Years .____ ___ _ ___ _ BCM a Bulgaria I 2.9 1976 n/a II 2.7 1980 g n/a m_________ III n/a 1989 n/a Czechoslovalda 2.7 980 1991 12 II 4.75 1995 2005 17 Huingary I 2.7197 1992- II 1.9 1989 1998 10 Pbland 1 t 1979 1998 20 II 2.7 1989 1998 10 Roa -wia I 1. 397Y n/a 12? II (1.5?) 1989 n/a Yuslavia I 1 1.3 1 2003 15 Source: Anhur D. Lino a. Bilhiou standard cubic metres @40 Al/m3 2.23 Gas was in many cases also supplied under separate agreements as compensation for pipeline construction services rendered to the USSR or, in the case of Czechoslovakia, Hungary -21- and Romania, as transit fees. Earlier this year all contrt were converted to hard currency terms, resulting in a substantial price increase. It has been indicated in the press that the Soviet Union is now considering formally going back to contact foms allowing barter payments, as very few cash payments for gas have in reality taken place since tie conversion to hard curency (though they have for oil). Table 23: USSR Export Gas Prices $/MMBTU- TM7-l 1980 1X 11 198 10980 ~i9 EastEurope I0.27 I 1.22 1 2.96 1.79- 1.06 0.83 0.91 I 2.75 West Euroe . . . 1.6 .5 Source: Soviet Energy: An bs Accoumt 2.24 Clearly, therefore, gas imports are a major component of Eastern Europe's trade balance. Assuming that the 1991 price of $2.75/MMBtu (equivalent to $100 per 1000m3) applies equally to all East European countries, the total annual i bill is appximately $4.7 billion, or broady equivalent to 1.1 per cent of East Europe's GNP (at official exchange rates). E. Industry Structure 2.25 With the exception of Yugoslavia, energy industry structures in East European countries have up to now been reladvely similar large, state owned organizations governed by ministries with control over all aspects of energy production, trade and distribution. Several countries are now in the process of ireor zng and privaizing their gas industries. 2.26 The details of the industry structure for each country are given in the relevant country sections in the appendix to this reporL There is no unique model, just as there is no "correct" way of organizing the gas industry. Some countdes, such as Poland, have historically had a fully- integrated gas producdon, transmission and distribudon company. Other countries, such as the CSFR and Yugoslavia, are organized on a regional basis. 2.27 Reorganization and privatization of industies is seen as a step in the process of transforning centrally-planned into market economies. The potential benefits to be gained from decentalization/ privatization of ownership and control and introduction of competition are increased inflow of foreign investment, increased economic efficiency, increased international compedtiveness, and uldmately a contribution to economic recovery. Whether or not all these benefits will be reaized will depend on the ability to atta foreign investment and the speed with which restucturing is able to take place. F. Potential Contribution of Natural Gas to Environmental Improvement 2.28 Atmospheric polludon poses serious problems in all East Euopean countries. Lack of environmentally accepted technology and awareness have contributed to an increasingly serious level of environmental damage for which corrective measures need to be implemented. The solution of closing down polluting plants and industdes and replacing them with environmentally friendly alternadves is, in most cases, not a viable option, because new plant cannot be buit sufficiently quickly. 2.29 If natural gas was used to rlace coal in power geneaton, substantial environmental improvements could be achieved. Similar effect could result if new, clean coal technology power -22- plaits were installed. The shortage of capital rsources, however, prevents fast progress on this front, which is fiuther obstructed by the lack of indigenous gas reserves and the prospect of long term commitments to increased imports payable in hard ;urrency. Several countries are very concerned and actively seeldng solutons to these difficult problems. It sees liely that within five to ten years, some progress could be made towards displacing heavily-polluting fuels, such as lgnite, by natual gas, but that it may take between ten and twenty years before the levels of S02, NQx and prtculate emissions can be stabilized. Table 2.4: Potential Increase In Gas Demand in Power Generation Electricity Potential Realistic Potential Realistic From Coal Gas Fired Gas Fired Gas Burn Gas Burn Capacity Capacity BCMC BCMd GW2 GWD j Bldia= 23 5 3.2 _O 4.5 O a ctoslovat 47 33 6.7 1 9.4, 1.4 ia IHun- 7- 25 1.1 0.4 1-S 0.6--- |Poland 133 92 18. 1 2. 14- Ylugoslavia 57:7 __ 37_ _ 2 9.4 2.8 Source: Arhr D. Little a. Potentia for gas in power gera_io meaurd in teums of CCaT capacity eqied if all oal-red capacity was to be replaced (asuming load factor of 60%). b. Realistic pondal fof gas in power geaon, in tms of simated CCGT capacity that could be built in he short term (up to 1995, asuming load factor of 80%) c. Potential aS bumn if al coal fied capacity was replaced by CC¢Ts (asmuing efficiency of 50%). d. Realistic forast of gas demand In power generadon, given estimated CCGT capacity that could be built in the short term (assuming efcieoncy of 50%). 2.30 It may be appropriate for Governments to indicate their commitment to higher environmental stndards by iposing additional taxes on the fuels which contribute most towards atmospheric (and other forms c!) pollution, or by mandating higher standards of environmental protection at new industial and power plant, and probably at existing facilities as well. This would have the benefit of increasmng the value of natural gas in the market (on the basis of gas being valued at its "oppomrnity cost") and therefore making it economically viable to build new pipelines and to obtain gas imports from higher cost areas. G. Prospects for Increased Indigenous Gas Production 2.31 Romania, Hungary and Poland have significant indigenous gas production while Bulgaria, Czechoslovalda and Yugoslavia produce only small amounts. Total reserves in Eastern Europe (proven and probable) have been at some 500 BCM and cuTently some 45 BCM of gas are produced annuaUy, compared with annual imports of 45 BCM. Production facilities and transportation systems are in most cases in need of repair and upgrading, and underground storage capacity needs to be incrased in orde to meet winter demand peaks. 2.32 Although gas reseves are very modest if measured on a world scale, there are several areas in Eastern Europe with good potential for new discoveries which, if commercially viable, could help reduce dependence on energy imports and thereby improve prospects of a faster .23 - economic recovery. However, Western capital will be an essential requirement for all exploraty activity. 2.33 Bulgaria, in general, and the Black Sea are viewed as having the best prospects. Exploradon activides are being catried out in the Bulgarian, Romanian, and Soviet sectors of tie Black Sea. Other areas with recognized potential include southeast Poland (pardcularly from coal- bed methane) and parts of Yugoslavia. Given that foreign investors can be atacted to explore for petroleum in these areas, and to provide the capital necessary to improve recovery on existing fields by replacing outdated and inefficient equipment, it seems likely that at least part of future demand increases could be covered by inci;ased domestic producdon levels. 2.34 It is not possible to forecast future production levels without a detailed geological survey of each prospective basin, and an assessment of likely exploration and production costs. Based on US experience, we anticipate that it will be possible to at least maintain, and probably slighdy increase, indigenous production in most countries. If the initial promise of substantial reserves of coal-bed methane in Poland can be fulfilled, then indigenous production could rise significantly. HX. Consumer Energy Pricing Policies 2.35 The price of energy relative to other goods has traditionally been low in most East European countries. Unlike Western Europe, residential prices were often substantially lower than those paid by the industral and power generating sectom Market reforms have tended to raise the price of energy faster than the rate of general inflation. This trend has been strengthened by the move to hard currency trading for imports from the Soviet Union. 2.36 Several countries are now increasing their efforts to move towards a market economy by liberalizing prices, with huge relative price increases as a consequence. In September 1991, Romanian gasoline prices were reported to have been raised to world market levels. Household lectricity prices in Czechoslovakia were increased by 70 per cent on October 1, 1991. Czechoslovakia's Federal Economic Council has decided that prices shall be liberalized grdually until they reflect market forces. In Hungary, energy prices have doubled as the govemnment has c,ut subsidies. Price reform is an essential step, and should be used to avoid misallocadon of resources and giving the wrong incentives to both users and producers. The liberalization of prices is a necessary exercise on the way to full market economy, though a painful experience with price inflation and reduced living standards-among its consequences. 2.37 Price liberalization is now well underway in most East European countries, a fact which makes analysis of historical prices relatively meaningless. In the country secdons of the Appendix, we have indicated the more recent gas pnces which have been made available to us (not for al countries). It should be noted, however, that these may have changed substnally since they were recorded. I. From Comecon to Hard Currency 2.38 Since January 1991, trade between the Soviet Union and the former members of the Council for Mutual Economic Aid (CMEA) has fornally been settled in hard currencv based on world market pices. Though this policy has been implemented on paper, it appears not to have been fully activated immediately. Payment in kind is sdll far more common than hard currency cash payments. Neither the Soviet Union nor East European countries are likely to be prepared for the dislocations that could occur if this policy were put into practice. Three such potential consequences of this tansiton are: -24-* a) A rapid increase in the prices of goods and services imported by Eastern Europe from the Soviet Union, and subsequently, a large potential outflow of hard currency reserves. It is estimated that Poland alone would be forced to pay an additional $1.2- 1.5 billion per year if an immediate move to market pricing was enforced. Just one of many commodities - oil - is sold to Poland, at the equivalent of about $21/tonnes while the intenaional market is rading similar quality oil for about $125/tonnes. b) A virtual cessation in trade between CMEA counties and the Soviet Union because the East European countries do not have large hard currency reserves with which to pay for imports at market prices. c) A competitive disadvantage for the Soviet Union if the six East European countries were to form a trading block (as has been suggested) and sell essential parts, components (some of which are not produced outside the CMEA countries) and technical assistance, on which the Soviet Union relies, at higher prices. 2.39 Oil export reductions have affected, and will continue to affect, Eastern Europe since the Soviet Union has cut back deliveries by about 30 per cent due to lower production and the necessity to trade with the West. Furthermore, the East European countries have lost the ability to re-export Soviet oil deliveries from which they previously earned significant amounts of foreign currency. Hence, a dual effect is felt: Eastern Europe will import less oil and, in addition, not be able to generate hard currency from re-exports. Obviously, alternative oil supplies are available, but it is questionable whether Eastern Europe has the abiit to pay for imports without 'special' nancing arngements. 2.40 With gas, although prices have increased, and will continue to increase to market levels, the Soviet Union will still need to pay transit fees for using the pipelines located in Eastern Eue to make deliveries to Western Europe. The reality of this situation suggests that the pipeline owner (i.e. the East European counties) should be recovering transit fees to cover operation and maintenance costs and provide a return on capital invested in the pipeline. Major questions of rent sharing between the Soviet Union and East European countries arise, as pipelines are an essential link to major West European markets. Table 2.5: The Gas Import Bill of Eastern Europe 1989 Importsa 1989 "Soft", 1989 Hard Hard BCM Currency Cost Currency Cost Currency $ Billion $ Billion Cost as % of 1989 GDPb Bulixana ~~6.1 0.3 0.6 1.1 CS_ 1. - Q5 _ 1.2 16 Hun 3.9 0.3 0.6 16 Poland T7.9 - 3 0.3 0.8 Romania ~~7.4 - 0.3 0.8 1.5 ia - 5~~~~.4 0Q4 5 .6 0.4 Total 44;.6 3 .8 47 . Souse Arhu D. LiWe a. From de Sovie Union b. _ ,adjusted for h& don .25- 2.41 A compadson of Soviet ruble gas exports to the CMEA six in 1989 with their potential value under hard currency trading at world market pries suggests that the higher price imapact on Eastern Eurpe will be tremendous. The shock has already been seen in 1991 as shortages of all energy supplies have occurred due to a lack of hard cency with which to make purchases. In the futre, Eastern Europe is likely to requir lare loans pm the West to pay for energy imports, or a reversion to previous tading pcices with the Soviet Union or its consdtuent republics. 2.42 Soviet natual gas exports to Easter Europe, which in 1989 totaled 44.6 BCM, cost an estimated $2.0 billion under CMEA wading angements at an average price $45.69/1000 m3 ($l.2lftMBtut at a "realistic" ruble exchange rae of 0.49 $/R. The official exchange rate is 1.589 $/R). With the present had currency gas price of $2.75/MMBtu or $104.27/1000 m3 the same imports would cost $4.7 billion. Further moves to market-based pricing are likely to have very serious impacts not only on national account and tade balancs between Xc former CMEA countries and the Soviet Union, but also on the supply and demand for gas within the region. -26- M. Future Gas Demand and Supply 3.1 In this secdon, we compae the projected gas demand, in the forthcoming two decades, of both Eastem and Western Europe with the gas we believe could be made available fiom new and existing supply sources at various points in time. We will begin by reviewing our demand projections for Eastern Europe as a whole. The bases and assumptions used for our demand forecasts are described in detail in the A Subsequendy, we will describe curently planned expansion of L in Eastrn Eumope, and evaluate whether planned transport capacides will suffice to deliver supplies satisfying prctd increases in demand. We will then go on to review -urent and future avaability of gas from various supply sources, and the perceived relative suppiy security of individual suppliers. 3.2 We have calculated the costs of gas delivered to a border or landing point which would be most conveni4ntly located for deliveries to the East European markets. Delivered costs have been calculated firom six potendal supply sources along ten alternadve international transport routes. 3.3 In the final section, we will combine our conclusions reached in previous parts of the chapter, and discuss their implications. The purpose of this exercise will be to indicate: - The volumes of gas which could realistically be made available to East. European markets from import sowces. * The degree of competition for new gas between the markets of Eastem and Western Europe and its likely effect on inteional gas prices. o The inimum price which would have to be paid in order to ensure that new projects ire developed and brought on stream in time to meet future gas requirements. * The possible cost advantages which could be gained from inteional cooperation. 3.4 Clearly, there is a complex set of relationships which exist between gas supply, demand and price. There is also an important set of relatonships between gas supply, price and production and tansmission costs. 3.5 Higher prices are likely to cause producers to make available greater quantities of supply, but to constrain demand. Low prices have the reverse effect. Short un price effects can be minor, for example in the residental sector, for which the price elasticity of demand is low, or can be major, for example in the indusil sector. A small change in gas prices can have a major effect on gas demand, depending on the relationship between oil prices and gas prices, and the extent to which consumers can switch between tie two fuels at short nodoe. 3.6 In general, the principle of boier price being equivalent with, or close to, long-run marginal costs can be observed in the gas industry in Westen Europe. However, it is not easy to define with pecision at what level long-run margina costs are at any point in time, as this depends on what is meant by "long-run' (2 yeas, S yeas, 10 years ?), and what discount rate is used by inves These reladonships are e ely omplex in prctical terms. -27- A. Future Gas Demand in Eastern Europe 3.7 We have construtted t demand scenarios for each country, of which the base case represents our "best esdmate" given curmnt plans and economic outlook, and the high and low cases indicate the range of uncertaint suirounding the forecast. In our base case scenario, we project that overall demand in Easten Europe Initialy will decline, returning to its 1990 level of 80 BCM in 1995. The initial decline in demand is assumed to take place in the industrial sor, being due to a combination of factors such as closure of noncompedtive and/or environmentally hazardous industries increased energy conservadon and initdal end-use efficiency improvements. The decline in industry will be somewhat offset by growing demand in the residentialcommercial and power generation sectors. 3.8 Thereafter, demand will grow by 2.8 per cent per annum during the 1995-2000 period and 3.6 per cent per annum during the 2000-2010 period. Over the long term, the power generaton and industrial sectors will account for the largest absolute share of gas demand growth while thie residential and commvial sectors will have the largest percentage increase in demand. 3.9 In our low scenario, we have assumed a continued slow to stagnating economic growth until 2000, with real economic growth and improvement of living standards not taking off until after the turn of the centry. The low scenario also assumes litde improvement in energy end-use efficiency and limited replacement of coal fired capacity. 3.10 Our high scenario, by contast, assumes strong economic recovery fiom the mid 1990s and onwards, impiovements in end-use efficiency and some replacement of coal-fired capacity by gas. No case assumes additional development of nuclear capacity. 3.11 The total demand of ghe six East European countries will amount to between 79 and 81 BCM in 1995, 86 and 102 BCM by 2000 and 110 and 173 BCM by 2010. Given present prospects for future indigenous production levels and continuation of presently contracted deliveries from the Soviet Union, tis implies a supply gap of between 3 and S BCM by 1995,43 to 79 BCM by 2005 and 53 to 117 BCM by 2010. Table 3.1: East Europeen Gas Demand Forecast r BCM 19,0 W O~ 1995 TU5~ zOT2010 Average Growth Low Scenatio 86.7 -8g.4 7 1O3 1. Ban Csi _9S1D.5 131.0 -. 3.12 Of the countries studied, we believe ta Yugoslavia (given present energy policies) will experience tie largest growdt in gas demand, followed by Poland and Cwchoslovakia. -28 - Table 3.2: East European Gas Demand Forecasts by Country | BC,- NM -19 I 19Avrge; -i Growth Bulgaria _ 6.63 . 7.4 _ 9 SCzechoslovakia 2.7 -1 3.7 16.8 20 .8 26.0 -3.6I u-- 11.3- - - - Poland I0.1 11.1 13.35 16.7 21.2- 3.8 l Roma ~~1 33.2- 30.3 33.2 3.7 al.1 YuWosavia . . l9'l. 4.1 Total . 80.7- ? 9.7 191.6 109.6 130.,9, 2.5 B. Planned Expansion of Infrastructure 3.13 If plans for increased consumption of gas in Eastern Europe are to be realized, gas transportation infrastructure will have to be extended significantly to allow for incr-ased supplies of imported gas. Thus, several new pipelines leading into the area are being planned, including one from the Soviet Union to the Polish border, one from the North Sea via Denmark to Poland and one from Iran, which would lead across Turkey and deliver gas to the Balkan countries. In addition, a link is planned between the Yugoslav and Italan networks, through which Algeian gas is to be imported into Yugoslavia. 3.14 Other projects include interregional pipeline cectons, mainly intended to link up the systems of the countries closest to the Soviet boder with those further away, in order to improve the capability to import Soviet gas. Also being consideed is the construction of an LNG terminal near Rijeka or Krk, which could supply not only Yugoslavia but also Hungary, Austria and Czechoslovakia with Algeran gas. These projects are described in more detail in Section C below. However, it is far from certamin whether al these plans will be realized within the time frames considered, as most East European countres suffer from a severe shortage of financial resources. Weste technology and financing may therefore be required. 3.15 Conclusions. Given our forecasts of energy demand, Eastern Europe will need additional supplies of between 30 and S0 BCM in 2000, growing to between 50 and 120 BCM in 2010. We expect part of these requirements to be met by increased indigenous production of gas from upgraded e g or yet-to-be found new gas fields. Existin i s esdmated to have a spare capacity of between 10 and 15 BCM per annum. Present plans foresee new pipelines to the area and LNG facilities adding a total transport capacity of around 40 BCM (including the Iranian pipeline to the Bulgarian border). If all new demand is to be met by imports, additional transportation capacity of 35 BCM and 105 BCM will be needed in 2000 and 2010, respectively (excluding presendy planned capacity addidons). Unless signifiant new indigenous resoures are found, it seems clear that if gas demand is to be allowed to grow as foreseen in national energy plans, substandal new investments will have to be made in tan n infirastrucue to the area 3.16 It is not possible to esdmate the total amount of investment which will be required without knowing which of these projects will proceed. Not all of them will go ahead. The total broad cost levels associated with the infrastructure are shown in Table 3.3 (to an accuracy of ±30%). 3.17 It will be a major challenge to mobilize the necessuy investment in order to allow such projects to go ahead. At a dme when the West Europan gas industry appears to require investment commitments of approximately $200 to $300 billion over the next 10 yeas or so, and the -29- worldwide oil refining and oil tansportation industries need to make huge investments in environmental prcion, there would appea to be a probability that te funds cannot be obtained to allowthfe gas indusry to realize its fuillpotendiaL Table 3.3: Investment in Infrastructure Pro ect Approximate cost $m n imnal in ugos6 , socae pipelines -200 Pipeline from USSR 1330 Pipeline from ian 74M0 Pipelne frm Norway (Troll) 5500 LG ShD (Dervessell 250 C . Short Term and Long Term Gas Availabiity 3.18 USSR. Currendy, the Soviet Union is exportng annualy some 60 BCM to Westem Europe and some 45 BCM to East European buyers. An incrase in deliveries from Western Siberia would require expansion of the production facilities in West Siberia, or development of the Yamal ara, both of which hold sufficient additional resves that could be produced at relatively low production cost (the huge field sizes result in ver low unit production costs). New pipelines would however have to be built, as the spare capacity of the existing system at present is only about 10-15 BCM per annum. 3.19 Substantal volumes could also be released for expt if the efficiency in gas utilization within the Soviet Union was improved or tansmisson losses in the eistig on system were minimized by upgrading/refurbishment of pipelines and comp . Ali these measures would, however, require large sums of capital invesmet, wic may be difficult to rai in the short term, though we understand Snam has reached agreement with Oazprom to undertake compressor and pipeline refiubishment. 3.20 We have calculated indicative capital investment required for S pipeline projects and 1 LNG project, which are given in the table below. We esdmate typical project lead time to debotdeneck existing facilities, from the dme a decision has been mad and financing has been arranged to fist deliveries, to be around two to three years. A new pipeline from Yamburg could technically be built within five years, whereas the lead dme of a development of the Barents Sea resvzves is estated at 10-12 years. 3.21 Norway. Currently, Norway is supplying some 27 BCM of gas (per annum) to Westem Europe. In order to supply Eastern Europe, the existing pipeline network in Gernany would have to be extended eastward, as for example is now occurring with Wintershall's Midai/Ste;al system and parallel developments by Ruhrgas and VNG. Alternatively, a new offshore pipeline could be built, for example, via Denmak to the Polish coast, and then south to Czechoslovakia and Hungaiy. 3.22 In order to increase its ability to supply substantial new volumes tO Europe, Norway would have to develop large new reserves such as Sleipner West or the Haltenbanken fields. However, Sleipner West gas has a high carbon dioxide content, making it difficult and costly to develop, and the location of the Haltenbanken fields off northen Norway would lead to a very high cost of gas dedivered to the European coas -30- Table 3.4: Indicative Capital Investment Required to Increase Export Capadty of the Soviet Union (New PipelinesING; Excluding Production) Supply options Vu rnvestment l________________________ BCM $ billion West Siberia to PoLish border 13.3 (Brest-Litovsk) - Polish border to Warsaw ) +0.4 West Siberia to Uzhgorod 3( 14.2 - Uzhgorod to Prague (10) +1.0 - Uzhgorod to Warsaw (5) +0.4 - Uzhgorod to Budapest (5) +0.4 West Siberia to Romanian border S 0. (Ismail) - Romanian border to Bucharest (2.5) +0.1 - Romanian border to Sofia (2.5) +0.1 Barents Sea LNG to Poand( 5.8b (including liquefaction and regasification)l Barents Sea pipeine gas to Poland 13 5.2 (Brest-Litovsk) TO LUSSR 60a 51 l a. Figures in the b t not included in total since they would not increase marginal deliverability ( it is unlkely, for example, tht both a Barents Sea LNG project and a pipeline fiom this area wwu be malized). b. Inluding cost of shps 3.23 The North Sea fields which are being developed, or considered for development at present, are all relatively small, and will probably, to a large extent, be used to substitute the now postponed initial volumes from SleipnerEast. Gas from the Troll Phase 1 development is, given presently planned production and transport capacities, already committed to Western buyers under the Troll Agreement (i.e. if all options are taken into account). It seems likely that more gas will be found in the Norwegian part of the North Sea when exploration activities in this area are restarted, but until such time possibilities to expand production significantly beyond the above mentioned projects seems limited. 3.24 Based on past experence, we estimate Norwegian North Sea gas projects to have technical lead times of up to 8 years, while Haltenbanken reserves would take up to 10 years, and Troms gas (located off the orthernmost coast of Norway, including, for example, the Snohvit field) up to 12 years to develop. 3.25 Algeria Algeia, already linked to Westem Europe via the Transmed pipeline to Italy and exporting LNG to several West European buyers, has substantial reserves of gas. Prven resves in 1990 amounted to 3,750 BCM, to which up to 1,250 BCM could potentially be added. The current production rate is close to 100 BCM a yea of which about 50 per cent is reinjected after LPG extaon. Some 30 BCM are currently committed for export to West European buyers (growing to 40 BCM in 2000). We are not aware of plans to increase gross or net production at the main gas field, Hassi RMel, before the late 1990s. We believe however that a fmther S BCM per annum could be made available imnmeiately for 20 years without damaging ultmate recovery. -31 - Table 3.5: Indicative Capital Investment Required to Increase Norwegian Export Capacity (New Pipelines/LNG; Excluding Production) Supply Options Voumie Investment BCM $ billion Via EmEOtoSFR border 10 3.5 - CSFR border to Prague (5) +0.I - Prague to Budapest (5) +0.1 - CSFR border to Polish border (5) +0.1 - Polish border to Warsaw (5 +0.5 Via Denmark to Polan d 4.5 (Niechorze) - Niechorze to Warsaw (5) +0.3 - Niechorz to Pague (5) +0.4 - Niechorze to Budapest +0.5 Norwegpan LNG ! tto Poland 5.5 2.7a (includmng liquefaction and regasification)__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Total Norway 23.5 14.7 a. liuding cost of ships 3.26 The current gross capacity of Hassi R'Mel exceeds 100 BCM per annum. Production was 86 BCM in 1989, approximately 90 BCM in 1990, of which up to 60 per cent was reinjected. Reinjection is unlikely to fall below 50 per cent before 2000, leading to a net output of 50 BCM per annum, unless Sonatrach's views on reinjection change. 3.27 Production will, however, increase - developments in the Amenas/Rhourde Nouss/Gassi Touil areas over the 1990s will add approximately 14 BCM per annum to total production capacity. These volumes could potentially be made available by 1995, but are more likely to come on stream after 1996. 3.28 Given current export commitments, Sonatrach is left with a deficit of 6 BCM by 1995 and 15 BCM by 2000, depending on deliveries to the USA, which are flexible under the Panhandle contract, and the timing of the Shell contract. Further investments in more capacity to increase producdon are therefore required. 3.29 Existing pipelines leading from Hassi R'Mel to Arzew, where a potendal new LNG plant would presumably be located, have spare capacity of around 40 BCM. There is around 9 BCMof "spare" nameplate liquefaction capacity. Contrt have recently been let for refurbishment of existing plants to alow for a return to nameplate capacity. We believe Sonatrach is about to let further cont to inrease annual producton capacity by a further 6.5 BCM. Refurishment lead time is estmed at 3 years. 3.30 In order to expand Transmed, new sub-sea lines would have to be built. It has now been decied to bild an additional line across the Meditemnean (extending the theoeical capacity from approximately 7 BCM to approximately 21 BCM per annum), primarily to serve Italy, but also to supply small volumes to Yugoslavia. Curent coitments in Transmed amount to 20.2 BCM, but the line will be considered fully udlied even after the expansion, as 4 BCM of reserve capacity is required for reasons of supply security. Accordingly, we believe a second new subsea line is about to be announced with the possibility of a third. Transmed expansion projects are esdmated to have a technical lead dme of two years. -32- Table 3.6: Indicative Capital Investment Required to Increase Algerian Export Capacity (New Pipelines/LNG; Excluding Production) Supply Options Volunae lnvestment l ____________ BCM $ billion Via Transed 5 3. Monfalcone - To Belgrade (5) +0.9 - ToPrague (5) +1.0 - To Buapest (5) +0.4 - To Bucharest (2.5) +1.1 LNG to Omisal- 5. 2.41 - To Belgrade (5) +0.9 - ToPrague (5) +1.3 - To Budapest (5) +0.5 - To Bucharest (2.5) +1.2 Total Algeria 10. _ 12._ a. Iuding cost of ships 3.31 The Algerian supplier Sonatrach, together with Morwco's SNPP and Enagas of Spain, is proceeding with plans to build a pipeline from Hassi RMel to Spain via the Straits of Gibraltar. The purpose of Phase I of the project is to supply Morocco and Spain, but a subsequent phase envisages selling gas to France and Germany via this pipeline. Accordingly, Algerian production capacity may need to be expanded in the late 1990s, and almost certainly post 2000. However, this seems unlikely to cause a large increase in production costs, though this may depend in part on the location of future exploratory efforts. 3.32 At present, Algeria does not supply ,as to Eastern Europe. A contract is likely to commence in the early 1990s, for 0.6 BCM per annum to be delivered via the TransMed line to INA of Yugoslavia, with the possibility of expansion to 2 BCM later to other Yugoslavian buyers. Analysis of the costs of delivering Algerian gas to Eastem Europe, which is described in more detail elsewhere in this document, suggests that Algeria has a competitive advantage over other suppliers for deiveres to several Eastern European countnies, especially Yugoslavia and Hungary. 3.33 Libya. Like Algeria, libya has large gas reserves which are estimated to be in excess of 1,500 BCM. Proven reserves in 1990 amounted to 1,220 BCM, with an uldmate potential of 2,000-2,800 BCM. Libya is still reladvely unexplored, with two thirds of the reserves in onshore areas. 3.34 The reserves are located primarily in the Sirte Basin in the south east of the country (holding 650 BCM. Other areas with hydrocarbon reserves are the Ghadames Basin (in the south west), with approximately 170BCM, the Bouri Area (offshore) with around 7OBCM, and the 7th November fields (300 BCM), located in an offshore development zone shared with Tunisia. 3.35 Libya has a theoretical potential to export 20 BCM per annum by 2000. The current poducton rate is around 14 BCM a year. Twenty per cent (2.8 BCM) of this is exported to Spain. 'This volume could easily be increased by further development. Technical lead times are similar to those of Algera -33- Table 3.7: Indicative Capital Investment Required to Increase Libyan Export Capacity (New Pipelines/LNG; Excluding Production) uppy opion Vojjue Investment BCM $ billion Libyan LNG to 5.5 2.4a - TOBelgade (5) +0.9 - TOPfuue (5) +1.3 - ToBu (5) +0.5 - TO___ _ (2.5) +1.2 Total i MSa 5.5 6.3 a. lcludbg cost of dhips 3.36 Past problems of foreign investors, discouraged by concerns over contractual stability and political as have however so far severely hampered the pace of development. Contract disputes with Spain and Italy over gas prices have also contributed to a less than favorable reputation in terms of supply security. In addition, only the Barcelona and La Spezia LNG terminals have treatment facilides for Brega LNG, which contains higher hydrocarbons that must be separated from the gas before it can be fed into a transmission system. The Brega plant is now being revamped by the addition of an LNG extracion facility to permit a more standard quality of LNG to be exported. 3.37 Qatar. Qar's vast gas resources are contained in the giant North Field, located in the waters offshore Qatar in the Persian Gulf. The North Field is an extension of Iran's South Pars field. Proven reserves are 4600 BCM current producton is 6.5 BCM per year. BP, Total and Qatar's national petroleum company (QGPC) and Japanese partners are planning the development of an LNG scheme based on deliveries from the North Field. The Japanese utility Chubu Electric has bought the planned output of the future plant; an annual 5.5 BCM of gas in the form of LNG. 3.38 We are not aware of an additional LNG project being considered at present, but would not rule out this possibility if willing buyers can be found. We have calculated the costs that would be involved, indicating the prices that East European buyers would have to offer in order to encourage firther development of Qatars export potential to European markets. 3.39 Given the long sbipping distance to Japan, and the reladvely sniall volumes planned to be exported under the present agreement, the planned LNG harbor facilities are unlikely to be utilized to full capacity. If additional LNG trains were to be built, harbor facilities could prtsumably be extended at moderate cost to accommodate increased shipping volumes, or even used as they are. -34- Table 3.8: Indicative Capital Investment Required to Increase Qatar's Export Capacity (New PIpelines/LNG; Excluding Production) r Supply Opton Volume Investment BCM $ billion Qat 2ti 3a.5 3.4a TcOB flWe (S.S) +0.9 To Pe (S.S) +1.3 To Budapcst (5.5) +0.5 ToBucha (5.5) +1.2 Totl___ta_.5_ 7.4 a. hxIncg cowt of sbi 3.40 Iran. Iran has proven reserves of gas of around 14,200 BCM, and is currendy producing only 20 BCM per annum, largely consumed domestically. The country has tried to encourage Qatar to participate in joint further development of South Pars, and to share some of the costs involved. However, while Iran is planning to build a large pipeline (capacity 30 BCM or more) to Eurpe, of which approxiely 20 BCM night be sold in Europe (the balance in Iran or Turkey), and furher pipelines to Pakistan and ndia, Qatar wishes to concentrate on exporting LNG to the Far East. 3.41 ian is developing the North Pars field at a cost of around $4.0 billion. Technically, the gas could be onstream in 1995. However, in order to make the European pipeline project economically viable, Iran has to find buyers for the full 20 BCM per annum to Europe, who are willing to pay the premium required to trnsport the gas to European markets. Irn also has to overcome its perceived image as a polidcaly unstable source of supply. So far, Iranian gas has not been able to compete with alternative gas sources in supplying the markets of Western Europe, though it has had a contract to supply Bulgaia via exchange withte USSR (now canceled). Table 3.9: Indicative Capital Investment Required to Increase Iranian Export Capacity (New Pipelines; Excluding Production) -ptiontios Volume Investment I ______________ BCM $ billion To Bulgarian border 20 7.4 l To Sofia (20) 0.4 To Belgrade (18) 0.7 To Bucharest (2. 0.2 Total Ira n 2_ . . 8.7 3.42 UK. In the medium trm (mid l990s to 2000), we estimate that UK gas will be available at the UK beach at a cost of between $ 2.55/MMBtu or higher, as the remaining cheaper reserves will by then have been contracted Assuming that the cost delivered at the beach of Continental Europe would be the same, the delivered cost at, for example, the Czechoslovakian border would lie mn the vicinity of $ 3.2QfMBtu, or more. Although the UK would thus be able to compete with Norway in cost trms, the price obtainable in the gas hungry UK market would be considerably higher, even if end consumer market values were the same. Thus, unless East European buyers are prepared to pay premia of $0.75/MMBtu or higher, no UK producer can be -35- expected to be willing to export to Eastern Europe as long as there is unsatisfied demand in the UK. 3.43 The Netherlands. The Netherlands are facing a similar situation to the UK. There are too many potential westem gas buyers caPable of outbidding East European competitors on the way from the Netherlands to the borders of Eastern Europe to make it realistic for the limited amounts of a4lditional Dutch gas that will be released for export in the next two decades ever to reach these markets, unless an existing buyer, such as Ruhrgas, is willing to release some of its portfolio to another country, perhaps in the form of a joint venture (as has occuTred in the former GDR). 3.44 Conclusion. In conclusion, from an availability point of view, the most likely alternative supplier to the Soviet Union in the short to medium term seems to be Algeria. In the medium to long term, Iran, Libya and Qatar could be regaided as potential additional sources. In the case of Norway, we find it more difficult to predict substantial short to medium term future exports to Eastern Europe, as it is unlikely that sufficient volumes can be made available at a price which is acceptable to buyers and which adequately covers the investment required on the part of the producers. D . Supply Security 3.45 Security of supply is a relative term which is used to express the extent to which the risk of default connected with gas deliveries to a cetain market or customer can be mninimized. 3.46 The degree of supply security in a gas market depends on: • The long-run availability and accessibility of sufficient gas volumes to cover expected growth in demand Oong-term supply security); and i The degree to which the risk of involuntary supply interruption due to, for example, a temporary inability of individual producers to deliver according to contract can be minimized, e.g. dtrough diversfication (short-term supply security). 3.47 In this context, it may also be worth describing the two different types of short-term supply security between which we usually distinguish, i.e. a technical and commercial supply security, where the former refers to likelihood of interruption of gas production due to technical reasons, and the latter to other non-technical causes of supply interruption, such as breach of contract due to price disputes etc. 3.48 Eastern Europe has up to now relied on the Soviet Union for a large part of its energy needs. In recent years, both oil and {s supplies to Eastern Europe have been constained due to production problems within the Soviet Union. Field production problems associated with poor labor relations, non-availability of spare parts, severe weather, etc., and gas transportation difficul- ties caused by pipeline ruptures, leaks, etc. have sometimes meant that supplies have been curtailed. West European buyers are believed not to have suffered curailments to the same extent as East European buyers in the past, perhaps because of the more ataive prices which were paid by Western buyers until recendy. 3.49 The supply difficulties of the Soviet Union seem likely to deteriorate further. The curent polidcal instability seems certain to disrupt the availability of spare parts and to interfere with producdon and maintenance operations. The fragmentation of the USSR into its constituent republics, and the possible disintegration of some of the republics themselves, suggests that the supply problems will not be resolved quicldy by internal action, an instability which prevents extenal partners from negotiating suitale arrangements to allow them to assist in resolving supply -36- problems. Accordingly, dependence on the USSR for gas supply becomes more risky (from a purely technical point of view) as time progresses, undl political stability retuns. 3.50 After decades of political and economic dependence, the East European countries now wish to diversify away from the Soviet Union as single source for imported gas. This diversifica- tion is an attempt to ensure that the gas volumes needed to satisfy demand are delivered as specified. 3.51 Supply diversification is effectively an insurance policy, assuming that new suppliers are equally or more secure. In order to secure their own ability to supply consumers with gas and minimize vulnerability to supplies being interrupted (for example as a result of temporary production shut downs), gas importers build up gas supply portfolios, consisting of contracts with several suppliers, possibly backed up by strategic storage. 3.52 Different suppliers are regarded as more or less secure in terms of the extent to which they can be relied upon to deliver gas according to contractual terns. Thus, the addition of an individual supplier can add more orless to the overall risk of a supply portfolio, depending on how "secure" he is. 3.53 In Table 3.10, we have evaluated all realistic potential suppliers to Eastern Europe according to aspects we perceive as important to supply security, and ranked them on the basis of total supply security (being the sum of the weighted average scoresl). It should be noted that aspects and weightings chosen are based on our own perceptions of suppliers, and are therefore subjective. The weights have been chosen arbitrarily on the basis of our own evaluation of individual suppliers and their contract and production histories to date. In this context it is worth mentioning that historical evidence on Lbya, Iran and Qatar does not exist, which serves to explain their high proportion of neutral "grades". This may obviously distort the overall evaluation somewhat. 3.54 Conclusions. As can be seen from Table 3.10, we would, on a long term basis, rank Algeria as the most secure supplier and the Soviet Union as the least secure supply source from the perspetive of an East European buyer. Regardless of how critically individual altenative suppliers are viewed, it would be difficult to deny that some of the most fundamental current weaknesses of the Soviet Union collectively serve to undermine its perceived security of supply in relation to those of other sources. Thus, in order to increase overall security of supply, all of the alternative suppliers evaluated would represent possible candidates. I In order to indicate order of supply security, we have used a common methodology for mnuerical anysis of qualitadve information: (i) Slect relevant aspects of supply security on the basis of potental to influence future security as a supplier. For example, producion history is a very relevant indicator (ie. past occrrnces of intrupted gas flow due to teWical reasons. etc....). Gas quality, which also varies between supply sources, would not necessaily be relvant, unless te is risk of displacement of intupd volumes by differet quality gas. (ii) Weight aspects in order of importance (based on subjective pcepidons). (iii) Evaluate each supplier against aspects and gradW them.+l if thdei performae contnbes posively to supply security, -1 if it seves to reduce supply security, and 0 if their peforance has a ustral effect on supply security. (iv) Multiply "grades" by weights. (v) Divide sum of scores for individual suppliers by the suq of weights to obtain overal supply security ranking. -37. 3.55 Diversification of supply sources spreads the risk of unplanned gas shortages to several suppliers, thereby reducing tota risk and increasing secwity of supply. iAke an insurance policy, it carries a premium in the form of higher cost per cubic meter of gas purchased. The larger the number of addidonal suppliers, the greater the cost nor unit of gas imported is likely to be. The reason for that is a combinadon of the smaller volumes at would be purchased from each supplier and the large differences in production and transpatdon costs between different sources. Table 3.10: Comparison of Soviet Security of Supply with other Potential Suppliers Aspects of USW Norway lgeria ETy" Iran Qatar Weight Supply Securitys. Size of re--TFes -+ - O R/P rato+ + + + + + 5 Own consumption + + i 4 in relation to !!Pn Disiance to mariet O + Capacity utilization - Production . + + 0 0 0 5 - Transmdon 0 0 0 0 5 Contract hstoiy + + 0 0 P nhistory + + O O O 4 -r-~~ + 1F ~ -s ty ~~~~~~+ + W T + toidcal sta b l t - + =~ . - . Ris of naonal + + + + disintegation I__ Risk of structural + + + * 2 change (industry Risk of political O 3 intervention Needforhard + + + O currency _ _ _ _ _ _ _ _ _ _ _ Need for new investnent in order + + + 0 . 5 to expand/maintain exports ASiity to at+ + . + 3 investment Imporance of . O 3 Eastern Europe in mm portfolooo Overall supply 6 T I 4 T security ranking (weighted) a. Aspwts weightednin orde of import S ical; o r pat. .38- Chart 3.1:. Gas Supply Options for Eastern Europe JL ~~From Barents Sea a ~ Brs itvs 1t- Warsa b\ Uzgrd2Pau a~~~~~ Bud Ltvs apesaw/t c Bereqdaroc 3Budharest/ e Bul9arian Border 5 Sofia From/ q Niechorze Qatar hMonfalcone Extra-regional pipelineslLNG routes j misaljk @ * * * Intra-regional pipelines j Gdansk ***** lntr-regional pipeline -39- E. Supply Cost Calculations 3.56 We have calculated the supply costs and constructed supply cost curves for the individual countries of Eastern Europe as well as for the region as a whole. The supply cost curves of individual countries can be found in the country sections of the appendix. It may be worth noting that the costs calculated are not equivalent with gas prices, which would be determined in negotiation between buyer and seller. 3.57 The cost of delivering gas from six suppliy sources to 17 delivery points was calculated, resulting in 48 different supply options. The supply sources studied include the following: USSR e Incremental West Siberian gas volumes through existing network. * Incremental volumes through a new 35 BCM pipeline from Yamal to Uzhgorod, from which smaller branches spur off to Brest-Litovsk and Ismail. - Barents Sea gas, delivered via a new pipeline to Brest-Litovsk or to an assumed new LNG terminal in Gdansk (due to an assumed very long development time of a potential Barents Sea project and the high costs that would be associated with it only costs delivered Gdansk have been calculated for this option). X Supply cost estimates are based on Western standard cost assumptions. Iran * 20 BCM of gas delivered to Eastern Europe from northern Iran via the planned new pipeline through Turkey (with another 10 BCM consumed in Turkey), delivered at the Bulganran border. Norway * North Sea gas delivered via Emden and Midal/Stegal to Litvinov in Czechoslovakia. * North Sea gas delivered via Denmark and the proposed Polpipe line to Nlechorze in Poland. * LNG from the Snohvit field off the north Norwegian coast delivered to an assumed new LNG terminal in Gdansk (due to an assumed very long development time of a potential Snohvit LNG project and the high costs that would be associated with it only costs delivered Gdansk have been calculated for this option). Algeria * Pipeline gas delivered via Transmed through Italy to Monfalcone on the Yugoslavian border. * LNG produced at a new plant and delivered to a proposed terminal in northern Yugoslavia. Other 0 Libyan LNG produced at a new plant and delivered to a proposed terminal in northem Yugoslavia. -40- Qatar LNG produced at a new plant and delivered to a proposed terminal in northern Yugoslavia. 3.58 Although the United Kingdcra and the Netherlands could be in theory be regarded as potential suppliers to Eastern Europe, we have decided not to include them in this review of potential new suppliers. If our expectations concerning a developing supply deficit in the UK market in the forthcoming two decades are correct, a potential UK exporter will base his decision on whether to export or not on the highest margin he can receive on delivered gas. Against that background, gas exports from the UK to Eastern Europe seem highly unlikely to us. 3.59 Nigerian LNG has also been left aside, as previous calculations have indicated that Nigerian LNG delivered Europe would be significantly more costly than Qatar LNG, which is one of the most expensive supply sources investigated. Nigerian LNG is more costly mainly due to higher production costs, gas gathering costs and larger need for new infrastructure (greenfield site). 3.60 Cost Assumptions. To arrive at realistic estimates of investment and operating costs, various assumptions had to be made concerning pipeline diameters, routing (topographic and climatic considerations), compressor station spacing, steel quality, roughness of pipe, etc. The degree of accuracy of our estimates is assessed at approximately +/- 30 per cent 3.61 A number of further simplifying assumptions have been made: - No allowance was made for the fact that full economies of scale would probably not acrue to individual buyers. Instead, volumes and costs reflect the size of pipelines at the point of delivery. i We have looked at the delivered cost of individual suppliers at several delivery points, although the implication of this is that aggregated gas volumes can be misleading in terms of their ability to indicate the maximum quantity of gas available from any individual source. * Production cost estimates are resource cost based, reflecting investment costs, field operating expenses and production volumes discounted over project life (of field, at 10 per cent discount rate). Taxes have not been included. Transport, liquefacdon and regasification costs include capital and operating costs, calculated on the basis of the foHlowing assumptions: * 20 year economic life for pipeline projects (typical duration of supply contract). * 25 year economic life for LNG tankers (standard estimate of ship builders, although in praice, LNG tankers will have longer life if properly maintained). * 10 per cent real discount rates, costs expressed in 1991 terms. A 10 per cent discount rate could be regarded as relatively low, individual project risk and opportnity cost of capital may require higher rates. Higher discount rates would result in higher costs. e 8000 hour load factor (91 per cent). In the interest of consistency and comparability, we have chosen not to differentiate load factors on individual transport options calculated. A load factor of 91 per cent would be a standard assumption for long distance, onshore pipelines. In some circumstances, it could be considered as a high assumption, e.g. for pipelines directly connected to a single offshore production source. Lower load factors would result in higher costs per cubic meter. -41- Instantaneous loading to full capacity is an important simplification. Normally, immediate utilizadon of the maximum capacity of a new pipeline would only occur at construction of small pipelines. For larger pipelines, capacity is usually built up in stages. However, in order to take this into account in our calculation, we would have had to make further assumptions on capacity and investment build-up. A gradual build- up of capacity would have had an increasing effect on trnsport costs per cubic meter, while a gradual build-up of investment would reduce them. The additional degree of uncertainty and complexity introduced by talking this into account would, in this context, of primarily aiming to indicate transport costs in order of magnitude, not have corresponded to the value added of increased accuracy. F. Supply Cost Curves 3.62 Of all supply options studied, incremental gas volumes from the USSR delivered through the existing system would be the cheapest (in cost terms). This is because marginal costs of transportation would be limited to additional compressor fuel use (3 per cent of throughput), and marginal costs of production are likely to be very low ($3.80- $18.95/lOOO m3 or $0.10 - $0.50MMBtu). At present, there is only about 10-15 BCM per annum of spare capacity available from the Soviet Union. Beyond that, new production capacity must be developed and additional pipelines built. 3.63 In order to diversify their supply, EastEuropean gas buyers could approach a number of different potential sources. In the short term (wiin 5 years) however, only North-African LNG, Qatar LNG, or Algerian pipeline gas are likely to be available. Other sources would take longer time to develop. 3.64 Of the non-Soviet sources, North African gas (both LNG and pipeline gas) and Iranian gas are the least Dostly to deliver to the borders of Eastern Europe, though of course the situation for each individual country varies according to its location. Qatar LNG is more expensive than North African LNG due to the larger shippmg distance. Norwegian North Sea gas delivered by pipeline to Europe would be the most cosdy to deliver (apart from USSR Barents Sea pipeline gas), and probably not be available before 2000. The Norwegian cost disadvantage is a result of the combination of high production costs and large distances from wellhead to market. 3.65 Conclusions. In the short to medium term (deliveries beginning before 2000), we believe that between 15 and 20 BCM could be made available to Eastern Europe, of which 5.5 BCM would be in the form of North African LNG delivered to a new terminal at Omisalj, an additional S BCM of Algerian pipeline gas delivered via the Transmed pipeline, and the rest consisting of Soviet volumes. The total investments required to bring these to the East European border would be approximately $5 billion. Addidonal supplies from other sources like Iran, new developments in the Soviet Union and Norway, or LNG from Qatar seem unlikely to be made available before 2000. 3.66 The Iranian gas pipeline project, which is presentl being considered, would need a price (at the Bulgarian border) above $1.90/MMBtu ($70.85/10i m3) in order to be economical (given full utilizaton). In order to provide incentives for new Norwegian North Sea gas projects to be developed, border gas prices of between $2.85 and 3.20 per MMBtu ($107.25 - $120/1000 m3) would have to be offered. -42- Chart 3.2: Supply Cost Curve for Eastern Europe. Gas Delivered to Closest Border/Landing Point $1;000 m3 12 13 $IMM@tu 160 - 4.0 140 10 1 120 3.0 100 4 8 USSR gsatUhgoro2 2.0 60 _ _ _ 40 ___1.0 20 Aenst nce2 0 ~~ 0 20 40 60 80 100 120 150 BCMp.a. Supply Options Deliveries from: 1 Iranian gas at Bulgarian border 1994 2 USSR gas at Uzhgorod 19 3 USSR gas at Beregdaroc 99 4 Algerian gas at Monfalcone 2000 5 USSR gas at Ismail 6 USSR gas at Brest-Litovsk 2005 7 North African LNG at Omisaij 8 Qatar LNG at Omisalj 9 Norway Polpipe 10 USSR (Barents Sea to Brest-Litovsk) I1 Norway via Emden 12 Norway LNG at Gdansk 13 USSR Barents Sea LNG at Gdansk -43 - G. Future Gas Supply and Demand 3.67 The collapse of economic systems in Eastern Europe has ended a period of economic and social interdependence, which previously made trade with the Soviet Union a necessity. The transition to hard currency-based trade has provided a catalyst for East European countries to diversify away from Soviet gas supplies. 3.68 Indigenous gas production is unlikely to remain constant in the future without significant investment in exploration. Depletion of Eastern Europe's gas reserves occurred at a very rapid pace historically and production levels will not be maintained in the future unless significant additions to reserves are made. The latest data (for 1989) suggests that Eastern Europe is dependent on the Soviet Union for about 50 per cent of total gas requirements. However, considering Eastern Europe without Romania (the largest gas producer), dependence on Soviet gas rises to about 70 per cent. Whether or not this dependence increases in the future will depend on: * The ability of the Soviet Union to offer competitive gas pricing contracts to Eastern Europe. e The attractiveness of alternative gas supply sources such as Norway, Algeria, lian and Qatar. o How rapidly new infrastructure can be developed to augment alternative sources of natural gas. o T he ability of buyers to pay in hard currency. 3.69 The forecasts in this document are predicted on the basis of crude oil prices rising from approximately $25 per barrel (for Dubai crude f.o.b.) between 2000 and 2005, in 1991 dollars, and stabilizing at this level. Naturally, a smooth trend is not expected to occur in reality, as there will be a trading range of $3 or $4 around these levels. Consistent with this forecast of crude oil pnces, we expect gas prices to rise from their current level of approximately $2.25-2.50IMMBtu (high load factor gas, delivered European border, adjusted for indexation time lags) to approximately $3.50-3.75/MMBtu. (The reason gas prices grow slightly more than crude oil pices is because the link between oil and gas prices is assumed to be via gas oil and low sulfur fuel oil, not crude oil, and therefore reflects developments in the oil refining industry, changing slate of crude oils - ie. higher sulfur crudes, changing product demand, etc.). 3.70 Our high case forecast for Eastern Europe as a whole shows indigenous production declining from 37 BCM in 1990 to 14 BCIM in 2010. This forecast presumes that production on existing fields continues to decline, with some marginal improvement of R/P ratios to reflect upgrading of production facilities. Inpms will have to increase throughout the entire period from 44 BCM in 1990 to 90 BCM in 2000, increasing considerably to 159 BCM by 2010, as demand growth will exceed reserve additions. (The import requirements for the base case are somewhat lower, cfr. pg. iii). This would require investments in new infrastructure to the East European border of $2 billion up to 2000 (including new pipeline from West Siberia). In the longer tem, additional investment of up to $50 billion may have to be made in order to bring in adequate amounts of addidonal supplies, unless substantial discoveries of indigenous reserves am made. 3.71 Competition for the volumes available to European buyers in future will be strong, as both East and West have substantial supply gaps to fill The ability of individual importers to offer compedtive market prices will depend on the value of gas in each market, distibution costs and distance from supply source. -44- Table 3.11: Projected European Gas Supply and Demand Balance (High Case) BCM Western Europe Denand -260- 3aP - -2 Indigenous 121 145 125 lW 75 Norway 28 27 35a 35a 35a USSR 55- - 64 64 AlIgena _s II= 7 w8 074 NeftherranTs- -N 4 4 Nigeria -5 5 5 DCfi F 0 3- 77 139 .91 Eastern 1Europe: Demand ~ ~- 81 80 102 133 173 Supply_ (Committe) hidigenous 37 ~ 36712 13 74 USSR _ T 3 8 40 = 40 40 imn 3 T 3 fcit T - 0 _L 7T 75 114 ITOTAL O s 115 is 4 31S DEFICIT I I a. If all the Troll options are exercised, Norway would be selling 47 BCM from 2000 onwards 3.72 Obviously, as far as financial strength is concerned, East European buyers will initially, due to the fact that they are in the process of rebuilding their economies, have a disadvantage in relation to their West European neighbors. Distance from supply source affects transport cost and therefore the price required by the supplier. Eastern Europe has in these terms a competitive advantage vis-a-vis Western Europe when it comes to supplies from the Soviet Union, Iran, Libya and Qatar. As regards ability to offer higher prices however, it seems clear that Eastern Europe will have severe problems in comnpeting with Western Europe for the incremental volumes available for supply to European buyers during the next decade. Even if gas market values were similar to those of Western Europe (which is a possibility, since substitute fuel prices will gradually move towards intemational market price levels), internal transmission and distribution costs are likely to be much higher than in Western Europe due to the substantial new infrastructure investments that will have to be made, and the lower volumes which are consumed, leading to lower prices. 3.73 Clearly, the volumes which will be made available for sale to buyers in Eastern Europe will depend on the prices offered to suppliers. In the end, suppliers are likely to be offered sufficiently high gas prices to provide incendves to develop more costly reserves in remote locaions. However, as gas is in most of its applications t00per cent substitutable by other fuels, gas pdies could not rise above those of competing fuels (adjusted for any premium due to superior convenience, efficiency, environmental friendliness, lower operating or capital cost, etc.). Future -45- gas price developments will therefore ultimately depend not only on the supply and demand of natural gas, but also of other energy forms. 3.74 With rapidly-emerging potential supply deficits in both Westem and Eastern Europe, "sellers market" conditions prevail Gas companies in both areas will compete for the available supplies and there is likely to be an incease in prices at the uEopean border as a consequence. 3.75 Precisely how the deficits are to be addressed is a mater for the gas companies them- selves, acting jointly in consoria or individually. Each company is likely to wish to create a balanced portfolio of supplies, with a judicious blend of imported and indigenous availabilities, some low resource cost gas to balance tk. - risks of high resource cost gas, and gas from "secure" supply sources to balance that obtained from "risky" supply sources.Each company is likely to prefer a unique combination of gas from the various potential sources, takdng account of their market size and structure, energy prices, the degree of conetidton and other factors. Appendices Country Sections 1 -48 - APPENDIX1S Page 1 of 6 Bulgaria A. The Bulprian Energy Industry - Summary * Bulgaria's national primary energy fuel mix in 1989 consisted of 38 per cent coal, 37 per cent oil, 14 per cent natural gas and 11 per cent nuclear, hydro, and imported electicity (Source: MEA Energy Balances). * Naural gas has been used since the 1960s, primarily in the industrial sector. - Natural gas consumption has, since the early 1980's, grown at an average 6 percent per annum. v The natural gs grid is not very well developed, primarily serving the purpose of bringing Soviet supplies into the country for further transport to industrial consumers and CHP plants. * The main problems facing the government of Bulgaria in the energy sector are the following: - limited domesdc energy reources apart from low grade brown coal - Lack of financial esouces necessary for investment in altemative power sources, and exploration for indigenous hydrocarbon reserves - Dependence on the Kozludoi nuclear power plant for supply of 25-30 per cent of natonal powerdemand - Dependence on the Soviet Union as single source supplier of oil, coal, imported electricity, uranium and gas (apat from contracted gas from hran). B. Historical Natural Gas Supply and Demand Bulgaria has proven hydrocarbon reserves of about 2 million tonnes of oil and 13 BCM of natral gas. Howe=, it is believed that additional unproved and highly prospective reserves are located in the Black Sea Fute eloration efforts are expected to be concentted in this region. Gas demand was 5.9 BCM in 1989, represendng about 14 per cent of total energy demand, up from 9 percent in 1980. A very small amount Oess than 2 per cent) of gas is produced indigenously, while the remainder is imported from the Soviet Union. Gas discoveries in the Black Sea could increase future domesdc producton significantly. In the absence of hard data, it is estimated that about 40 per cent of gas imports are used as feedstock for petrochemical plants while the remaining 60 per cent are consumed as follows: 31 per cent in combined heat and power plants; 12 per cent in the iron and steel industry, 12 per cent in the construcdon industry (cement, bricks, etc.); and S per cent in the glass manufacturing and other industries. -49- APPENDII Page 2 of 6 C. Gas Infrastructure Due to the rather modest indigenous (proven) reserves of gas, the function of the Bulgarian pipeline network has mainly been to bring Russian gas into the country. In future, it will also be used to transit gas through to Yugoslavia and Greece. The two main systems, which begin at the Soviet border in the northeast, transport gas to large industrial consumers and combined heat and power (CBP) plants around the country, converging in Sofia A new pipeline will branch off the southern system before it reaches Sofia, and continue from there towards the Greek and Yugoslavian borders. The nominal capacity of the present system has been indicated to be 9 BCM/year. An additional pipeline transmitting Soviet gas to Turkey runs along the eastern border of the country. D. Planned Expansion of Infrastructure The European Economic Community is subsidizing the construction of a pipeline from Bulgaria to Thessalonika in Greece, a spur of which will go to Skopje in southern Yugoslavia. The capacity of the system will be 9 BCM per annum. Preparations hava been started in Macedonia for linking up with this major gas pipeline, which is expected to be operational by January 1994. The hIanian pipeline to Western Europe through the Balkans is a project which has been considered for a long time. In spring this year, initial discussions were held between Greece and Iran. To be commercially attractve, we believe the line needs a throughput of at least 20 BCM per annum, probably even more. Other countries which have expressed an interest include Yugoslavia (1.5 BCM), Czechoslovakda (3 BCM) Bulgaria (1 BCM), Italy (2 BCM), and, without indication of potential off take volumes, Turkey, Romania, Poland, Austria and France. E. Major Gas Purchase Contracts In the past few years, Bulgaria has been importing around 6 BCM of gas annually from the Soviet Union. Although the contracts were converted to hard currency terms in early 1991, trade has continued on barter terms. Gas is received in exchange for bartered goods, as a loan repayment for rendered Bulgarian pipeline construction services, and as a transit fee. In 1989, a 20 year contract was signed with Iran for yearly imports of 1 BCM of gas, scheduled to begin in 1990. Deliveries have, however, not yet taken place. The Iranian gas will be delivered via the Soviet transmission system. Press reports have indicated that the transit fee which is being demanded by the Soviet Union is too high for ranian deliveries to be economically viable. Iran would receive Bulgarian chemical products in a counter trade anrangement in exchange for its gas deliveries. F. Industry Structure Production of oil and gas falls under the responsibilities of the Ministry of Industry, Trade and Services. Oil and gas is impotd by fte Khimimport Corporation, subordinated to the Ministry of Foreign Trade. Transmission is camred out by Bulgargas, which is a separate organization. Local distribution companies are responsible for low pressure lines feeding industrial facilities in their respecdve areas. Major users like CHP plants and lrge industrial consumers are responsible for their own intnal distrbuton, and in some cases also control distribution lines. -50- APleEDllDI2 1 Page 3 of 6 G. Potential Contribution of Gas to Environmental Improvement Current energy policy is based on continued utilization of indigenous, low quality brown coal to meet increases in demand for electrcity. Six new coal fired units ae included in the 1990-95 plan. Most other planned capacity additions will be small scale, clean coal technology CHP. Compared with some of its East European neighbors, Bulgaria appears to suffer less severely from environmental problems such as air and water polludon. This is partly due to the relatively high proporton of electricity generated from hydroelectric or nuclear power. The water supply is, however, limited and irregular, so hydroelectric capacity needs to be supported by fossil-fueled alternatves. 51 per cent of the inland rivers and 36 per cent of total hydro potential has already been utilized. Also, the country's only nuclear power plant at Kozlodui is in bad condition. After a thorough examination, the IAEA came to the conclusion that for safety reasons it was imprudent to operate the plant given its condition. Some remedial action has since taken place and the plant is still in operation. Plans to continue construction on a half-built a second nuclear plant at Belene have been deferred due to strong enviromnental opposition. Replacement of coal-fired capacity with gas fired CCGTs does not seem likely at present. Replacement of coal-fired capacity with CCGT power plants could, in theory, lead to an increase in annual gas demand of up to 5 BCM (given current electricity demand, and dependent on the amount of capacity replaced). H. Prospects for Increased Indigenous Gas Production Bulgaria is considered to have one of the best outlooks for additional onshore and offshore oil and gas discoveries in Eastern Europe. Foreign investment laws and exploration policies have recendy been liberalized in an effort to attract investors. The area considered to contain oil and gas has been divided into ten onshore and six offshore blocks. Several Western operators have signed exploration contracts and joined the search for hydrocarbons in the Black Sea. Profits from commercial discoveries are to be divided equally between the foreign participants and the state; net profits must however not exceed 25 per cent of the total profits in convertible currency after fees and taxes. I. Current Plans for Expansion of Gas Markets and Future Gas Supply and Demand Being the smallest user of gps in Eastern Europe, Bulganra represents the only country that is not planning to significantly increase gas purchases in the future. Unlike most of its neighbors, it is thus not expected to show an increase in gas demand in the near future. Gas is only used in industry, either as a feedstock (45 per cent) or for energy production (30 per cent), and in CHP plants (25 per cent). The only energy sources used by the residential sector are district heating and electricity. Only the petrochemical sectr is exectd to require additonal gas. Gas demand in this sector could, however, fall as petrochemical c s adapt to intemational competition. Neither the electricity authority nor the district gas companies foresee major increases in gas consumption for power generation or in the residential and commecal sectors. Previously, the attractiveness of low gas prices and environmental friendliness prompted constuction of gas-based combined heat APPENDIXI Page 4 of 6 and power plants However, future plans are for incrmwtal power generation based on clean coal technology. Bulgaria is not very well endowed with natural resources. Apart from poor quali.y lignite, energy reserves are very limited. Natul gas has been used to substitute coal in city CHP plants for environmental reasons, but future plants are plamed to use clean coal technology (fueled by lignite) rather dtan gas, which would have to be imported. Moreover, most of the populated centers in Bulgaria are already connected to the gas grid, implying that district heating requirements are expected to remain relatively constant Any increases in demand will probably be met by Irnian gas, which is currently delivered via exchange with the Soviet Union. Contrary to the forecast by Bulgarian authorities, the Soviet Union hopes to develop additional gas demand by inidating, inter alia, a compmssed natural gas program that would displace oil-based transport fuels, such as gasoline and diesel. A pilot gas station already exists in Sofia The Bulgarians have apparently not responded explicity to the Soviet interest in developing a new gas market niche. J. Pricing Policy Bulganra has until recendy condnued its traditional policy of closely controlled prices. Energy prices have now been liberalized. On 3 June 1991 plans to price liquid fuels to international market levels were announced. The primary effect of raising energy prices and constant wage levels in the short term will be a rapid decline in demand, particularly m the energy sector. Gas demand is less likely to be drastically reduced as it may be considered an essendal item given its importance as raw material in production of exportable chemicals and fertlizers. 1991 Pricesa $/'000 m3 _ $/MMtu Impt price 95.500W 2.52 L ndustry prce 9.50t Commercial sec 98.502.62 Household sector 2 .62 _ Source: Wodd Bank a Representsesdimd avege 1991 pde K. Gas Demand Forecast Our forecast for gas demand in Bulgaria predicts continued use of gas in the industrial sectors, with beginning development of residential demand from 2000 onwards in the high scenario. The low scenario represents our view of future gas demand given stagnant to slow economic development, no efficiency improvements, no replacement of coal fired capacity in power generadon, and no development of oter maret segments. The high scenario represents gas demand under the assumption of strong economic growth, active development of gas market and -52- Page 5 of 6 new customer segments (esidential), some efficiency imvements and some replacement of coal fred capaity in power genatdon at the xwense of coaL Bulgarian Gas Demand _ ; . ~~~Average BCM 1990 1995 2000 2005 2010 Growth scenario LOW 3.5~ 6.5 68 7.0 0.4 scenarioI Base Case 6.5 6.6- 7.1 7.4 7.7 0.9 Hcaigh 6.5 6.6- 9.4 1T2.7- 7 17.2 5.0 .Producton I____ : hpor < 6.5 6.5 - 65 6 s_ 6.5s RDeficit . I O F.I I 0-2.9 1 0.3-62 0.5-20.7 Soce. Athur D. Lie As can be seen from the table above, we predict that a supply gap of up to 3 BCM could develop by 2000, and between 0.5 and 11 BCM by 2010. L. Supply Cost Curve We have calculated the delivered cost of gas from two alternative supply sources to Bulgaria. * Incremental gas from the Soviet Union, delivered from the Yamal peninsula via a 35 BCM pipeline to Jelets, with a subsequent 5 BCM branch to Romania, and a 2.5 BCM pipeline fom Romama to Sofia; and e Incremental raian gas volumes, delivered via the proposed new pipeline through Turkey to south eastern Bulgaria, continuing from the border to Sofia. In cost terms, Iranian gas seems to be the cheapest supply source, but it is not likely to be available before 2000. -53- Page 6of 6 Supply Cost Curve for Bulgaria: Gas Delivered Sofia $/'000m3 $IMMBtu 150 7 3.96 120 100 2 2.63 80 _ 60 _ _ _ _ _ _ _ _ _ _ 40 __________________ 1.32 40 __________ 20 0 I I I mCM 0 5 10 15 20 25 30 35 40 45 50 Supply Options Deliverles from: 1 Iranian Gas m1996 2 Soviet Gas via Romania 1996 2005 -54- Page I of 6 Czechoslovakia A. The Czechodovaklan Energy Industry . Summary * Czechoslovakia's national primary energy fuel mix in 1989 consisted of 57 per cent coal, 21 per cent oil, 13 per cent natural gas and 9 per cent nuclear, hydro, and imported elecicity (Sourc: IEA Energy Balances). Natural gas has been used in all market sectors since before the 1960s. * Natural gas consumption has since the early 1980s, grown at an average 2.6 percent perannum * The natura gas grid is very well developed, with the main Soviet export pipeline to Westem Europe crossing the country from east to west o The main problems facing the government of Czechoslovakia in the energy sector are the following: - Dependence on impot fuels as energy sources - High share in energy mix of indigenous low grade coal used in highly polluting industries and power plants * Dependence on the USSR as main source of imported fuels Need to extend gas infrastructure in order to permit imports from other sources - Urgent need to reduce air and water pollution without impairing ability to satisfy power demand - Lack of financial resources required for investment B. Primary Energy Supply and Demand The Czechoslovakian energy supply mix is dominated by coal, which accounts for over 57 per cent of total supply. The Czechoslovak coal deposits are almost entirely low quality, and rcent environmental concerns may prompt a reduction of coal's share of energy supply in the futue in an effort o aLeviate quality concerns, Czechoslovakia trdes brown coal for lower sulfur hard coal from Poland. This trading allows a higher quality of coal to be buned domestically. C. Historical Natural Gas Supply and Demand Czechoslovakia has proven gas reserves of about 14 B(M (and proven plus probable of about 64 BCM). In 1989, production reached about 1 BCM. Indigenous production represents less than 7 per cent of tdomesc gasreq . APPE@NDI Page 2 of 6 Gas demand was 9.6 BCM in 1989 and accounted for about 13 per cent of total energy demand, up from 9 per cent in 1980. Czechoslovakia imports most of its gas from the Soviet Union. A significant volume is received as transit fee payments for gas pipeline transmissions to Westem Europe. Gas consumption is concentrated in the power generation and industial sectors which respectively accounted for 37 per cent and 25 per cent of total gas demand in 1989. Apart from 0.6 BCM used in the petrochemical industry, the industri sector uses gas for steam-raising in a wide variety of processing/manufacturing activides. The residential and commercial sector accounted for 41 per cent, indicating an established gas transmission and distrbution system Historically, gas demand has increased by 2.6 per cent per annum during 1980-89. A modest decline was recorded in industrial and power generation gas demand over this period, though this was more than offset by an almost 11 per cent increase in residential/commercial consumption. D. Gas Infrastructure The pipeline network was devloped for the putpose of transporting Soviet gas to Germany and France. Instead of transit fees, C'zechoslovakia received Soviet gas as payment. The Bratrstvo pipeline system (commissioned in 1975) connects the Progress pipeline at Uzhgorod on the eastern border with the Megal system at Waidhaus and Baumgartn in the west. One of the Brotherhood pipelines is used for local purposes, and has a capacity of around 5 BCM. The Brotherhood system could be expanded to permit increased imports of Soviet gas. Bohemia and Moravia are well coveed by transmission lines, while the Slovakian part of the system, although including a larger part of the Bratrstvo pipeine, has fewer branch lines. In the past, the seasonal variation in gas consumption sulting from a high proportion of gas used for heating purposes has been a major problem. In 1989 two additional gas storage reservoirs were constructed bringing the total to five with an overll capacity of 3 BCM There are now gas storage facilites both in Bohemia and Moravia, able to meet 40 per cent of total winter peak gas demand. E. Major Gas Purchase Contracts Having only minor indigenous reserves of gas, Czechoslovakia is the largest user and inporter of Soviet gas in Easten Europe. Gas is received in exchange for bartd goods and as a transit fee. Furthermore, 4.5 BCM is purchased from the Soviet Union at a reduced price in exchange for engineering work done by Czechoslavak companies on the Soviet gas pipeline system. F. Industry Structure The Ministry of Economy is responsible for the adminstaton of two oil and gas companies, five coal production enteprises, two electicity co nies and one company (Transitni Plynovod Praha), which operates the TransGas (Bratrstvo) ransmission system. Oil and gas production is canied out by Naftovy A Plynarenske Pdiemysl Zapadnoslovenske through its -56- APPENDI 2 Page 3 of 6 subsidiary Nafta Gbely. EneW imporU are handled by the Chemapol Corporation, subordinate to the Ministry of Foreign Trade. The two gas utilities, Czech-Moravian Gas (Ceske Plynarenske Podniky, CPP) and Slovak Gas (SPP), are both owned by the two republics. CPP, which handles gas distribution in Bohemia and Moravia, is planning to restrucr the gas industry of the Czech Republic. CPP itself will be restructured into a holding company, with eight subsidiari -+s comprising 58 business units. It is not known to us whether SPP, which is the Slovakian equivalent of CPP, has similar plans, but it would seem likely, given the geneal bend towards ucturing and privatization present in the country. A major point of dispute is the future ownership and control of the TransGas pipeline (built by CPP), which carries Soviet gas across Czechoslovakda to the German and Austrian borders. For the moment, ownership has been transferred to CPP (48 per cent) and SPP (52 per cent), but future foreign participation may be allowed. The two utlides are in disagreement over the relative size of their respective shareholdings. The Slovaks would like to see a separate company set up to manage the 72 per cent of the pipeline which run across their territory. Currently, TransGas' profits are split equally between the two Republics. G. Potential Contribution of Gas to Environmental Improvement Czechoslovalia has the second worst enviromental problems in Eastern Europe (only Poland is worse) mainly consisting of air and water pollution. It has been recognized that the power generation sector is to a large extent responsible for the emissions of dust, sulfur, S02 and acids which pollute the air. In 1989, 51 per cent of electricity was generated from coal (primarily lignite), 28 per cent from nuclear power, 8 per cent from gas, 8 per cent from oil and 5 per cent from hydro. The efficiency of existing coal plants is very low, 21 per cent as compared with 38 per cent for a modem Western plant burning hard coal. In February 1991, it was reported that power stations in Northem Bohemia (where lignite is produced and many of the power plants are located) reduced their output by 776 MW to reduce pollution. Northern Bohemia is the most polluted region in the country, which is why the Govemment has decided to close down a number of lignite fired plants ir this area. 50 per cent of total lignite generating capacity (600 MW) are to be closed down within five years, with the rest to be refitted with desulphurizateon equipment The quesdon of how to replace this capacity is not an easy problem to solve. Hydro electicity has already been exploited close to its fu potential and is unlikely to offer substantial possibilities for expansion. The govanment aims to increase the use of gas m power generation, but gas would have to be imported and paid for in hard currency and would increase its already significant share of primary energy demand and the country's dependency on imported fuels. An increase of nuclear capacity woud require substantal outlays of capitaL The goverment strongly favors expansion of the nuclear program, but has been met by protests from Austia. We predict that given curent electricity demand, replacement of coal-fired capacity with CCGT power plants couldiheoretically, lead to an increase in annual gas demand of between 1.5 and 10 BCM (depending on the amount of capacity replaced). -57- Page 4 of 6 H. Current Plans for Expansion of Gas Markets According to plans drawn up prior to 1989, Czechoslovakia was to increase gas con- Sumption from current 15 BCM per year to 25 BCM per year by 2005. The government is currently investing in conversion of about 14 CHP power plants in order to increase use of gas in power production. I. Future Gas Supply and Demand Despite lited domestic gas reserves, the Govemment is trying to reduce dependence on Soviet gas imports. Given Czechoslovakia's hard currency limitations and significant indigenous coal reserves, gas will, on an incremental demand basis, have a secondary role in the economy during the next few years, only growing by 1 per cent per annum Increased gas use will be seen in all sectors, but power generators and residen- tial/commercial users are expected to have higher requirements than industrial users given the newly stated government prnorities. The emerging government policy suggests that future gas developments affecting demand will focus on: * The district gas system * Conversion of combined heat and power plants; as well as * Selected conversion of industridal boilers from coal and oil to gas. Czechoslovakia plans to convert approximately 168 coal-based heating units to gas by 2000. The coal units currently consume about 2.8 million tonnes per year of lignite. Displacement of coal will require about 0.8 BCM per year of gas. However, with indigenous coal resources, it is unclear whether conversion will be economically attractive, though environmental benefits are becoming a major consideration. The reliance on Soviet gas imports has prompted authorities to consider alternative supply sources, such as Algerian pipeline gas via Italy (and Austria), regasified LNG through a pipeline from the Adriatic, Norwegian pipeline gas or LNG, and/or inian pipeline gas. J. Pricing Policy Earlier in 1991, gas prices were increased to near market levels through a 134 per cent pice nse as a result of price liberalization. The rise in gas prices in Czechoslovakia is expected to put some downward pressure on demand, partiularly at the residential and commercial levels. Household gas prices rose by 130 per cent at the beginning of 1991, but are nevertheless still far below market price levels. Czechoslovakia is thought to be in a better position than other East European countries given its historically tight monetary and fiscal policies. However, the economy had only partally moved to market-based pricing in 1990 and thus 1991 will require further price liberalization, particularly since wages have been allowed to increase in lock-step with prices. Higher gas prices are likely to affect ridental and commercial gas sales more than the mndustri and the power generaion secos -58 - Page 5 of 6 K. Gas Demand Forecast Our low scenario predicts slov economic growth, with gas demand increasing moderately in industry and power generation and more strongly in the residential sector. In the high scenario, which is based on strong economic growth and increased use of gas at the expense of other fuels (mainly coal), gas consumption is predicted to grow rapidly in al sectors. Czechoslovaklan Gas Demand BRu Avrerage Growth Low scenario 12.7 135 15.0 16.8 18.8 1.9 Base _ 13.7 16.8 20.8 20 3.6 Hgscenario r2. 13 176 23.3 30.94. Indig.0. 0. 0. 0.08 Production I12.0 12.0 12.0 12.0 12.0 Defici __ 0.8 1.0 2.24. 8 4.0-10.5 U8I As can be seen from the table above, we predict a supply gap of around I BCM to have developed by 1995,2 to 5 BCM by 2000 and 6 to 18 BCM by 2010. L, Supply Cost Curve We have calculated the cost of bringing incremental gas from the Soviet Union, Norway, and North Africa to Czechoslo .4.a Soviet gas is assumed delivered at Uzhgorod, Norwegian gas via the proposed Polpipe line or Midal/Stegal to Litvinov, Algenian pipeline gas from Monfalcone on the Yugoslavian/Italian border, and regasified Libyan/Algeian LNG from the proposed terminal at Omisalj in Yugoslavia. The shorter internal distance from Litvinov to Prague does not seem to offset the cost disadvantage of Norwegian gas. Algerian pipeline gas seems to be the least costly non-Soviet supply alterave for Czechoslovakda in the short to medium term (deliveries staring before 2000). -59- Page 6 of 6 Supply Cost Curve for Czechoslovakia: Gas Delivered Prague $f000 m3 $IMMBtu 4.00 140 120 3 gA 6 ~3.00 100 3 80 2.00 60 40 1.00 20 0 ____LI_ __ CM 0 5 10 15 20 25 30 35 40 45 50 Supply Options Deliveres from: 1 Algenan Gas Via Transmed 1994 2 USSR Gas via Uzhgorod 1996 3 North African LNG 4 Qatar LNG 2000 5 Norwegian gas via Polpipe 0 6 Norwegian gas via Emden 2005 -60- Page I of 6 Hungary A. The Hungarian Energy Industry - Summary * Hungary's nadonal primary energy fuel mix in 1989 consisted of 24 per cent coal, 30 per cent oil, 31 per cent natural gas and 15 per cent nuclear, hydro, and imported electricity (Source: IEA Energy Balances). * Natural gas has been used in all market sectors since before the 1960s. * Natural gas consumpdon has since the early 1980's grown at an average 3 percent per annum, primarily at the expense of coal and oiL o The natural gas grid is well developed, covering most of the country and reaching most areas of large energy consumpdon. v The main problems facing the government of Hungary in the energy sector are the following: - HEghly dependent on the USSR as main source for imported fuels - Proven/ecoverable gas reserves nearing depletion - Need to increase domestic gas production by finding new reserves and improving recovery on presendy producing fields - Need to extend gas infrastructure in order to permit imporn from other sources - Need to reduce air and water pollution without impairing ability to satisfy power demand - Lack of financial resources required for investment - Need to improve energy conservation - Need to increase base load power production capacity. B. Historical Natural Gas Supply And Demand In 1990. Hungary had remaining proved plus probable reserves estimated at 26 million tonnes of oil and 123 BCM of gas. Under the most recently completed five year plan (1986-90), Oi GT (the former govenment organization in charge of oil and gas activity, now called MOL) drilled an average of 200,000 meters of exploratory wells and 170,000 meters of development wells each year. At an average depth of 2,100 meters, this amounts to about 95 wells per year. Reserves are expected to be depleted quite rapidly over the short term as funds are invested in secondary and tertary recovery projects. -61 - Page 2 of 6 Natural gas accounted for about 31 per cent of total energy demand in 1989, up from about 26 Per cent in 1980, of which about half is domestically produced and the remainder imported from the Soviet Union. While the share of gas in primary energy demand has been increasing, coal has declined by about 4 per cent and oil by about 10 per cent. This decline was partially offset by increases in hydro and nuclear power, which rose from 2 per cent of primary energyr demand In 1980 to 15 per cent in 1989. Total natural gas consumption was 9.9 BCM in 1989. Gas is primarily used for power generation and in industry. In 1989, power generation accounted for about 46 per cent of total gas demand and was used to generate about 14 per cent of total elecicity production. The second largest user of gas is the industrial sector, which accounted for 31 per cent of total demand and is comprised primarily of petrochemical, iron and steel and energy sector end-users. The residential sector accounts fr 18 per cent of total gas demand, while energy transformation, own use and losses togetheraccounted for 4 per cent of total demand. Overall, gas demand has grown at a moderate rate during the 1980s, increasing from 7.5 BCM in 1980 to 9.9 BCM in 1989, an average annual increase cf 3 per cent. Gas demand growth has occurred primarily in the residential sectors, which grew at an average 14 per cent annually from 1980-89. (Source: IEA, 1 MTOE = 0.957 m3 of natural gas, assumng 40 MY gcv per standard m3). C. Gas Infrastructure Hung has sizable natural gas reserves which were discovered in the 1960s. The pipeline network was developed to distribute indigenously produced gas from fields scattred in the eastern part of the country to major centers of consumption, namely the consumer districts of Budapest, Central Hungary and Transdanubia. Gas imported from the Soviet Union is delivered at Beregdaroc via the Bratrstvo system, the capacity of which has been increased continuously. 'ansit gas to Yugoslavia is supplied via a pipeline beginning in the vicinity of Budapest to Horgos on the Yugoslavian border (commissioned in 1979 and expanded in 1983). At the end of 1988, Hungary's remaining proven and probable gas reserves were ap- proximately 115 BCM. Although the reserves are there to be produced, the Hungarians have problems in retrieving them, as production costs are increasing due to inefficient and outdated equipment. In 1989, some 5 BCM were produced, but output is expected to drop to 4 BCM per year by 2000. The Hungarian residential segment is well penetrated. 35 per cent of households are supplied with piped gas (a further 59 per cent cumrendy use bottled gas). Underground gas storages exmst at Hajduszoboszlo, Kardoskutt and Pusztaedevics. There are two main gas gathering stations with a combined capacity of 11.5 BCM per year. D. Major Gas Purchase Contracts Hungary has two contracts with the Soviet Union. The Orenburg contract, which is for deliveies of 2.7 BCM per year, may be extended beyond the 1992 expiry date, subject to revision to adapt to new market condidons. The Yamburg contat stipulates deliveies of 1.9 BCM per annum from 1989 to 1998, which wiil be supplied to compensate Hungary for its contributions to the construction of the Progress pipeline. -62- Page 3 of 6 OKOT (now MOL) reached an agreement with the Yugoslav companies Energopetrol and Naftagas on delivery of 67 BCM of gas for 20 years, to be delivered between 1997 and 2017. Supplies will build up to 3.6 BCM per year by 2000. E. Industry Strnctui The energy sector was previously controlled by the Ministry of Industry and administered through a number of trusts. The former National Oil and Gas Trust, OKGT, was responsible for and had monopoly control over exploration, production, processing, and transport of natural gas and oil. OKGT also managed seven other regional oil and gas production ad- ministrations, and the Oil and Gas Pipeline Administration (Gaz-es Olajszallito Vallalat). Two affiliated companies, NKFV and KFV, handled production, processing, and marketing of natural gas and operate underground storage facilities. There were five regional gas companies, which handled regional distribution activities. Trade in oil and gas was undertaken by the Ministry of Foreign Trade through its organization Minelpex. A reorganization of the Hungarian industry has recently taken place. At the beginning of 1991, reorganizaton of the energy sector commenced with the official decision to disband the state energy combine OKGT, which has now been transformed into a joint stock company, the Hlungaran Oil and Gas Coiporation (MOL). Twelve affiliated companies have been separated from the former OKGT, includinig the five distribution companies. The government has announced that access to excess capacity in MOL's pipelines will be introduced. The state will retain 50 per cent of the equity in the regional companies, while the rest will be pIivatized with no limit on foreign par- icipatin. Production of oil and gas, refining, transport and marketingis to be transferred to a new oint stock company, which initially will be state-controlled, but may later be privatized. Imports have now been liberalized and Mineralimpex's monopolv broken, leaving MOL free to take import natural gas to Hungary. Although Hungary is generally regarded as having the best climate for foreign investment in Eastern Europe, lack of government direction has so far hindered constructive decision making and kept the gas industry firmly under state control. F. Potential Contribution of Gas to Environmental Improvement In 1989,46 per cent of Hungan eltricity was generated from nuclear plants, 26 per cent from coal, 14 per cent from gas, 13per cent from oil and the rest from hydroelectric capacity. Hungary's air is less polluted than that of most its neighbors, with the exception of Yugoslavia. Polludon could potentially be reduced if coal-fired capacity were to be replaced by natural gas-fired units. Hungarian power generation capacity, given that existing nuclear capacity is not shut down due to safety problems, is sufficient not to require construction of new base load power plants until after the year 2000. By then, electrcity demand will have increased by the equivalent of about 1 GW of capacity, which could be met by constructing gas-turbine and combined cycle plants. Given current electricity demand, replacement of coal-fired capacity with CCGT power plants could, in theory, lead to an annual increase in gas demand of between 0.5 and 1.5 BCM (depending on the amount of capacity replaced). -63 - Page 4 of 6 G. Prospects for Inereased Indigenous Gas Production Gas producton in Hungaty could increase significantly in the second half of the 1990s as the Pannonian basin, which extends into Yugoslavia and Romania, is believed to be highly prospective. Five concessions ae being offered to foreign companies to be awarded by the end of 1992. Tougher teams in Soviet import contracts imposed at the beginning of 1991 have made the search for domestic gs more urgent. To sustain current production levels, heavy investment would need to be made in enizing and improving the efficiency of gas production equipment. The Hungaria govement expects to award explorion concessions to foreign com- panies toward the end of 1992. Gas prospects are thought to be good, particularly in the Pannonian Basin which extends into Yuoslaa and Romania. The search for domesdc gas reserves will be increasingly attractive as the cs oontinue to seek payment in hard currency. H. Planned Expansion of Infrastructure In Hungary, a new line is to be built from Beregdaroc on the Soviet border leading through Hajduszobioszlo and Szeged to the Yugoslav reception stadon at Horgos. From there it will continue some 600 im into Yugoslavia, ultimately leading to Belgrade. It will have a diameter of 820 mm for fte first 123 km, where at least 1 BCM per year of its projected annual capacity of 8.8 BCM wil be sent to an undergound gas storage reservoir for subsequent despatch though Kisujszallas, Szolnok and Szeged to Budapest. The remaining gas will continue southward to Yugoslavia, with up to 3.5 BCWyear available for consmpdon in southern Hungary. It is estmated thaw the pipeline will cost around $50 million, 50 per cent of which will be fieanced by the Yugoslavs by a $25 million loan, which Hungary will repay with low rnsit fees for 8 years. In late 1990, OKOT (MOL) signed an agreement with seven Yugoslav companies, Metalimpex of Czechoslovakda and Austria's OMV to examine the possibility of importing 8-10 BCM ofLNG peryearvia aregasifcation tenninal to be constrcted on the Adriatic coast either at Koper or Omisalj. In addition, a plant for emichment of poor quality gas is under construcion near Tazlar. The World Bank is engaged in a project analyzing the feasibility of a pipeline connection with the Austia transmission system from Baumgarten or Fischamend (TAG) to Gytr (approximate distance 130 km), allowing imports of gas from Austria (out of its portfolio of indigenous, Norwegian, and Soviet gas). Another option which is being studied is an additional connection with thie Cechoslovakian transmission system at Ivanka to Gytr (90 km), allowing inreased imports of Soviet gas. I. Pricing Policy Price liberalizaton has been introduced for oil products, with consequent rises in energy prices. Gas prices are still regulated. Gas prices for household consumers rose by 50 per cent on June 1, 1991. Hungry is presendy exeiencing a high infladon rate (30 per cent). The priar effect if piices ar raised and wages held oonstant will be a rapid decline in demand, particularly in the -64- APEFNIDIX 3 Page S of 6 energy sector. Gas demand, however, is less likely to be drastically reduced as it will likely be considered an essential item given its importance in the residenti and commercial sectors for heatin. Lower priority uses such as the petrochemical sector and certain industrial applicadons will take lower priority in terms of allocation of limited gas imports and as such could have lower demand in the futur October 1991 $1000 m Pricesa10 lEi M 111.32 7 29 C lr :" setr I 6.343 J-oshld w 122.26 3.24 B:=, WodtBank J. Gas Demand Forecasts Our high scenario for future Hungarian gas demand is based on strong economic growth, replacement of coal-fired capacity, increased demand for gas in all market segments, and improvements in end-use efficiency. In the low scenario, we have assumed slow economic growth, stagnating to slow growth in gas demand in all sec and no replacement of coal-fired capacity. Hungarian Gas Demand B(Nr ff 7m 25F_005 Averagel Growth Low Scenaiio I. I - 16 1. 1 17.1 2.1 I Basecs CIr 11.3 _6_ -ff.71 --T.T 7 2.7_ High Scenano 11T- --I 1.5 -77 -7.7 4T6 Indi 3.3 . 2 4.2 4.2 P ction _ S~~~~~. 6__ ; 6.0 6.0 6.0 _ _ U U ~ ~~~ 4 .-.31-10 .9 17.3_ - ;°os3-- :- 9l Source Aur D. Liue As can be seen from the table above, we esdmate that by 2000, a supply deficit of about 2.4 to 5.3 BCM mz:y have deloped, growing to 6.9 to 17.5 BCM by 2010. Ke Supply Cost Curve The cost situation of Hungary is similar to that of Czechoslovakia. Of the non-Soviet supply alternatives, Algerian pipeline gas delivered via Transmed and Monfalcone is the least costly. Soviet gas is cheaper in Budps than in Pcg, due to the shrer transport distance from Uzhgorod. As visualized in the chartb Norwegian gas would be considerably more expensive to deliver to Budapet -65- Page 6 of 6 Supply Cost Curve for Hungary: Gas Delivered Budapest $1'000m3 SIMMDtu 140 - 4.00 4 5 6 120 - 100 2 3 3.00 80 60 - ~~~~~~~~~~~~~2.00 40 - ~~~~~~~~~~~~~~1.00 0 8CM 0 5 10 15 20 25 30 35 40 45 50 Supply Options Deliverles from: 1 Soviet Gas via Beregdaroc 01994 2 Algerian gas via Transmed 1 3 North African LNG 1996 4 Qatar LNG 2000 5 Norwegian gas via Polpipe 2 6 Norwegian gas via Emden 2005 -66- APlEENlDIX 4 Page 1 of 6 Poland A. The Polish Energy Industry - Summary * Poland's national fuel mix in 1989 consisted of 78 per cent coal, 14 per cent oil, 8 per cent natural gas and 0.5 per cent nuclear and hydro electricity (Source: IlEA Energy Balances). o Natural gas has been used in most market sectors since before the 1960s. Use of gas in the residential and power generation sectors began in the mid to end 1970s. o Natural gas consumption has, since the early 1980's, grown very slowly at an average of less than 0.5 percent per annum. * The natural gas grid is not very well developed, covering most of the country but having only limited throughput capacity. * The main problems facing the government of Poland in the energy sector are the following: - Heavy reliance on domestic coal as primary source of energy, used to produce electricity in inefficient and highly polluting power plats as well as in all other market sectors - Highly dependent on the USSR as single source of gas imports - Proven/recoverable gas reserves nearing depletion - Need to find additional gas reserves and improve production facilities in order to maintain/increase indigenous production levels - Substantial need to extend gas infrastructure in order to meet demand targets and to permit imports from other sources - Need to reduce air and water pollution without impairing ability to satisfy power demand - Need to gready improve efficiency in energy end-use and to replace polluting and inefficientboiler capacity - Lack of financial resources required for investment. B. Primary Energy Supply and Demand Poland is the largest consumer of energy in Eastern Europe, by far exceeding the total consumption of for example Yugoslavia (119 MMtoe as compared with 44 MMtoe), despite the fact that its gross domestic product only amounts to about 70 per cent of Yugoslavia's. Its population is however the largest in Eastern Europe, exceeding ta of Yugoslavia with about 50 per cent. -67 - Page 2 of 6 About 80 per cent of Poland's own total energy needs are satisfied by coal, a proporion that has increased only slightly since 1980, consistent with moderate growth in overall energy demand. In addition, Poland-, along witi the Soviet Union, is a significant hard coal exporter to other East Eurpean countries and the West. Poland's coal is mosdy high quality hard coal, and as such has the potential to help both Poland and the surrounding countries to meet future growth in energy demand and improving the environment. Poland has historically exported the higher quality hard coal and used lignite domestically in order to maximize foreign exchange earnings. Hlowever, the recent economic reforms have prompted large increases in all domestic coal prices, thus reducing the relative attractiveness of this fuel compared tO il Or gas (despite the fact that oil and gas prices have also increased). As mines are given autonomy in the future and stae subsidies are cut, local demand is expected to decline in the near On the supply side, r. ionalization of inefficient and unprofitable coal mines is expected to reduce output. Exports to both Eastern Europe and the West are expected to continue in order to provide Poland with a major source of hard currency. Currently, coal accounts for 98 per cent of electricity generation, but this is expected to decline in the future in order to help reduce emissions. C. Historical Natural Gas Supply and Demand Poland's most recent assessment of proven onshore gas reserves is about 130 BCM, significantly lower dtan previous figures reported by Polish authodities. Coal-bed methane reserves could add substantially to indigenous gas reserves. Gas demand was 9.6 BCM in 1989, up from 8.9 BCM in 1980. This represents a relatively small 7 percent share of energy demand, a figure that has remained constant since 1980. Poland produced over 50 per cent of its gas requirements indigenously as recently as 1985, but since then domestic gas output has declined. Additional imports from the Soviet Union have made up for the shortfaLl The majonity of gs consumption is in the industrial sector whicb accounted for almost 54 per cent of tota demand in 1988. The residential and commercial secws consumed about 36 per cent of the total while power generation (including distict headng), which is principally fueled by coal, accounted for 6 per cent. Historically, total gas demand has grown very slowly at less than 0.5 per cent per annum during 1980-89. However, this masks strong growth lh the residential and commercial sectors where gas use increased by over S per cent per annum as a result of expansion of the gas distribution network. Other uses ofgas increased much more slowly during the 1980-89 period. D, Gas Infrastructure The Polish gas network was developed to distribute imported Soviet gas and indigenously produced gas from southeast Poland, where the Soviet pipeline enters the country and producing gas fields are located. Poland has three separt gas tansmission networks, one for high calorific value gas, one for low calorific value gas and one for coke oven gas. The three systems span most of Poland, but have only limited throughput capacity. In order to reach the targeted increase in gas demand the system would have to be cxpanded substantally. Remaining -68- Page 3 of 6 recoverable Polish reserves have been estimated to 134 BCM, but may be lower. Current production is about 3 BCM per year. E. Industry Structure Polskie Gomistwo Naftowe i Gazownistrol (POGC). !ic utility enterprise of the Ministry of Commerc, Mining and Power, adninisters 22 re . i.nizations responsible for exploration and producdon of oil and gas. Distribution of gas is handled by distribution companies, such as the Polish Gas Corpordon of Warsaw. The POGC is responsible for exploration, production, transmission and distribution of gas. It controls six regiona gas uities. Responsibility for gas imports formerly rested with Weglokoks, although negotiations wer mainly caried out by the government. Gas pipelines are mnied by regional enteprises such as the Mazowieckie District Enterprise for Exploitation of Gas Pipelines, which is responsible for all pipelines in eastem Poland including the line from Kobrin to Warsaw and its branches. nhe division of responsibilities between the Government and the state-owned energy companies is rather unclear. The Ministry of Industry exercises control over the management and activities of energy companies. The Government is moving towards a restructuring of the gas sector, assisted by the World Bank. The first move wil be to divide the industry into separate business segments which will be encouraged to operate more along commercial lines. At a later date, private capital may be invited to participate in some or all of them. F. Potential Contribution of Gas to Environmental Improvement Environmental pollution is a severe problem, caused by emissions produced by the power generation sector and by industry. 96 per cent of Polish electricity is generated from coal Qignite plus high sulfur hard coal). Realizing that it will not be possible to substitute this massive dependence on coal, the govemment first and foremost aims to clean and improve the quality of the coal which is burnt in power plants. The first priority in confronting Poland's environmental problems will be the control of emissions of particulates, sulfur and nitrogen oxides. Desulphurization plants are planned, inidally for seven power stations using high fur hard coal or lignite. The govenment expects that the coal industry will be able to finance the coal cleaning program. Investments required to reduce S02 would, however, be very large. The Polish Electricity Transmission Board estimates that a realisdc progam would cost $1 billion, hoping that foreign aid and investment wl provide much of eis apital requred. Given cunent electity doe d, replacement of coal-fired capacity with CCOT power plants could, theoretically, increase annual gas demand by between 15 and, if all coal-fired capacity was replaced with gas, 27 BCM. -69- Page 4 of 6 G. Prospects for Increased Indigenous Gas Production If indigenous gas production is to incease in Poland, more investments will be needed to step up exploration activities and improve recovery on producing fields. Exploration activity centers around an effort to make Poland self-sufficient in gas by 1996 throu coal-bed methane recovery. One out of several existing schemes for coal-bed methane recovey IS being promoted by Pol-Tex Methane Company, a joint venture fonned by McKenzie Methane - Poland of Texas, United States and the Jastrzebie hard coal mining company. The company is expected to invest $36 million to develop about 5-6 BCM of natural gas from coal seams which will not be mined in the future. Proven reserves amount to between 130 and 150 BCM of gas. The potential for new discoveries is considered to be high, reserves are estimated to exceed 600 BCM4 Since exploration activities require large amounts of capital, the oil and gas sector has been specally targeted for promotion of foreign investment opportunities. The Polish Government is trying to improve terms and conditions in order to facilitate and attract more investment. The World Bank and European Investment Bank have provided loans of $310 million for development of the Polish gas industry, Which will be used to improve indigenous production. H. Current Plans for Expansion of Gas Markets The government is aiming to increase the use of gas wherever possible, mainly for environmental reasons. A doubling of current consumption is envisaged by the year 2000. Plans include increasing use of gas in power generation. New gas fired capacity of 1.9 GW is to be constructed, which in 2005 will equal S per cent of total installed capacity. Great emphasis is also being placed on the need to increase energy efficiency, and a lot of effort will be put into reaching Western efficiency levels. The problem the govenmment is facing in tying to realize all these aims is to find reliable supply sources. Discussions are being held with both Norway and Algeria, so far without positive results. I. Planned Expansion of Infrastructure Poland has ambitious plans for expansion of its gas infrastructure in order to increase utilization of indigenous reserves as well as bring in additional imported supplies. The Soviet and Polish Governments are planning the constrction of an additonal pipeline from the Urals to the Polish border, intended to brng gas fom Western Siberia to Poland. Furthermore, a pipeline which could carry 6 BCM of North Sea gas to Poland, connecting the Polish and Danish transmission systems, is being studied by the POOC and DONG. The new pipeline (Polpipe), fom Rodvig on the Danish island of Zealand to Niecharze on the Polish Baltic coast, would be 225 km long and require capital investment of $600 million (excluding investment in required new infrastructure on the Norwegian Continental Shelf). From the Baltic Coast, the pipeline wou-i continue to Eastern Germany,, Czechoslovalia and Hungary. -70- APPENDIX 4 Page S of 6 J. Pricing Policy The Polish economy experienced very rapid inflation in 1989. Since then, inflation has been brought under control by a rigorous fiscal regime. Energy prices have been increased as part of the price liberaization program There was a new increase on May 27, 1991, when household gas pries rose by 150 per cent and industry prices by 20 per cent. Aid is to be made available to those on low incomes. Poland is expected to continue its move to market based pricing from action taken erlier this year. A substantial increase in gas prices was already enacted in early 1991, but additional price increases will be required to move totally to market prices. Furthermore, cross- subsidization is significant since the gas price inc.eases have taken place only in selected secs. Mi!d 1 $ prcesO m3 $MMStu l mpvt_ -- ~~93.W0-0 2.46 dustry 1 ~~~116.87 1 3.10 Household ___5_ _ 1 2;55 SoMIe: Wrd Bank K. G. l Demand Forecasts Our high scenario is based on strong economic growth and rapid replacement of coal in all sectors, with gas growing especially fast in the residential sector. in the low scenario, economic growth is slow to stagnant, gas replaces coal in the residential sector, but maintains its maket share in all others. Polish Gas Demand BCUM 1990 1995 200 20Qoo 2010 Average Growth Low scenario 11.F _3 1._14.6 17.1 27 Ba Case -IO. 1. 1. -Tr I6:'7 21Tf.2 3.8 fU.D- 1 e.5 14.9 20.2 28.3 5. lidig. - --3.3 3.3 4.2 5.3- 6.8 Prouction _____ ImpWts 0~~~-8.!8j -8 I 0- 8.0 8.0 D__icit o w-0.2 ' .3-2.7 I .3-6.9 2.3-13.5 Sow=c klhur D. Litlle As indicated in the table above, we predict that a supply gap of between 0.3 and 2.7 BCM will have developed by 2000, growing to etween 2.3 and 13.5 BCM by 2010. -71- Page 6 of 6 L. Supply Cost Curve In the short to medium term (deliveries beginning Wefore 2000), incremental Soviet gas volumes are the least costly and also the only sources realistically available to Poland. North African LNG delivered Poland would be more costly than Soviet gas. Despite the longer transport distance, Soviet gas fom West Siberia is cheaper if delivered via a large new pipeline to Uzhgorod with a subsequent smaller branch to Warsaw than throgh a dedicated branch to Brest-Litovsk Supply Cost Curve for Poland: Gas Delivered Warsaw $S'000 m3 $IMMMtu 160 6 7 5.00 4.00 120 1 m _ = _ 3.00 80 2.00 40 1.00 0 5 10 15 20 25 30 35 40 45 50 Supply Options: Deliverles from: 1 Soviet gas via Uzhgorod U1994 2 Soviet gas via Brost-Litovsk1 3 Norwegian gas (Polpipe) 1996 4 Soviet gas (Barents Sea) via Brest-Litovsk 32000 5 Norwegian gas via Emden 6 Norwegian LNG via Gdansk 0 2005 7 Soviet LNG (Barents Sea) at Gdansk -72- AEPENDIX 5 Page 1 of 6 Romania A. The Romanian Energy Industry - Summary e Romania's nadonal primary energy fuel mix in 1989 consisted of 30 per cent coal, 23 per cent oil, 45 per cent natural gas and 2 per cent nuclear and hydro electricity. (Source: EA Energy Balances). * Naural gas has been used mainly in the industrial sectors since before the 1960s. * Natural gas consumption peaked -t 36 BCM in 1985 and has since fallen by an average 1.5 per cent per annum. a The natural gas grid is well developed, covering most of the country with transmission and distributon lines. The main problems facing the government of Romania in the energy sector are the following. - Declining indigenous oil and gas production due to depletion of existing fields - Urgent need to increase gas reserve base and improve production facilities in order to maintain/increase indigenous production levels to meet short term demand through adaptation of apprpiate exploration policies - Dependence oL a single source of gas imports (USSR), which have been cut back substantally after the 1991 tiade agreement - Nt"'d to reduce air and water pollution without impairing ability to satisfy a ower demand - Lack of financial resources required for investment. B. Historical Natural Gas Supply and Demand Romania has the largest reserves of oil and gas in Eastern Europe. Associated natural gas deposits are concentrated in the oil-bearing fields in the south and south-east of the cou'itry. Non-associated natual gas fields are located in the Transylvanian Basin, where high quality gas is produced and udlized as a petrochemical feedstock. Estimates of remaining reserves have not been published but are believed to be between 160 and 190 BCM. During the 1980s, there has been an overall decline in gas production due to lack of investment in the energy sector. The outlook in the post-Ceausescu era appeas more favoable. Six Romanian rigs are actively drilling for oil and gas in the Black Sea, with production already beginning in two fields reported to have modest reserves. Westem companies are eed to ast the government in the upstream sector in men near future. Ronanian as demand, which is supply driven, was 34 BCM in 1989, compared with 36 BCM in 1985 and 34 in 1980. In l9, nat:al gas consumton fel to 28 BCM of -73- Page 2 of 6 which over 80 per cent was used in industry and for power generation. Gas represented 45 per cent of the total energy supply in 1989, the highest figure of any East European country and one which has declined only slightly from about 48 per cent during the early 1980s. Of the total gas supply, 82 per cent was produced domestically (1989) while the remainder was imported from the Soviet Union. Gas imports have been incng, especially since 1987, as domestic production has declined due to field operation diffiulties, pipeline problems and strikes. Imports from the Soviet Union have, howeve, under the 1991 tade agreement, been cut back substantially from their 1990 level of 8 BCM to an annual 3 BCM The decline in domestic production was especially pronounced from 1988 to 1990 when domestic production fell by almost 9.4 BCM, of which only 4.2 BCM was offset by increased imports. Gas consumed by the petrochemical sector has remained about constant. Recently, a shortage of electricity and gas feedstock for petrochemical plants has resulted in power shortages and a major downturn in petrwhemical output. Fertilizer and methanol plants were operating at about 52 per cent of capacity during 1990 and were thought to have shut down during the winter of 1990/91 without any announced reactivation. Gas supplies, which have dwindled during 1991 due to strikes in the energy industry, are being diverted to the now higher priority residential and commereal sectrs for lighting and heating requirements. C. Gas Infrastructure Romania's transmission and distribution systems were developed to distribute indigenously produced gas to main centers of consumption around the country. Gas is imported from the Soviet Union via a pipeline entering Romania from the east. Apart from an area in the Carpathian mountains, the country is relatively well covered with both transmission and distribution lines. The gas distribution system covers some 25,000 km. Romania has Eastern Europe's largest gas fields, located primarily in the south and southeast of the country and in the Transylvanian Basin. Natural gas is accounting for over half of the country's energy production. Reserves are, however, being depleted at an excessive rate, and will be exhausted by the late 1990s if the current production rate is maintained, unless new discoveries are made. Total gas production in 1990 was 28 BCM (down 12.5 per cent from 1989) and is expected to fall to 25 BCAM in 1991. D. Industry Structure Romania!s energy sector is still firmly under government control. A rew natural gas corporation, Romgaz, was created in early 19z1 to take over the assets and activities of an organization known as Gas-Methan or Gas-Centml (which was an autonomous public sector enterprise). The company explores for, produces, transports and distributes natural gas within Romania. Associated gas is produced by Petroni, a state-owned national oil company which is involved in domestic exploration for, and production of, oil. State-owned Petrolexport exports and impot petroleum products and natural gas. E. Potential Contribution of Gas to Environmental Improvement In 1989, 41 per cent of Romanian electricity output was generated from coal (mainly lignite), while gas contributed with 25 per cent, hydro with 17 per cent, and oil with 18 per cent. Romania has, in recent years, had a policy to use indigenous low calorific value coal for power generation Many old coal-fired plants are, however, in bad need of repair due to damage caused * 74- Page 3 of 6 by burning too low quality fuels. If lignite-fired capacitv were exchanged for modern gas-fired CCGT power plants, substantial reductions in atmospheric pollution could be achieved. We predict that given current electricity demand, replacement of coal-fired capacity with CCGT power plants could, in theory, lead to an annual increase in gas demand of between 1.5 and 6 BCM (depending on the amount of capacity replaced). F. Prospects lwr Increased Indigenous Gas Production Non-associated gas production in 1989 was only 18 BCM from an estimated reserve of 91 BCM. Non-associated gas production will continue to decline unless new reserves are discovered. At the present level of production, non-associated gas reserves will soon be exhausted (early 1990s). In order to offset the rapid decline in production levels, Romania is hoping to be able to cut back flaring of associated gas. A region with gas potential is thought to be the Black Sea, where it is estimated that some 100 BCM may be located. Exploration and production is, however, bound to be expensive. The goverment has initiated a comprehensive assessment of the country's hydrocarbon potential which is to be financed by a World Bank Technical Assistance loan. The study is aimed at identifying areas which have good gas potential, including the Carpathian mountains. Foreign investors have been invited to bid for 13 exploration blocks. However, due to logistical and legal constraints, this has been delayed, although many companies have indicated a preliminary interest to particpate for development of the gas sector. G. Futu-e Gas Supply and Demand Romania is expected to maintain indigenous production at the 1990 level of 25 BCM tbrough 2000 as a result of increased investment from Western private and institutional organizations and technical assistance for field maintenance. In the short term, imports from the Soviet Union as well as cuts in flaring of associated gas (estimated at 2 BCM) will prevent over- depletion of Romania's remaining gas reserves. As a result, imports will increase to 7.5 BCM by 1995 after which further increases in demand will require additional imports of 3.3 BCM per annum. Much of the growth in demand will be in the residential and commercial sectors where gas use for lighting and heating is be ng a priority. Power generation and petrochemical users will also show modest growthi in gas demand while industrial use will decline as plants are closed and efficiencies increased. H. Pricing Policy Under the Ceausescu regime, Romanian energy prces and consumption were closely controlled by strict rationing and supply interruptions. Energy pries continue to be subject to regulation against the background of the country's shortage of ener8g. There is a wide gap between international energy prices and prices for both domestically produced gas ancd energy product retail prices, parucularly for household energy (at realistic exchange rates). In some cases, pnces have even been set below cost. -75- AEEENDILI5 Page 4 of 6 .I1l 1Y$P rOrlces $ 0ml u R!je i 93.72 2.48 57.17~ Housebolds S7.17 l.Sl Sowve: Wdrld Bank Prices for domestically produced gas were raised by 10 per cent in July 1991. Based on the official exchange rate of 60 lei per dollar, the price of domestically produced oil was raised to $132 per tonne, matching current prices the country pays for oil impots fiom the Persian Gulf and Libya. Under the existing policy, the gas price will continue to be increased by the Government every quarter by 10 per cent, until the price reaches the international import price level. Currendy, the price to industrl users is Lei 3550 ($ 57.2) per thousand Nm3, compared to the import rice of $ 95 per thousand Nm3 from the Soviet Union. The gas price to household consumers is however being held constant at Lei 1000 per thousand Nm3. There is thus a need for some form of transitional programs for gradual adjustment of energy prices to international parity luvels. For tradable energies (i.e. energies for which do not have natural monopoly characteristics and for which prices are set by free interplay of supply and demand such as oil and coal), this cot'.1 for example, be achieved by a system of periodic price adjustments, until prices can be set by market forces. For non-tradable energies (energies with natural monopoly characteristics, such as natural gas and electricity), an acceptable pricing philosophy must be decided on; i.e. should they be priced on value, or on cost? If it is decided to price them on cost, the cost of providing these energies must be calculated in order to set a corresponding price. In a first step, prices couldbe set to cover operating costs and eam gradually increasing operating profits, thus contributing to covering capital costs, to be replaced, in the long term, by fuel-cost tariffs. Romania is faced with a hyper-inflationary environment in the short term The primary effect if prices are raised and wages held constant will be a rapid decline in demand, particularly in the energy sector. Gas demand, however, is less likely to be drastically reduced as it will likely be considered an essential item given its importance in the resiental and commercial sectors for heating. Lower priority uses such as the petochemical sector and certain industrial applications will take lower priority in terms of allocation of lmited gas imports and as such could have lower demand in the future. The financial difficulties of energy institutions are due to inadequate pricing, rapid build-up of accounts receivable and payable, and to a general shortage of capitaL Romania needs a plan to deal with financial restructuring of the energy organizations, as well as an overall reorganzaton of these entrises within the fiamework of an overall macroeconomic program. I. Gas Demand Forecasts In our low scenario we have assumed slow economic growth and limited replacement of nther fuels in order to improve the enviromnent. The high scenario assumes strong economic g1owth and replacement of coal-fired power geneation capacity in order to reduce air pollution. -76- APPEbMI Page 5 of 6 In all three scenarios we have assumed that indigenous production ceases after 1995 to reflect current R/P ratio. The emerging sucppy gap should, therefore be seen as an indicator for the need for new imports as well as the need to find and develop new indigenous resources. Romanian Gas Demand BC9 1995 200 verage Growth Low scenario 33.2 30.5 32.0 33.4 6 0.2 Base Case 33.2 30.5 33.2 _36.7 _41.11. High scenario 3. 1 35.7 43I31.2 2.2 Ind. Producton 24.6 m 0 _ lMner 8. 5 r 3. 3.0 . Deficit O 2.9-3.4 29--32.7 3040.1 31.6-49.2 Sougcw: ArthurD. Li#e ,As can be seen in the table above,, we foresee that a supply deficit of around 30 BCM may have developed by 2000, growing to between 30 and SO BCM by 2010. J. Supply Cost Curve rWe have calculated the cost of bringing ps from five different supply sources to Rtomania. In the short to medium tnn incrementa Sovnet gas and North Afiican LNG are the least costly alternatives. In thes long run, however, incremental Imnian gas could be delivered at lower cost than all other supply alteimatives. -77- Page 6 of 6 Supply Cost Curve for Romania: Gas Delivered Bucharest 211f m3 $USMM@ 150__ 4.00 120 4 - 3.00 80 X 2.00 60 40 1.00 20 0 9C I I I I I J M 0 5 10 15 20 25 30 35 40 45 50 Supply Options Deliverles from: 1 Iranian gas 01994 2 Soviet gas a Ismail 1996 3 Algerian pas (Tranamed) 2000 4 NortAfcan LNG2000 5 Qatar LNG a 2005 -78- Page I of 7 Yugoslavia A The Yugoslavian Energy Industry. Summary * Yugoslavia's naonal prniay energy fuel mix in 1989 consisted of 42 per cent coal, 38 pa cent oil, 13~ pesoent naral gas and 7 per cent nuclear and hydro electrcity (Source: * Natual gas has been used since before the 1960s. * Natual gas consumption has grown at an average annual rate of 9 pu: ent between 1980 and 1989. * The natral gas grid is not very well developed, consisting of two separate networks, covering only small parts in the north (Slovenia/Croatia) and east (Serbia/Bosnia- Hercegovina) of the country. * The main problems facing the government of Yugoslavia in the energy sector are the following: - Need to find additional gas reserres and improve production facilides in order to maintain/mcrease indigenous prduction levels - Largely dependent on a single source of gas imports (USSR) - Aim to increase use of gas at the expense of high-polluting oil and coal con- sumption c Large need to extend transmission/distribution network in order to meet targeted increase in gas consumption - Need to reduce air and water poUution without impairing ability to satisfy power demand - Lack of financial resomves required for investment - Need to find additional hydrocarbon reserves - Need to restucture the energy sectors ar.d increase energy prices to world market price levels. B. Historical Natural Gas Supply and Demand Yugoslavia has estimated proven gas reserves of 82 BCM, of which two thirds are located in Croaia and one thind in Vojvodina. Output from new fields (Molve, Sari and Gradec, among others) in the Podravina region have aed sigcanty to production. Originally thought to be a good prospem the North Adriatic has proved dispointig. Reserves at two North Adriatic fields (lvana and Ika) are about 6.5 BCM and production is expected to reach 0.5 BCM in 1991 but only continue for about ten yeas -79- AITEIDI 6 Page 2 of 7 The 6.1 BCM of gas consumption in 1989 represented 13 per cent of total energy demand versus only 8 per cent in 1980. Yugoslavia is the second smallest gas user in Eastern Europe next to Bulgaria but is planning to increase gas consumption significantly in the future. New fields have been developed (3 olve), but the increase in gas use of 2.2 per cent per annum has mainly been met by imp mstic prodution has not increased as quickly as demand, causing imports to rise by an avge 12 per cent per annum during 1980-89 (to 3.6 BCM). Yugoslavian gas demand has historically been spread relatively evenly across fte power generation, energy, petochemical, industrial and residentialcommercial sectors. Over time, gas use in power generon and industry has declined. C. Gas Infrastructure The Yugoslavian network is rather small, consisting of two systems which are not interconnected. The Serbian gas system brings imported Soviet gas from the Hungarian/Romanian border at Horgos in Vojvodina to main consumption centers in Serbia and Bosnia-Hercegovina. Approximately 1500 km of pipelines of varying diameters distribute gas to Nis, Sarajevo and Belgrade. The network mainly serves large industrial customers. Recently, Energogas resumed extension of a Soviet tunkhne which will increase imports of Soviet gas transited through BulgrdiL Makpetrol of Macedonia also has plans to constuct a pipeline for imports of Soviet gas ftrough Bulgaria, which however would not binterconnected witi fte Energogas-pipeline. The Northern network is used to transport Sovict gas from the Austrian border, entening the country at Maribor, to major cities in Slovenia and Croatia. INA-Naftaplan operates an underground gas stoage facility at Okoli (Croatia), having a capacity of 0.35 BCM, which will rise to 0.5 BCM on completion of the second stage of development. A further 0.48 BCM gas storage facility is being built at Bantsld Dvoii. Others are planned in Bosnia- Hercegovina and Slovenia. A pipeline connection with the Italian trasmission system at Monfalcone is presently under construcdon. Yugoslavia has some indigenous gas reseves. At present, the largest field in operation is Molve, with a yearly production of 0.8 BCM. Gas has also been found in the Adriatic (Ika field), but reserves are thought to be small D. Major Gas Purchase Contracts As part of an armngement to reduce Yugoslavia!s trade surplus with the USSR, new agreements have been worked out, according to which the USSR will deliver up to 12 BCM per year by 2000, which is more than double the current contract quantities. The Soviet Union will also supply pipeline equipment and engineering for development of gas networks in eastern Yugoslavia. An annual 0.6 BCM of Algeran gas to be delivered via Italy, has been negotiated by the Slovenian company Petrol lkely to be available from the end of 1991. -80- Page 3 of 7 E. Industry Structure Six regional companies hold responsibility for supplying their respecdve supply areas with natur gs. no sx oare Energopemol Bosnia-Hercegovin Energogas Serbia INA-Naftaplin Croaia Naftagas-Cas Vojvodina Makpetrol M Petrol Slovenia Only two companies are engaged in natural gas producdon (INA- Naftaplin and Naftagas-Gas). INA is active onshore within Coat and offshore in the Adriatic. Naftagas only has onshore production in Vojvodina and Serbia. Import contracts are negotiated separately by all companies, without need for Federal approvaL F. Potential Contribution to Gas Environmental Improvement The expressed objective of the Yugoslavian energy policy is the efficient supply of optimal quantities of energy at modert cost without causing damage to the environment Special emphasis is to be put on the reduction of polludon. Energy producers, especially powerplants and coal mines, are characterized as the worst polluter Fundamental changes to the entire energy sector are required, including a change in fuel mix for pow& generation, which is currently heavily dependent on coal There is a strong environmental movement against and a atum prevnting the development of new nuclear power. Yugoslavia has one nuclear power plant. The Govenmuent's policy is not to develop any new nuclear power before 2000. Apart from cleaning up coal-fied stins, po on of increased use of gas in power generation seems to be the only option available if airpollution is to be reduced. Emission control regulations requiring the use of cleaner coal have already been implemented. This will cause significant increase in costs, singe neither industrial or power generation plants are fitted with adequate emssion control devices. The authoides are detemined to cut pollution, but it will take ti, since the country has more urgent problems to be dealt with, and capital is scarce. A fedeml ecology tax has been discussed, but not implemented so far. Development of the Ika gas field in the Adriatic would have the advantage of both contributing to reducing the local energy shortage and allowing a cut in poli ition fom fuel oil and coal burning industries and power plants in the Rijeka area. The pxject has however been hold up by a prie discussion between INA-Naftaplin and the Croatian Electicity Boaid. G. Prospects for Increased Indigenous Gas Production Yugoslavia is planning to increase indigenous gas production from the current 2.6 to more than 6 BCM by the end of the century, in orde to supply the planned expansion of gas use. This may be a difficult target to ealize, considering the heavy mnvestments which would be required and uhe present lack of financial resources. -81 - Page 4 of 7 Since 1988, offshore exploratory operations have been camed out by foreign oil com- panies. Output on the Molve gas field will mcrease by 1 BCM per year to 1.8 BCM, due to recent addition of further gas processing installations. INA-Naftaplin is however uncertain about the prospects of finds In the northern Adriadc, and prefers to concentrate invesunents on the Molve gas field rather than investing offshore We predict that given cuTent electricity demand, replacement of coal-fired capacity with CCOT power plants could lead to an increase in annual gas demand of between 3 and 9 BCM (depending on the amount of capacity replaced). H, Current Plans for Expansion of Gas Markets A major shift of policy in favor of natural gas is taking place. In general, Yugoslav gas consumption is expected to double over the next the ten years. As in many other East European countries, the shortage of funds may however force these plans to be moderated, unless foreign investors can be attcted. The increase in gas supplies is expected to came mainly from imports, primarily from the Soviet Union, but alro from indigenous producdon. I. Future Gas Supply and Demand The outlook for the Yugoslavian gas sector is very positive. The Govemment is stressing displacement of coal and oil with gas in a wide range of industries, primarily in the power generation sector. Though official forecasts suggest a doubling of gas demand by 2000 from the 1989 level of 7.3 BCM, a more realistic estimate, taking into account capital constraints, has demand growing to 8.2 BCM in 1995 and to 10.7 BCM in 2000. With limited domestic reserves, and exploration efforts yielding only modest discoveries, most of the incremental demand will have to be satisfied by imports from a variety of new pipeline projects connecting Yugoslavia with the Soviet Union and Iran (via new links between other East European countries) and Algeria (with additional links through Italy or by means of an LNG import terminal). As of 1991, Yugoslavia is receiving gas impots from Algeria through a pipeline connection with Italy. The driving force behind increasing gas demand in the future centers around environ- mental concerns and expansion of the gas distribution system. The residential/commercial and power generation sectors will grow fast, as new (Serbia, et al) and renovated (Belgrade) distribution systems and conversions of oil and gas power plant units are completed Most of the forecast incremental gas demand in the power generation sector will be from displacement in coal and oil-fired stations. There are plans to build a gas-fired power plant in Slovenia. Other planned power stations could also be gas-fired. Growth is also significant in the transformation (including own use and losses) category given that production declines will require additonal gas volumes for field use. J. Planned Expansion of Infrastructure The current capacity of the existing Yugoslavian network is insufficient to handle the quanddes of gas which are expected to be produced locally and imported from the USSR and Algeria by 2000. Yugoslavia has very ambitious plans for the extension of its gas transmission system, which would require large investments if they were to be realized in full. Apart from construction of tansmission links and distribution lines to major users all over the country, -82- AEPEEMK 6 Page 5 of 7 it will be necessary to link up with the Italian, Austrian and Hungarian systems for further imports of gas from Algeria and the USSR to be possible. An extension of the network would also provide an impetus for increased domestic production, which is planned to increase to more than 6 BCM by 2000. Construction of underground storages, which will have a total worldng gas capacity of 1 BCM by 2000, is underway for Croatia, Vojvodina, Slovenia and Bosnia. In Vojvodina, where much of the indigenous gas is produced at present, domestic networks will be developed in all major residential areas. In Serbia, the USSR is helping to build a 160 km pipeline, which will bring Soviet gas transited across Romania and Bulgaria (completed end 1990?). Energogas has proposed a $160 million pipeline expansion program to be realized before 1995. It would include construction of 670 km of transmnssion and distribution lines and 120 km of urban networks, extending to central and southeaste parts of Serbia and Kosovo. The BelIrade gas system will be renovated with financial help in the form of soft export credits offered by the Italian government. Italgas has signed a contra to assist in the development of the Serbian gas system. There have been plans to interlink the Northern and Southern pipeline networks, but so far vety litde movement on this front. The new link with the Hungarian system, which will bring in new Soviet supplies, is aeady under construcdon. The pipeline will be 600 km long, and have a capacity of 7 BCM per year. It is planned to be completed by 1992 and to supply 170 large industrial customers and 250,000 households. K. Pricing Policy Yugoslavia suffered hyper-inflation in 1989, with annual inflation rates reaching 2600 per cent. A market approach to energy pncing has been preferred, with attempts to increase historically low energy prices to levels which are more realistic from an iaternational price spective. The future of the pricing policy and the status of the Yugoslavian Dinar are affected by current political uncertainties. Yugoslavia is faced with a situadon of very high inflation and, with the current political instability, could be forced to taken draconian economic corrective measures after the regional crises are resolved. L. Gas Demand Forecasts In our low scenario, we assume the economic recovery from the effects of the civil war to be very slow, with limited investments in environmental improvement measures, and consequently, limited displacement of fuel oil and coal. In our high scenario, we assume strong economic growth, with a gas market developing in the residential/commercial sectors in the rebuilding period from 1995 to 2000, and some replacement of fuel oil and coal fired capacity in order to reduce emissions. -83- Page 6 of 7 Yugoslavian Gas Demand 2903 _MI- Average Growth Low scenario 6.9 7.8T 13 14.9 9 |8~S : Bw W6.2 8.3 1.9 l scean 7.9 9.6 9.0 13.1 17.5 4.9_- Ind. Produc- 2.5 1T.8 2.3 2.3 73S tion __ _ _ _ g linp ~4.4 I4.4 I5.7 _5.7 YT IDeficit 1 0-04 083.-96193I Sourc: Athur D. Lite As indicated in the table, we predict that a supply deficit of up to 1 BCM may have developed by 2000, growing to between 6 and 9 BCM by 2010. M. Supply Cost Curve If the proposed LNG terminal in northern Yugoslavia (either at Omisalj or Koper) and the Iranian pipeline are built, Yugoslavia will have access to tree relatively low cost supply sources: Algerian or Libyan LNG, Algerian pipeline gas delivered to Monfalcone, and, from 2000 onwards, Iranian gas via Bulgaria. Incremental Soviet gas would be more cosdy if delivered via the new pipelines assumed in the analysis. The cost delivered Belgrade would be approximately $95 per 1000 m3 (approx. $2.50/MMBtu), which is considerably higher than Algerian gas delivered via Transmed ($84.63/1000 m3). -84- Page 7 of 7 Supply Cost Curve for Yugoslavia: Gas Delivered Belgrade $"000 m3 $IMMBtu 180 - 4.00 160 - 3.00 120 4 3.00 2 - ~~~~~~~2.00 8012 40 1.00 0 ~~-'------'--------SBCM 0 5 10 15 20 25 30 35 40 45 50 Supply Optons Deliveres from: 1 Iranian gas U 1994 2 Algeran gas via Transmed 19 3 North Afrlcan LNG 1996 4 Qatar LNG 2000 a2005 Forecasts and Assumptions .86- -PENDIX7 Page 1 of 6 Overview of Forecasts and Assumptions Used Natural Demand In Eastern Europe (BCM) 1990 ~ ~ ~ ~ ~~~- 2010 --2 l0 i lfw~ (Low Case) (Base Case) (High Case) B'Iia 6.5 7.0 7.7 17.2 Czechoslovakia 12.9 88 - -26.0 30.9 M4=ar 11.3 17.1 19.4 2.7 l Poland 10.1 17.1 21.2 28.3 Romania 33.2 36.6 41.1 51.2 Yugoslaia 6.9 14.9 1 15.5 1 17.5 Total 80.8 1,09.5 130.917. Base Case The Base Case econoniic oudook for Eastern Europe as a whole is characterized by a sharp decline in economic output between the years 1990 to 1995, as industries close and the economy restructures, a period of declining to very slow growth. From 1995 to 2000, as countries adapt to market economic conditions, typicnl GDP growth rates have been assumed to be 0.5 to 1.5 per cent per annum. We have assume thle period from 2000 to 2010 to be one characterized by higher growt rates, typically 2 to 3.5 per cent per annum of GDP growth as the fee market takes hold. Energy growth will be charactized to some extent by the wish to move away from oil and solid fuels towards natural gas. Consequently, gas demand is forecast to fall by only 0.3 per cent per annum during the difficult period to 1995, during which time its overall market share may increase to up to 30 per cent. The residential sect is the only sectr which is forecast to experience growth to 1995, driven by the increased availability of gas which is planned for several major cities which cunendy suffer from air pollution caused by the use of lignite and other solid fuels in the home. The residential sector is forecast to experience much higher growth rates than other sectors, reflecting the pattern experienced in many of the West European economies, notably the UK, Netherlands and Germany, during the 1970s. Industrial energy demand is forecast to suffer the greatest reduction during the petiod to 1995, reflected by a drop in industrial gas demand of 1 per cent per annum. From 1995 to 2000, industry may recover, with a resurpnce in heavy industy, now fueled by natural gas rather than by solid fuels. Lighter industries will begin to emerge also during this penod, although at a slower rate. The basis for this assumption is that Eastern Europe may be better placed to operate the heavier, energy intensive, mature technology type industres than its Western neighbors, as labor costs are expected to remain well below Western equivalents. Similarly, Eastern Europe may, due to lack of technologica/commercial know-how and real competitive advantage, not be able to develop significant alternative industries in the service/high technology sectors within the time frame of this forecast. -87- Page 2 of 6 The use of gas an the power generat:on sector is expected to increase most sharply in the period 1995 to 2000, as existing solid fuel based district heating systems are switched to natual gas, and as highly efficient stand alone systems begin to be constructed, a trend which is expected to contnue throughout the period. The methodology employed to describe natural gas supply is based on curent plans, existing contracts and reserve/production ratios. The supply forecasts are identical for the base, low, and high cases, which allows consistent comparisoii of the relative supply gap for each case. The oudook may be used to identify the implications of demand forecasts on requred investment in production capabiity or imported gas. It does not, however, provide a view on how gas supplies might develop, and should thus not be treated as a supply forecast (for example, we expect Romania to continue to produce indigenous natural gas throughout the foecast period, despite the low reserve production ratio, with production ceasing in our outlook in 2000 rather than as per R/P ratio, in the early 1990s). The High Gas Case and the Low Gas Case The High and Low cases represent sensitivities on the Base Case forecast, indicating the range of uncenainty within which forecasts must be viewed. The economic outlook features corespondingly higher/lower growth, which is reflected in overall energy demand and natural gas demand. Natural Gas Demand Outlook for Eastern Europe a- Low Case - Base Case 200 - High Case _3_] 100 50 1980 1985 1990 1995 2000 2005 2010 a Inchldes Bugu ia, H y,Pad, Roaia and Yugoslvi - 88 - Page 3 of 6 The difference between Low Case gas demand and Base Case gas demand in 2010 is shown to be 21.5 BCM, which is approximately 50 per cent of the difference between the High Case and the Base Case, at 41.8 per cent This reflects a combination of two effects, the likelihood that the sharp econonic and energy-use decline in the early 1990s will impact fuels other than gas, and that new energy demand may be satisfied by increased use of natural gas. The elasticity of natural gas to energy demand is low during times of recession, as transmission and distribution infrastructure which is already in place is not likely to be underutilized. The elasticity may be considerably higher in times of economic and energy-use growth, fueled by the desire to improve living standards in the residential sector, and to increase efficiency and reduce environmental damage in other sectors. Case assumptions vary consider.:bly by country. For example, natural gas use in Bulgaria, which is not expected to develop its gas network significantly, features very low Low Case and Base Case Growth, but very high High Case growth. This reflects the low level of gas use planned by the government, and the high potential for gas development should the Pannonian basin prove to be gas-prone. The Yugoslavian out'ook, on the other hiand, features all three cases with gas use in 2000 at two to three times the 1990 level, reflecting the existing "gas culture" and the strong likelihood of a natural gas based energy future. Bulgaria Unlike most of Eastern Europe, Bulgaria plans to base its energy future mainly on the introduction of clean coal technology and continued development of indigenous solid fuel reserves. The Low and Base Case demand scenarios each depict an en;rgy future where existing gas infrastructure is upgraded and better utilized, but not expanded significantly. The High Case assumes that the Government reverses its decision to limit future gas imports from the USSR, connects to the Western European gas network and develops indigenous gas reserves which, though currently low, have the potential to increase rapidly following exploration by Western companies in previously unexplored areas. Indigenous gas could thus be used to displace oil consumption and give gas a share of the overall energy market roughly corresponding to that held by solid fuels The high gas case also features the development of a residential gas market around the turn of th century. The wide range oetween Base Case and High Case gas demand illustrates the level of uncertainty which remains about Bulgaria. About half of Bulgaria's natural gas consumption is curntndy used in the chemicals industry, which may decline, leaving spare pipeline capacity to servce any new industries requiring natural gas. On the other hand, the pipeline which transports Soviet gas to Greece, which is believed to have up to 50 per cent spare capacity available, could initiate the development of an integrated network across Bulgaria. Czechoslovakia Natual gas demand in Czechoslovakia is forecast to increase fom 12.8 BCM in 1990 to between 18.8 and 30.9 BCM by 2010. From a relatively slow start during the period 1990 to 1995, when demand growth is forecast at 1.4 per cent per annum, natur gas is expected rapidly to displace lignite, particularly in the heavily polluted major cities. Up to 7.2 BCM (ow calorific value) town gas may be replaced with naura gas by 2000, and th=re are plans to replace 168 coal- based CHP heatng units in the same time period. -89- Page 4 of 6 Our gas forecasts are consistent with government plans to increase gas use to 25 BCM by 2010. The IEA statistics do not identify separately gas use by the comlmercial sector in Czechoslovakia, or any other East Eurpean country. Other sources identify approximately half of the gas use of the IEA s "Residental Sector" as belonging to the "Commercial Sector". Energ pricing in Czechoslovakia features, by Western standards, relatively high gas prices and very low solid fuel prices to both industry and the residential sector. Solid fuel prices may increase up to 500 per cent by 1995 from January 1991 levels, depending on what level of income is socialy achievable by the Govemnment. Hence the relative price of gas against its major competitor is expected to improve substantially, again supporting the oudook for increased gas demand. Hungary Hungarian gas demand is forecast to increase from 11.3 BCM in 1990 to between 17.1 and 27.7 BCMI by 2010. The Base Case forecast of 19.4 BCM by 2010 reflects the view that cheap impored coal may displace very poor quality indigenous coaL giving naturl gas a relatively modest increase in market share. The Base Case also reflects the impact of the Govement's planned 'flexibility factor", wvhereby energy demand is forecast to rise at 30 - 40 per cent of the rat of increase in national income. ITe pian may prove to be too ambitious, but its impact should not be discounted, given the Hungarian interest in energy efficiency and, by East European standards, strong tradition of looking West for new ideas and innovation. The rate of new connections in the residential sector is expected to be slow during the period 1990 - 1995, at 14 per cent per annum. The rate of connection is likely to pick up again once the shock impact of market pricing has wonm off. The erat of connection is unlikely to reach the 12 per cent per annum which was typical of the 1980s, as the grid will become much larger, but the smaller percentage increases represent an increasing number of actual connections per annum. Hungary may begin to build gas fired power generadon capability fom 2000 to meet surging demand for electriity. The period before 2000 may see more coal to gas displacement. Poland Increased use of naturl gas in Poland will occur most strongly in the residential sector, progressively displacing indigenous coal, and representing an increase fom 2.9 BCM in 1990 to between 7.7 and 17.0 in 2010. The wide gap between Low and High case highlights the Polish dilemma about coal, which cunently dominates the primary energy mix, representing 78 per cent of total primary energy demand in 1989. The environmental pressure to meve towards gas in cities, to address the seious air pollution problems, and to diversify away from coal is balanced by social pressure to protect the coal industry, wbich is likely to suffer from sharply reduced demand both at home and abroad. Other sectors may experience more modest growth in gas demand, with the key uncertainty being the aviability of indienous pas Poland has ambitious plans to develop coal-bed methane, which, if successful, may lead to gas icreasing its markt share in all sector. -90- APPYNEX Page 5 of 6 Romania Representing 45 per cent of pimary energy demand in 1989, the use of gas dominates Romanian energy. 1990demand of 33.2 BCM is forecast to rise to between 36.6 and 51.2 BCM by 2010. The hw gas demand case reprsents little development of the gas network, the existence of which is the key factor which may prevent a sustained reduction in gas use. The Romanian energy outlook is complex. There is considerable waste of energy in the industry and power genemion sectors, where gas demand may be reduced by up to 25 per cent through the implementation of basic conservation measures Underlying this, there is considerable unsatisfied demand in the residential, commercial and industral power generadon sectors, which all have been subject to rationing and supply cuts dwing the 1980s and 1990s. The supply side gives little fim indication about the way in which energy will be used in the future. Oil, which is relatively abundantly available, is too valuable to be used to satisfy indigenous demand, as it is the main source of export revenue. There are limited indigenous coal reserves, and the mainstay of energy demand has traditionally been indigenous gas. Gas has been over-produced and sold cheaply to feed highly energy intensive industries. The cumsent reserves to production ratio indicates that gas reserves will run out in the early 1990s. The forecasts are based on the view that energy demand will reduce by up to 30 per cent per annum in the period 1990 to 1995, and that this will be reflected im a reduction in gas demand of up to 17.7 per cent per annum. Being driven by supply rather than economic growth, we expect gas to continue to dominate the Romanian energ balance, fed mainly by gas from new discoveries, but also by continued imports from tadidonal supply sources. The development of the residential sector is subject to the greatest uncertainty, with demand estimates in 2010 ranging between 2 and 11 BCM. There is a considerable latent demand for heating and hot water, and an existing transmission network which could take gas to the centers of demand. The cost of further 6,velopment of the distribution network, and the ability of con- sumers to pay for gas supplies are, however, serious barriers to the development of a residential gas market Yugoslavia Natural gas demand in Yugoslavia is forecast to increase from 6.9 BCM in 1990 to between 14.9 and 17.5 BCM by 2010. This is based on te assumption that the current political difficulties are resolved permanendy during the period 1990 - 1995. For the purpose of this forecast, we have treated Yugoslvia as one country, despite the fact tdat each region may pursue separate, rather hn joint, polces in the future. Industial demand features an average decline of 6.4 per cent per annum over the period 1990 to 1995, which represents a very sharp decline in 1992i93 and a steady recovery theafter, displang coal. The residential sector features the highest growth, with a Base Case growth rate of 10 per cent per annum between 1995 and 2000. This rflects the small size of the sector at present, and ambitious plans to cconect Serbian homes to the gas network in order to reduce air pollution -91- Page 6 of 6 Gas use In power generation is expected to m aely double o the tme fhame, as existing coal fired capacity is refitted to bun gas to combat arpolluion. No gas fired COT genezation capacity is planed Overal, Yugoslaian g deman a sbare of primary eerg derand was 3 pe2 cent in 1989, expeed in he o foreat to increse to aoud 20 per cent by 2010. -92- Page 1 of 4 THE WORLD BANK SEMINAR Natur Gas in Easten Europe Regional Issues and Opdons London, January 16-17, 1992 Lst of Paldpants Mr. R.f.M. Lubbers, Prime Minister, lhe Nethernds The Rs Hon John Wakeham MP, Sectay of Sate for Energy, United Kingdom Mr. W. Wapeha, Vice Psdent, World Bank Chairman Bulgaia Mr. IL Stoykwv vice minister Ministry of Industry and Trade Ms. V. Hstva-Achoundova Chief of Deparment Ministry of Idustry and Trade Mr. A. Popov President Bulgaraz Czech Sloa Federal Republic (CSFR) Mr. V. Ludvik D lrecto, Federal Distribudton Cid Federa Mistry of Eonmy Mrs. Ptackova CP.p. Mr. V. Stepan Deputy Director Genal CP.P. Mr.A Demko Dirwcor Economics Depa t S.?.?. Hungary Mr. T. Jaszay Assint to the Deputy Stap Secetary Mistry of Industry and Trade Mr. P. Liged Head of Depament of Energ Supply Ministry of £dustry and Trad -93- Page 2 of 4 Mr. J. Subal President MOL Polnd Mr. K Adamczyk General Dimctor Energy and Fuel Management Deparment Ministry of Industry and Trade Mr. M. Kazmarczyk General Maager PONG Mr. A. Fmdzinsld Director for Gas Industry PONG Mr. A. Brach Economic Director PGNG Romania Mr. D. Popescu Secretary of State Ministry of Industry Mr. N. Pavlovsld Rompaz Mrs. ML Neicu Counsellor Ministry of Inustry Yugosava Mr. S. Spasic Assutnt Federal Secretary for Energy Federal Secretaiat for Energy & Industry Algeria Mr. FK. aid Vice Preent Sonatrach Mr. H.L Mefti Chahman Consel Aodu Fonds de Participation Iran Mr. A. Moshtaghlan ExploratIo and Production NIOC -94- Page 3 of 4 The Neherlands Mr. R. Bemer Direco of as Policy Ministry of 1conomics Affairs Mr. 0. R B. Verbeg Commercial Managing Diector Gasunie Norway Mr. G. Gjerde Assistant Director General Ministry of Petroleum and Energy Mr. P. Lindberg Vice President Statoil United Kingdom Mr. R. J Priddle Deputy Secrettary Depament of Energy Mr. E. H M. Price Chief Economic Adviser Department of Energy Mr. W. C F. Butler Head, Upstream Gas Branch Departmnent of Energy Overseas Development Adnlwtradon, UX. Mr. L B. Smith Head of Department, Joint Assistance Unit, East European Department Mr. R. Jenkins Deputy Head of Department, Joint Assistance Unit East European Department UniedKmngdomDelegaion Mr. Nielson Private Secretary to the Rt. Hon. John Wakehaml MP DuchDelegaton Mr. T. van der Graaf Deputy Secretary General of Prime Minists Office Mr. J. Hoekman Ambassador of the Netherlands in the U.K. Mr. A.J. Qtwnjer Minister Plenipotentiary for Economic Affairs Netherands Embassy London -95- Page 4 of 4 EBRD Mr. M. Tomlinson Sr. Project Manager Mr. C. Bongianni EIB Mr. 0. M. Van Muiswinkel Senior Economist Mr. A. It Jorgensen Head of Technical Department International Energy Agency (IEA) Mr. R. Skdnner Director, Policy World Bank Mr. M. Z Alahdad Mr. H. J. Ansari Mr. F. Batzella Mt. A. Fernoukhi Mr. D. F. Gray Mr. . Hahm Mr. P. L Law Mr. P. Nore Mr. A. 0. Oduolowu Mr. M. Shirazi Mr. B. R. Svensson Mr. H. E. Wackman Mr. 0. Hedley - IFC BmscQ L P. gaa Ca Mr. S. C Chugh, Managing Director Consultants Arur D. Uttle (UII,) Mr. J. C Wood-Collins, Vice President Mr. N. White, Senior Consultant MaS rgis 3U.K.r Mr. J. Ball, Mr. J. Stern ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAME COMLEED ACTITIES Cewuuy AcIvhty DO Nun ber SUBSAHARAN AFRICA (AFR) Africa Regimosa Anglophone Africa Household Energy Workshop (~nglish) 07/88 08S/88 Regional Power Seminar on Redue.;g Electrc Power System Lossim Afica (Eglish) 08/88 087/88 ntitutional Evaluation of EGL (1nglish) 02/89 098/89 Biomass Mappin Reional Workshops (English - Out of Print) 05/89 - Francphone Household Enaergy Workshop (French) 08/89 103/89 Intefafrican Blectrcal Engineering College: Proposals for Short- and Log-Tem Development (English) 03/90 112/90 Biomrass e t and Mapping (English - Out of Print) 03/90 - Angola Energy As t (English and Portuguese) 05J89 4708-ANG Power Rehabilitation and Technical Assistance (English) 10/91 142/91 Benin ue rt (English and French) 06/85 5222-BEN Botswana 1 As t Oigh) 09/84 4998-BT Pump Electrification Prefeasibihity Study (English) 01/86 047/86 Review of Electriity Sevce Connection Policy (English) 07/87 071/87 Tuhi Block Farms Electrfication Study (English) 07/87 072/87 Household Enery Issues Study (English - Out of Print) 02/88 - Urban Household Energy Strategy Study (English) 05/91 132/91 Burlina Faso Eneg mt (Engis and French) 01/86 5730-BUR Technical Assistance Ptogram (English) 03/86 052/86 Urban Household Energy Strategy Study (English and French) 06/91 134/91 Burundi 0A_ nt nsh) 06/82 3778-EU Petoleum Supply Management (English) 01/84 012/84 Status Repot (English and French) 02/84 011/84 Presentation of Energy Projects for the Fourth Five-Year Plan (1983-1987) (English and French) 05/85 036/8S Improved Charcoal Cookstove Stratey (English and French) 09/85 042/85 Peat Utilization Prqect (English) 11/85 046/85 Energy A _t (Eglsh and French) 01/92 921S-BU Cape Verde Enegy At (English and Porues) 08/84 5073-CV Household Energy Strategy Study (English) 02/90 110/90 Centrl Afican Republic EeW A _ (French) 08/92 9898-CAR ComotEs ly A m h and Pch) 01/88 7104-COM Comgo Energy A mt glish) 01/88 6420-COB Power Development Plan (English and French) 03/90 106/90 C8te d'Ivoire Energy A e t (Enish and French) 04/85 5250-IVC Improved Biomass Utilization (English and French) 04/87 069/87 Power System Efficiency Study (Out of Print) 12/87 - Power Sector Efficiency Study (Frenh) 02/92 140/91 Ethiopia Energy A t (English) 07/84 4741-ET Power System Efficiency Study (Enlish) 10/85 045/85 Agricultural Residue Briquetting Pilot Project (English) 12/86 062/86 -2- CoUnn" AeCi Date Nunber Bass Study (English) 12/86 063/86 Cooking Efficiency Project (English) 12/87 - Gabon Energy Assessm t (English) 07/88 6915-GA The Gambia Enry Assessment (English) 11/83 4743-GM Solar Water Heating Retrofit Project (Bnglish) 02/85 030/85 Solar Photovoltac Applications (Englih) 03/85 032/85 Petolem Supply Eangement Assisbtce (English) 04/85 035/85 Ghana Energy Asemnt (English) 11/86 6234-OH Energy Rationalization in the Industrial Sector (English) 06/88 084/88 Sav mill Residues UtiliUstion Study (English) 11/88 074/87 Guinea Energy Assesst (OIL of Print) 11/86 6137-GUI Guinea-Bissau Energy Assessment (English and Portuguese) 08/84 5083-GUB Recommended Technical Assistance Projects (English & Portuguese) 04/85 033/85 Management Options for the Electrc Power and Water Supply Subsectors (English) 02/90 100/90 Power and Water Institutional Restructuriag (French) 04/91 118/91 Kenya Energy Assessment (English) 05/82 3800-YB Power System Efficiency Study (English) 03/84 014/84 Staus Report (English) 05/84 016/84 Coal Conversion Action Plan (English - Out of Print) 02/87 - Solar Water Heating Study (English) 02/87 066/87 Peri-Urban Woodfuel Development (Eglish) 10/87 076/87 Power Master Plan (English - Out of Pdnt) 11/87 - Lesotho Enery (English) 01/84 4676-LSO Liberia Energy As_t (English) 12/84 5279-LBR Recommended Technical Asistance Projects (EngLish) 06/85 038/85 Power System Efficiency Study (English) 12/87 081/87 Madagascar Eny As ent nglish) 01/87 5700-MAG Power System Efficiency Study (English and French) 12/87 075/87 Malawi EneW As_t (lngis) 08/82 3903-MAL Technical Assistance to Improve the Efficiency of Fuelwood Use in the Tobacco Industry (English) 11/83 009/83 Sttus Report (English) 01/84 013/84 Mali Energy At (English and French) 11/91 8423-MU Household Energy Strategy (English and French) 03/92 147/92 Islamic Republic of Mauritania Energy Assessment (English and French) 04/85 5224-MAU Household Energy Strategy Study (English and French) 07/90 123/90 Mauritius Energy As t (English) 12/81 3510-MAS Status Report (English) 10,B3 008/83 Power System Efficiency Audit (English) 05/87 070/87 Bagasse Power Potential (English) 10/87 077/87 Mozambique Energy Asse (English) 01/87 6128-MOZ Household Electricity Utilizadon Study (English) 03/90 113/90 Niger Energy Asesment (Frnch) 05/84 4642-NIR Stats Report oglish and French) 02/86 051/86 Impoved Stoves Project (English and French) 12/87 080/87 -3 country Ac4vUy Thze Number Niger H-ousebold Energy Conservadion and Substitution (English and French) 01/88 082188 Nigeria Energy Assessnt (English) 08/83 4440-UNI Rwanda Energy As t (English) 06/82 3779-RW Energy Assest (Eunglish and French) 07/91 8017-RW Status Report (English and French) 05/84 017/84 Improved Charcoal Cookstove Strategy (English and Freach) 08/86 059/86 lIproved Chan:oa Production Techniques (English and French) 02/87 065/87 Commercialization of Improved Charcoal Stoves and Carbonization Techniques Mid-Term Progress Report (English and French) 12/91 141/91 SADCC SADCC Regiona Sector: Regional Capacity-Building Program for Energy Surveys and !olicy Analysis (English) 11/91 - Sao Tome and Principe Energy Assessment (3nglish) 10/85 5803-STP Senegal Energy t (English) 07/83 4182-SE Status Report (English and French) 10/84 025/84 Industial Energy Conservation Study (English) 0/85 037/85 Prep o Assistance for Donor Meeting (English and French) 04/86 056/86 Urban Household Energy Strategy (English) 02/89 096/89 Seychllees Energy A e t (English) 01/84 4693-SEY Electric Power System Efficiency Study (English) 08/84 021/84 Sierra Lecse Energy A _t (English) 10/87 6597-SL Somalia Energ Assessnt (English) 12/85 5796-SO Sudan M ement Assistance to the Ministry of Energy and Mining 05/83 003/83 :Ergy A _omet (iglih) 07/83 4511-SU Power System Efficiency Study (Englsh) 06/84 018/84 status Report (Englsh) 11/84 026/84 Wood Energy/Forestry Feasibility (English - Out of Print) 07/87 073/87 Swaziland Energ Assessment (English) 02/87 6262-SW Tanznia Energy Asssment (English) 11/84 4969-TA Pec-Urban Woodfuels Feasibility Study (English) 08/88 086/88 Tobacco Curing Efficiency Study (English) 05/89 102/89 Remote Sensing and Mapping of Woodlands (ngish) 06/90 - Induswial Energy Efficiency Technical Assistance inglh - Out of Print) 08/90 122/90 Togo Energy Assement (English) 06/85 5221-TO Wood Recovery in the Nangbeto Lake (English and French) 04/86 055/86 Powe r Efficiency Improvement (English and French) 12/87 078/87 Uganda Energv Asse t (English) 07/83 4453-UG Stus .port (English) 08/84 020/84 IUstitV'Aonal Review of the Energ Sector (Einglih) 01/85 029/85 Ener Efficiency in Tobacco Curing Industry (English) 02/86 049/86 Fuelwood/Forestry Feasibility Study (English) 03/86 053/86 Power System Efficiency Study (English) 1288 092/88 Energy Efficiency Improvement in the Brick and Tile Induskty (Enlish) 02/89 097/89 Tobacco Curing Pilot Project (English - Out of Print) 03/89 UNDP Terminal Report -4- Couwsy AedW$y DW* Nwmber Zaire 13nergy A _ssmt (English) 05/86 5837-ZR Zambia Enery A nt (English)' 01/83 4110-ZA Stas Report (English) 08/85 039/85 Energy Setor Institutional Review (nglish) 11/86 060/86 Zaibia Power Subswtor Efficiency Study (English) 02/89 093/88 Enegy Strategy Study (English) 02/89 094/88 Urban Household Energy Stategy Study (English) 08/90 121(90 Zinibabwe BnerV AIlst (Etiglish) 06/82 376S-ZIM Power System Efficiency Study (English) 06/83 OOS/83 Status Report (English) 08/84 019/84 Power Sector Mmgement Asisace Project (English) 04/85 034/8S Petroleum Manment Asistance (English) 12/89 109/89 Power Sector Management Institution Building (English - Out of Prit) 09/89 - Chacoal Utlizaion Prefeasibility Study (English) 06/90 119/90 integrated Energy Sty Evaluation (E1nglish) 01/92 8768-ZIM EAST ASIA AND PACIFIC (EAF) Adia Regional Pacific Household and Rural Energy Seminar (English) 11/90 - China County-Level Rural Enegeynts (English) 05/89 101/89 Puelwood Forestry Peinvtment Study (English) 12/89 105/89 Fiji lBnay A _mmnt anglish) 06/83 4462-FlY Indonesa Bu A m (Englih) 11/81 3543-IND Status Report tEngish) 09/84 022/84 Power Generation Efficiency Study (English) 02186 050/86 Eergy Efficiency in the Brek, Tile and Lime Idustri (Elngh) 04/87 067/87 Diesel Geneaing Plant Efficiency Study (English) 12/88 095/88 Urban Household Energy Strategy Study (nglish) 02/90 107/90 Biomass Gasifier Proinvestment Study Vols. I & l (Engish) 12/90 124/90 Malaysia Sabah Power System Efficiency Study (English) 03/87 068/87 Oas Utilization Study (English) 09/91 9645-MA Myaamar EnerVy As_met (English)) 06/85 5416-BA Pau New Guinea EneiV A_mment(l3nglish) 06/82 3882-PNG StatLu Report (English) 07/83 006/83 Energy Sategy Paper (lsh - Out of Prit) - - lwstitutiond Review in the Energy Sector (English) 10/84 023184 Power Taiff Study (English) 10/84 024/84 Solomon Island Energy Aet nglish) 06/83 4404-SOL BeqV A _mmmt OhWlish) 01192 979/SOL South Pacific Petboleum Transport in tho South Pacific (Englsh-ut of Print) 05/86 - Thaiand Energy Assessment (English) , 09/85 5793-7H Rumal Energy lse and Options (Eglish - Out of Pnnt) 09/85 044/85 Acceleaed Dissemination of Improved Stoves and Charcoal Kils gish - Out of Print) 09/87 079/87 -5- Coney AcdII Date Number Thaand Northeast Regioa Village Forestay and Wcodfuels Preinvestment Study (Englis) 02/88 083/88 Impact of Lower Oil Prices (English) 08/88 - Coal Development and Utilization Study (English) 10/89 - Tonga EnergyA t (me ngliSh) 06185 5498-TON Vanuatu Energy As (English) 06/85 S577-VA Western Samoa Ener Ayt (English) 06/85 5497-WSO SOUT ASIA (SAS) Bangldesh Energy A t (English) 10/82 3873-BD Priority Investment Ptogram 05/83 0183 Status Report (English) 04/84 015/84 Power System Efficiency Study (English) 02/85 031/85 Small Scale Uses of Gas Prefeasibility Study (English - (Out of Pdnt) 12/88 - bIdia Opportunities for Commercialization of Nonconventional Eney Systems (English) 11/88 091/88 Maarashtra Bagasse Energy Efficiency Project (English) 05/91 120/91 Mini-Hydro Development on Irrigaion Dams and Cmal Drops Vols. 1, I and m (English) 07/91 139/91 Nepal Energ y (English) 08/83 4474-NEP Sts Report (glish) 01/85 028/84 Pakistan Household E=nergy A _t (English - Out of Print) 05/88 - Amess,ent of Photovoltaic Progafas, Applicaions, and Markds (English) 10/89 103/89 Sri T } yEner Asgy (En ) 05/82 3792-CE Power System Loss Reduction Study (English) 07/83 007/83 Status Report (English) 01/84 010/84 dustri Energy Conservation Study (English) 03/86 054/86 EUROPE AND CENTRAL ASIA (ECA) Eastern Europe Ibe Futre of Natual Gas in Easten Europe (English) 08/92 149/92 Poruga Energy Aent (glEiSh) 04/84 4824-PO Turkey Energy Assessment (English) 03/8w 3877-TU MDDLE EAST AND NORTH AFRICA (MNA) Morocco Energy Asse t (English ad French) 03/84 4157-MOR Stus Report (English and French) 01/86 048/86 Syria Energy Am (EnSH) 05/86 5822-SYR Electric Power Efficiency Study (Engih) 09/88 089/88 Energy Efficiency Improvement in the Cment Sector (English) 04/89 099/89 Energy Efficieny Improvement in th Febrilizer Sector(English) 06/90 115/90 -6- County Av Date Nwnber Tunisia Fuel Substitution (English and French) 03/90 - Power Efficiency Study (English and French) 02/92 136/91 Energy Management Strategy in the Residential and Tetiay Sectors (Englih) 04192 146192 Yemen Energy At (English) 12/84 4892-YAR Energy Investment Priorities (English - Out of Print) 02/87 6376-YAR Household Energy Strategy Study Phase I (English) 03/91 126/91 LATIN AMERICA AND THE CARIBBEAN (LAC) LAC Regional Regional Seminar on Electric Power System Loss Reduction in the Caribbean (English) 07/89 - Bolivia Energy A _t (English) 04/83 4213-BO Nationd Energy Plan (English) 12/87 - National Enery Plan (Spnish) 08/91 131/91 La Paz Private Power Technical Asstance (English) 11/90 111/90 Natural Gas Distribution: Economics and Regulation (English) 03/92 125/92 Prefeasibility Evaluation Rural Electrification and Demand Assessment (Bglish and Spanish) 04/91 129/91 Private Power Genation and Transmission (ns) 01/92 137/91 Chile Energy Sector Review (English - Out of Print) 08/88 7129-CH Colombia Energy Strateg Paper (English) 12/86 - Costa Rica Enr t (English and Spatlsh) 01/84 4655-C Recommenlded Technical Assidtance Projects (English) 11/84 027/84 Forest Residues Utliaion Study (English and Spanish) 02/90 108/90 Dominican Republic Energy A _t (English) 05/91 8234-DO Suador EneW AmsA_t (Spanish) 12/85 5865-EC Energy Stra Phase I (Spanish) 07/88 - Energv Strategy (English) 04/91 - Haiti Energy A t (English and French) 06/82 3672-HA Status Report (inglish and French) 08/85 041/85 Household Energy Strategy (English and French) 12/91 143/91 Honduras Energy A _ (3ngish) 08/87 6476-HO Petroleum Supply Management (English) 03/91 128/91 Janmaica erg A s (English) 04/85 5466-JM Petroleum Procmnent, Refining, and Distribution Study (English) 11/86 061/86 Enrg Efficiency Building Code Phase I (English-Out of Print) 03/88 - Energy Efficiency Standards and Labels Phase I (English - Out of Print) 03/88 - Management Information System Phas I (Engish - Out of PRint) 03/88 - Charcoal Production Project (lish) 09/88 090/88 PIDCO Sawmill Residues Utilization Study (English) 09/88 088/88 Energy Sector Stratogy and Invetment Planning Study (English) 07/92 135/92 -7 Couni Acty De* Nlt ubr Mexico Improved Charcoal Producion Within Forest Management for the State of Veracuz (English and Spanish) 08/91 138/91 Panam Power System Efficiency Study (English - Out of Print) 06/83 004/83 Parguay Enersy (Englishi) 10/84 5145-PA Rcommended Techncal Assistance Projects (English- (Out of Print) 09/85 - Stats Report (English and Spansh) 09/85 043/85 Peru 13iV Asst (English) 01/84 4677-PB Status Report (English - Out of Print) 08/85 040/85 Proposal for a Stove Dissemination Program in the Sierra (English and Spanish) 02/87 064/87 Energy Strategy (Spaish) 12/90 - Saint Lucia Eneg Asessment (Eqh) 09/84 5111-SLU St. Vincent and the Ondines Energy Assmt (English) 09/84 5103-STV Trinidad and Tobago Energy A _t (Enlish - Out of Print) 12/85 5930-TR GLOBAL Enry End Use Efficiency: Research and Strategy (English - Out of Print) 11/89 - Guidelines for Utility Customer Management and Metering (English and Spanish) 07/91 - Women and Energy-A Resource Guide Th iterational Networc: Policies and Experience (English) 04/90 - Amesset of Personal Computer Models for Energy Planning in Developing Countries (English) 10/91 - 080692