Energy Information Administration
FedStats
Overhauling the Industry
Gazprom, the World´s Gas Company Giant
Foreign Investment
Caspian Region
The Pipeline Debate
Azerbaijan
Kazakhstan
Eastern Europe
Economies in Transition
Albania
Bulgaria
Czech
Republic
Slovakia
Hungary
Poland
Romania
China and Vietnam
China
Vietnam
The fall of the Soviet Empire ushered in an era of mass political, legal, and economic reforms. In Russia, the move to a market economy has involved the privatization of much of Russia's industry. Russia's large petroleum sector is currently going through the privatization process, though initially on a more limited scope and at a slower pace than other industries. A November 1992 presidential decree established vertically integrated oil companies from former oil-producing associations of the Former Soviet Union (FSU). The gas sector, however, was to remain intact under the gas monopoly Gazprom.
Like the breakup of Standard Oil in the United States during the beginning of this century, the FSU's oil production monopoly was separated along geographic lines, combining regional oil production associations with refineries and product distributors, and transforming them into integrated joint (public and private) stock companies (see Box entitled "Russia's New Petroleum Industry"). The final restructuring and consolidation of the industry's assets occurred in 1995 under a subsequent presidential decree that gave rise to the current structure of eleven vertically integrated oil companies {see Endnote 94}. Their estimated size in reserves and production allows them to compete with the world's major petroleum companies; eight of the eleven integrated Russian oil companies are ranked in Petroleum Intelligence Weekly as among the "World's Top 50 Oil and Gas Companies for 1994 " {see Endnote 95}.
The partial privatization of the Russian oil industry has consisted of two stages {see Endnote 96}. The first stage, which ended in June 1994, was the commercialization of state enterprises into joint stock companies and the selling of shares through vouchers, with ownership limited to workers and Russian citizens. Thirty-eight to forty-five percent of the shares in the companies are required to remain in government hands for at least three years, after which the government share may be reduced. The privatization process is currently in the second phase, which opens ownership to foreign investors. During this stage, remaining shares will be distributed in one of two ways: 1) the disbursement of blocks of shares to investors in exchange for their commitment to maintain employment levels and to make future contributions to the enterprise and 2) the sale of shares for cash.
In 1995, under the shares-for-cash proposal, the Russian government implemented a shares-for-loans scheme, whereby large blocks of government shares in certain joint stock companies (which included five of Russia's oil giants) were auctioned to a group of Russian commercial banks for cash. The successful bidders are required to hold the shares in trust for a maximum of three years in return for providing loans to the government to reduce its budget deficit. At any time, the government can buy back its shares. However, because the affected shares are to be temporarily managed by the bidder awarded the shares, a controversy has arisen over the possibility of corruption entering the bidding process. Consequently, all future auctions have been terminated and the results of last year's auction are being challenged. These challenges have arisen from many parties, including government factions, the public, commercial banks, and both managers and owners of the former joint stock companies. Some of these challenges are currently in court.
Most of Russia's new oil companies are operating as regional monopolies. Others, like Lukoil and Rosneft, are using their size and influence to expand beyond their borders to other countries, and compete with the world majors. For example, in 1994, Rosneft and two of its subsidiaries at the time purchased a 24-percent interest in the planned Leuna refinery in eastern Germany {see Endnote 97}. Lukoil also has stakes in several production-sharing agreements and joint ventures in former Soviet Republics and is pursuing interests in Europe.
Foreign capital and technology are needed in the oil sector to help stop the decline in production, which peaked at 12.5 million barrels per day in 1987 and fell to 6.2 million barrels per day by 1995 {see Endnote 98}. The decline in production, which only recently has begun to level off, is attributed mainly to management and production inefficiencies, outdated and inadequate infrastructure, lack of investment, declines in domestic demand, low domestic prices, an inability to export, and uncertainty surrounding pro perty right issues.
Downstream, the rebuilding of Russia's petroleum infrastructure is also being delayed by the slow pace of foreign investment. Most of Russia's 29 refineries are old, inefficient, and in need of modernization. The total operational capacity of Russia's refineries is 6.6 million barrels per day with a utilization rate of under 60 percent {see Endnote 99}. Russia's Ministry of Fuel and Energy has begun to restructure the refinery sector, with plans to build several refineries in Russia and to upgrade existing refineries. The ministry hopes to increase throughput by 17 percent to 4.2 million barrels per day, in the year 2000 {see Endnote 100}. Costs of modernizing and expanding the industry during the 1995-2000 period are estimated at $7 billion {see Endnote 101}.
One company, Gazprom, dominates the Russian natural gas industry and is the world's largest gas company, with reserves of 848 trillion cubic feet. In 1994, Gazprom produced 20,160 billion cubic feet {see Endnote 102}. Consisting of 10 production associations, Gazprom produces over 90 percent of Russian gas and owns over 70 percent of the country's gas reserves {see Endnote 103}. In 1993, Gazprom was converted into a state-owned joint stock company, and then began to be privatized in April 1994. As in the oil industry, shares were divided among Gazprom employees and other domestic investors, while 40 percent of its shares is to remain in government hands for at least three years. Nine percent of Gazprom's stock has been set aside for foreign ownership. The sale of shares (even between private individuals) requires Gazprom's approval.
In contrast to the oil sector, Gazprom has been relatively successful at maintaining output, which is mainly in western Siberia, where over 90 percent of Russia's natural gas is produced {see Endnote 104}. However, much investment capital is needed for field development and for rehabilitation of Gazprom's extensive network of pipelines, almost 90,000 miles. Currently, nonpayment from Gazprom's major customers, Russia's electric utilities, and the republics of the FSU has developed into a crisis. Revenues that would have been used for projects have been diverted to subsidize the electric utilities, since cutting off supplies to the utility companies is forbidden by law. Of the FSU republics, the Ukraine owes the largest sum of money. However, the Ukraine has some unique leverage since Russian gas accounts for about 60 percent of Europe's gas imports, of which over 90 percent runs through the Ukraine. Exports to Europe are one of Gazprom's most secure sources of cash. Attempts to reduce gas deliveries to the Ukraine for nonpayment have failed because the Ukraine began to siphon gas destined for Europe to offset the shortfall {see Endnote 105}.
Currently, since transport costs are not taken into account in establishing price, gas prices remain uniform across Russia, creating further inefficiencies in the gas industry. Some critics have recently called for regulating the industry. Some would even like to see Gazprom dismantled, but no serious efforts have been made so far to break up their monopoly.
Even prior to privatization, Gazprom has had relationships with foreign companies, both in and outside the FSU. Currently, Gazprom is working on various projects with European and Asian countries that could eventually lead to the establishment of an intricately connected gas network system throughout these regions. Further, Gazprom holds an interest in a German natural gas transmission operation with its German joint venture partner, Wintershall.
The breakup of the Soviet Union and the move toward a market-driven economy are seen by many foreign investors as offering new exploration and production opportunities to one of the world's largest petroleum producing areas outside Saudi Arabia {see Endnote 106}. Russia first began to open the door to foreign investment in its petroleum industry through joint ventures. Foreign participation was not allowed in the initial stage of the privatization of assets. The second phase, however, did open up opportunities for foreign investors to take equity stakes in Russia's petroleum industry. ARCO became the first foreign company to buy an equity stake of up to 6 percent in the Russian oil firm Lukoil, paying $250 million for convertible bonds.
Joint ventures in upstream activities remain the main vehicle for foreign investment. Joint ventures are a way for Russia to gain access to capital and efficient, cost-saving technology and for foreign companies to gain a foothold in Russia. Oil and gas production from joint ventures has been increasing rapidly over the last few years, contrary to the trend for total Russian output. However, the joint ventures currently operating in Russia's oil and gas sector contribute only a fraction to overall production. Joint venture production increased by 39 percent in 1995 to 420,000 barrels per day, comprising 7 percent of total Russian output {see Endnote 107}.
Foreign joint exploration and development projects in Russia are mostly within known fields located in three of Russia's five largest producing regions. The regions include western Siberia, the Arctic Region, and the Russian Far East. In western Siberia, Occidental is operating the Vanyoganneft joint venture, one of its two enhanced oil recovery projects (the other is located in the Komi Republic). Amoco has a 50- percent interest in the Priobskoye field. In the Arctic Region, the largest production-sharing agreement being negotiated is the Timan Pechora Company (TPC), led by Texaco (with a 30-percent ownership share) and including Exxon (30 percent), Amoco (20 percent), and Norsk Hydro (20 percent) {see Endnote 108}. The joint venture includes the exploration and development of 1.8 million acres located in the Timan Pechora Basin (with 11 huge oil fields) north of the Arctic circle. Also located in the Timan Pechora Basin is Conoco's joint venture, Polar Lights, the first oilfield developed and brought on stream by a western company. In the Russian Far East, Sakhalin Island is the site where three agreements have been negotiated so far. Sakhalin I is being developed with the Exxon-Sodeco consortium, Sakhalin II is being developed with the MMMMS consortium (Marathon-USX, McDermott, Mitsui, Mitsubishi, and Royal Dutch/Shell), and Sakhalin III has been divided and will be developed by two different groups two blocks are being developed by Exxon and one block is being developed by Mobil and Texaco.
Twelve production sharing agreements have reached an advanced state of negotiation, and await finalization. However, uncertainty surrounding jurisdiction over resources, licensing, and taxation, have made many oil companies withhold an estimated $60 billion of investment until legislation that provides adequate investment guarantees can be passed. For example, Amoco, the Timan Pechora Company, and the companies operating in all three of the Sakhalin agreements have chosen not to begin their projects until the passage of appropriate legislation. The long-awaited Oil and Gas Law--which was signed into law in January 1996--was supposed to provide that framework. However, modifications that were made to get the law passed did not fully provide the guarantees desired by foreign investors. Some provisions that foreign companies find objectionable are: 1) the requirement to have parliamentary approval for fields in areas defined as "strategic" and for production sharing agreements not awarded by tender, 2) the Russian government's right to modify conditions of a production sharing agreement if "major economic changes" occur during the term of the agreement, 3) a provision that subsequent individual laws will determine which fields can be developed under production sharing agreements, and 4) the lack of recourse available to foreign investors to resolve disputes in an international tribunal {see Endnote 109}. Thus, the Oil and Gas Law (as passed) is considered a major setback by many of the companies and has forestalled their major investment plans {see Endnote 110}. Other barriers to foreign investment include a high tax burden in Russia. The absence of reliable transportation and access to foreign markets are other hurdles faced by both Russian and foreign companies. Access had been curtailed severely due to uncertainty surrounding changing export restrictions, which include quotas, requirements to export through holders of official special exporter licenses, and high export taxes. Investors faced a further barrier when the Russian government instructed joint ventures to supply the bulk of their oil to former Soviet Republics, where payment problems have arisen.
Once market conditions improve in Russia, substantial infrastructure investments will be needed before the decline in production can be reversed {see Endnote 111}. Physical constraints on the infrastructure, particularly the inefficient and outdated pipelines run by the state pipeline monopoly Transneft, plague both foreign and domestic companies. Furthermore, Russia's vast pipeline system has seen a change in flow patterns, resulting in supply disruptions. New pipelines are needed and existing pipelines must be repaired and upgraded. Plans to expand the system are being given top priority, but not much can be done until investments increase.
At present, ambitious plans to develop Russia's petroleum resources have faltered largely due to uncertainties surrounding oil and gas laws, changing tax regimes, and the ability (both physically and legally) to export crude oil to international markets. If economic reforms continue and political stability improves, Russia could rival the Mideast as a source of crude oil exports. To entice foreign investment capital, Russia must offer investors the opportunity to earn acceptable returns on their investments. To do so, Russia must implement laws that protect property rights, provide access to foreign markets, liberalize prices, and offer fair taxation. Further, Russia must reduce the twin destructive influences that widespread corruption and organized crime have come to have over legitimate commerce.
The Caspian Sea shelf is considered one of the largest sources of petroleum outside the Persian Gulf and Russia.
The region's largest producers are Azerbaijan and Kazakhstan. The key to foreign investment in these two Caspian nations is obtaining secure export routes. Lack of a secure means of transporting Caspian Sea oil and gas to world markets has been an impediment to foreign investment. Until foreign investors can rely on access to markets, investment in the Caspian region's huge petroleum potential will remain small.
The lack of pipeline access is limiting production in the region. Russia is demanding participation in the region and derives its influence through its control of the only existing pipelines in the region. Also, disputes with Russia over the legal status of the Caspian Sea are being negotiated but they could still disrupt matters. Russia is seeking to push through new regulations stipulating that no offshore resource developments should be undertaken without the compliance of all surrounding states. Russian oil and gas companies, like Lukoil and Gazprom, have succeeded in acquiring stakes in large Caspian projects. Some foreign investors believe it is necessary to bring Russian participants into their projects to guarantee access to markets. In the meantime, various alternative routes have been proposed; however, until they become a reality, Russia will maintain its dominance in the area.
Many western companies would like to see multiple routes due to political instability in the area, to provide alternative access to markets for international companies involved and to diversify European energy supplies. However, the political climate for those interested in the Caspian region has delayed the development of proposed pipeline routes. The two most promising routes include pipelines that will link Caspian production fields with the Black Sea and, thereby, the Mediterranean Sea and European markets. The first proposed pipeline project is the Caspian Pipeline Consortium's (CPC) $1.2-billion project to refurbish and connect existing Russian pipelines to the Black Sea port of Novorossisk via Chechnya. However, the proposed project was additionally delayed when Chevron and others did not support CPC's proposals on financing and limited ownership of the 900-mile Caspian Sea oil pipeline. As a result, the original three-member CPC consortium (consisting of Russia, Kazakhstan, and Oman) negotiated and recently signed a new accord for a joint protocol to restructure the CPC, inviting Chevron and seven other international energy companies to join them, with an offer of 50-percent combined ownership. The consortium has awarded the following shares: Chevron (15 percent), Lukoil (12.5 percent), Rosneft (7.5 percent), Mobil (7.5 percent), British Gas (2 percent), Agip (2 percent), Oryx (1.75 percent), and Kazakhstan's Munaigaz (1.75 percent) {see Endnote 112}. The foreign companies will be responsible for financing the pipeline.
The second pipeline project arose from an agreement between Russia and the 12-member Azerbaijani International Oil Consortium (AIOC) {see Endnote 113}. The agreement between Russia and this largely western consortium gives these companies permission to use Russian pipelines to export oil due to be produced by the end of 1996 through two alternative export pipeline routes from Baku. One route is north through the CPC pipeline, which crosses Russia, and the other route is west through a pipeline to be built across Georgia. Both alternatives end at the Black Sea. The agreement is waiting final approval from the Russian parliament.
Turkey is undertaking its own plans to build a pipeline. The planned project is a $1.8-billion project to build a 1,047-mile oil pipeline linking the Caspian fields through Georgia to the port of Ceyhan in the eastern Mediterranean {see Endnote 114}. These plans however, have given rise to concerns over the environmental damage increased oil traffic through the Dardanelles would cause. One other option involves connecting pipelines in the FSU Caspian region to pipeline networks in Iran, although this latter option has met with strong opposition from the United States and Israel.
Political instability associated with repeated changes of government has limited reform in Azerbaijan, the oldest, and once major, oil-producing region of the FSU. However, Azerbaijan is now opening its large reserves, estimated at 10 billion barrels {see Endnote 115}, to foreign investment through joint ventures with the State Oil Company of Azerbaijan (SOCAR). Foreign investment is needed to restructure and modernize the outdated and inefficient infrastructure inherited from the FSU. The Caspian pipeline and territory disputes extend into Azerbaijan, which is also in need of an outlet to export markets.
The two largest international joint venture projects include the Shakh Deniz prospect, with reserve estimates of 4-5 billion barrels, and the 1-billion barrel Karabakh prospect {see Endnote 116}. The Shakh Deniz prospect is an $8-billion project between SOCAR and the AIOC. The 30-year project is to explore the three large offshore Caspian fields of Azeri, Chirag, and Gyuneshli. Initial oil production is expected sometime in late 1996, with peak production estimated at 700,000 barrels of oil per day by 2010. In addition, France's Elf Aquitaine has recently signed a production-sharing agreement with SOCAR for a separate onshore/offshore block in the Shakh Deniz area.
The second largest Azerbaijan joint venture project is being explored by the Caspian International Petroleum Company, consisting of Pennzoil, Agip, Lukoil, and SOCAR {see Endnote 117}. The $1.7-billion project includes the exploration, development, and production of the Karabakh prospect in the Azerbaijan sector of the Caspian Sea.
In addition, Exxon and SOCAR signed an agreement in June 1996 for two Caspian sea exploration blocks, while Occidental, Chevron, Mobil, and Unocal are actively seeking opportunities in offshore Azerbaijan.
Downstream provides another potential target for foreign investment. The state-owned monopoly, SOCAR, has 2 refineries with a refining capacity of 441,808 barrels per day {see Endnote 118}. Foreign investment will be necessary to help finance the modernization proposal to upgrade the refineries, but current investment plans have been delayed due to the previously-cited pipeline dispute and debt owed by the refineries for past deliveries.
After Kazakhstan became independent from Russia in 1991, the country hoped for rapid development of its Kazakhstan's recoverable reserves of crude and condensates, which are 21.9 billion barrels and 81.2 trillion cubic feet of gas and are mainly located in the Caspian Sea {see Endnote 119}. Probable reserves amount to 51.3 billion barrels of oil and 264.9 trillion cubic feet of gas {see Endnote 120}. However, Kazakhstan has no direct access to world markets. Further, Kazakhstan suffers from an under-developed and inefficient petroleum pipeline infrastructure. As a consequence, production of one of the world's largest petroleum areas has remained largely unexploited. State-owned companies in Kazakhstan currently account for most of the 1995 average production of 420,000 barrels per day, which could more than double by the year 2000 if there were guaranteed access to markets {see Endnote 121}.
Restructuring the oil industry included setting up the state holding company Munaigaz to coordinate all oil industry activities {see Endnote 122}. Prior to an international tender last month, there were seven producers and three refineries under Munaigaz control. There has been a proposal to end Munaigaz' monopoly, following the Russian example, by creating vertically-integrated oil companies. In what is being called a test case for privatization, Kazakhstan held an international auction for shares in two of its producers, Aktyubinskneft and Yuzhneftegas. These companies have combined proven reserves of more than 2 billion barrels, and also own the 150,000-barrels-per-day Chimkent refinery. Samson Investment Company, a U.S. firm, won a 100-percent stake in the Kazak producer Yuzhneftegas. Samson submitted a joint bid with the local investment firm Munainvest, fending off a single challenge from Canada's Hurricane Hydrocarbons. The Swiss Trading Company, Vitol, won the tender for a 90-percent stake in Kazak's Chimkent oil refinery, but the terms have not been settled {see Endnote 123}. Kazak companies' large debts, non-productive assets, and lack of transparency made investors cautious. Companies also were concerned about the many preconditions associated with the awarding of shares, particularly the required pledges for investment, social guarantees, payment of old debts, and environmental liability {see Endnote 124}.
Thus far, in Kazakhstan, privatization has mainly been limited to joint ventures, with many of the republic's most attractive fields being acquired by international companies. In 1993, Chevron began a long-term investment in Kazakhstan at one of the largest fields in the world, the Tengiz oil field with 6 billion barrels of proven reserves. The 40-year joint venture between Chevron (50 percent) and the government-owned producer Tengizmunaigaz could produce 700,000 barrels of crude per day and bring in $20 billion in investment. However, lack of a reliable export route has led production to be cut to 60,000 barrels per day, even though current capacity is 120,000 barrels per day. The high hydrogen sulfide content of the field has also posed potential transportation and marketing problems. Chevron, which has spent over $1 billion already, has delayed expansion plans until the pipeline issue is resolved.To help finance its share of the project, Kazakhstan sold half of its 50-percent stake to Mobil in early 1996 for $1.1 billion {see Endnote 125}. In 1993, seven foreign companies, including the British Petroleum/Statoil partnership, Royal Dutch/Shell, British Gas, Total, Agip, and Mobil, signed a contract for seismic testing in Kazakhstan's area of the Caspian Sea region, in exchange for the right to select two blocks for further exploration and development and the right to bid on the remaining blocks {see Endnote 126}. In addition, Mobil (50 percent) and three Kazak partners are exploring the western Atyrau and northwest Aktyubinsk regions in the $80-million, 25-year, Tulpar-Munai venture. In 1994, Oryx Energy signed two agreements to explore Kazakhstan's eastern Caspian Sea area. One involves the exploration of a large block in western Kazakhstan, in which Exxon later bought a 50-percent stake. The other is a 50-50 joint venture with two Kazak partners to develop the Arman field in the north Buzachi Peninsula.
Despite large gas reserves, development of natural gas resources also has been limited due to inadequate infrastructure. The country currently is a net importer of natural gas. The only existing export route for natural gas is a Gazprom pipeline that runs through Russia. This has led British Gas and Agip, who have exclusive rights to negotiate for reserves of the Karachaganak field, estimated to hold 16 trillion cubic feet of gas and 2.4 billion barrels of condensate, to bring in Gazprom as a partner with a 15-percent stake. However, a production-sharing agreement has not been finalized and Gazprom has yet to put up its share of the equity.
The pipeline issue also is holding up downstream projects. Kazakhstan has three refineries, with a refining capacity of 393,611 barrels per day {see Endnote 127}, that are in need of Russian crude deliveries, lower demand, and limited access to international export markets have reduced refining throughput and delayed modernization plans to expand capacity.
Eastern European countries are also undergoing major political and economic structural reforms. Previously under strong central government control, they have begun to decentralize their economies, transforming them through various programs consisting of industry restructuring and privatization. Former state-owned firms are being internally restructured, shifting from public ownership with state control to various types of private ownership. To address the need of potential investors for clearly defined property rights, each country has attempted to develop viable legal structures, contract laws, regulatory systems, capital markets, trade policies, and domestic bond and stock markets. However, while investment has not been as forthcoming as anticipate--due to the low pace of reform--any countries are proceeding with various degrees of privatization, such as joint ventures. Foreign investment is higher in the countries where reform has made the most progress, namely the Czech Republic, Hungary, and Poland. The diversity of reform among the countries in eastern Europe--which includes voucher sales, direct sales, and National Investment Funds--is related to how each country addresses the issue of sovereignty over strategic national assets.
As in the FSU, the Communist regimes left eastern European countries with bloated and inefficient hydrocarbon industries that suffered from decades of neglect, outdated technology, heavy debt, and environmental problems. Unlike Russia's large reserves, eastern Europe produces little oil and natural gas--only Romania has a sizeable endowment of reserves. The eastern European countries are dependent on imports, mainly from Russia, to meet primary energy demand.
The condition of eastern European refining is similar to that of upstream petroleum. All eastern European countries have refinery industries (Table 2). Most are badly in need of restructuring and upgrading. The petroleum marketing sector is the fastest growing sector in eastern Europe's energy industry, partly due to the introduction of foreign competition in many countries. Thus far, most energy enterprises are still publicly-owned and government-run. However, to meet the petroleum needs of those economies where privatization efforts are strongest, private ownership is beginning to emerge. For example, Hungary has sold an 18.8-percent stake in its vertically integrated petroleum company, MOL {see Endnote 128}. The Czech Republic merged its two largest refineries and sold 49 percent to IOC, a western consortium.
Eastern Europe under central planning was virtually closed to foreign investors. Foreign capital could play a pivotal role in helping diversify energy supplies, increase energy efficiency through modernization, and improve the environment. Although foreign direct investment has increased in these areas, inflows remain modest. Foreign direct investment has been slow to materialize due to continuing macroeconomic instability and insufficient institutional reforms. To date, most foreign investment has been through joint ventures.
Each country has a unique socioeconomic context, causing variation in the transition process across all countries in the region. Different ownership structures are emerging under different privatization schemes. Reform has continued, even in the face of economic decline and decreasing production since the fall of communism and the beginning of efforts to move to market economies. Only now are these countries beginning to recover economically, spurred by exports and increasing domestic demand.
After decades of neglect, Albania began to reform its oil and gas industry by establishing a state-owned oil and gas company and allowing joint ventures with foreign companies, mainly in the form of production-sharing agreements. The national oil and gas company, Albpetrol, was established in 1992. It currently controls 46 energy and petroleum-related enterprises {see Endnote 129}.
Foreign oil companies were initially restricted to offshore drilling {see Endnote 130}. Since legislation opened up onshore concessions to foreign investors in 1993, there have been two international onshore licensing rounds. In the first round, foreign companies were invited to bid for three oil-recovery enhancement projects {see Endnote 131}. Included in the second international onshore licensing round was the concession for two onshore blocks not awarded in the first licensing round and one offshore block in the Adriatic Sea, which previously had been relinquished by Agip of Italy {see Endnote 132}. Over the past four years, $100 million has been invested by foreign oil companies, with a further investment of $60 million expected during 1996 {see Endnote 133}.
Bulgaria's economy, which was one of the Eastern European economies most closely patterned after the Soviet system, is one of the most energy-intensive in the world. Although Bulgaria generates 40 percent of its electricity from nuclear energy, the country is also heavily dependent on coal {see Endnote 134}. The country's dependence on coal has created severe environmental problems.
Due to constant shifts in government, economic reform in Bulgaria has been among the slowest in eastern Europe {see Endnote 135}. Heavy subsidies and government-controlled prices still exist in the energy sector. Privatization of the energy sector was excluded from the 1995 privatization program, although the country's two largest refineries, Neftochim and Plana,were placed in a separate category reserved for enterprises that require special government approval prior to privatization. Even so, Bulgaria was the first eastern European country to offer petroleum exploration concessions to western countries {see Endnote 136}. Three international auctions - in 1991, 1993, and 1995 - have bseen held so far. Eight companies received oil exploration licenses in the first, while no licenses were awarded in the second. Final results of the third have yet to be announced. Production results have been mixed. In addition, foreign filling stations have been allowed to compete with the dominant state-owned oil and petroleum products distributor, Bulgargas.
Bulgaria is trying to use its unique position (connecting supply from the countries of the Commonwealth of Independent States and from the Middle East with western European markets) to reestablish links with Russia's newly integrated oil companies. However, the pipelines establishing these links have had oil transit disrupted by the United Nations' embargo against Iraq and the outbreak of war in the former Yugoslavia. In May 1995, Gazprom and Bulgargas set up a joint-venture company to control the flow of Russian gas through Bulgaria, build gas supply systems, invest in Bulgaria's 2,000-kilometer gas network (linked to Russia via two pipelines running through Ukraine and Romania), and market Russian gas to other countries {see Endnote 137}.
Separated from Slovakia on January 1, 1993, the Czech Republic has been an aggressive economic reformer with foundations of a market economy firmly in place. On November 28, 1995, the Czech Republic became the first post-Communist state in eastern Europe to sign an agreement to join the Organization for Economic Cooperation and Development (OECD), becoming the group's 26th member {see Endnote 138}.
Like Bulgaria, the country produces little energy, except for coal. The country is a net importer of all energy supplies and is largely dependent on Russia for its energy imports. Even though the Czech Republic is considered a lead reformer in eastern Europe, the country has yet to finalize plans on how it will restructure its oil and gas industry.
Even though the Czech Republic is considered a lead reformer in eastern Europe, the country has yet to finalize plans on how it will restructure its oil and gas industry. Currently, the gas distributor Transgas remains under full state control. Initially, with only one pipeline--the Friendship line from Russia--and with refining badly in need of upgrading, the Czech Republic has sought foreign investment to help it fully integrate with Europe and to reduce its dependency on Russian oil. In March 1996, the Czech Republic will acquire alternative sources of oil with the opening of its second crude pipeline. The pipeline to Germany was built under an agreement between the two countries. Downstream, the Czech government consolidated operations prior to privatization. The two largest Czech refineries, Chemopetrol and Kaucuk, were merged to form Czech Refineries, with the state's 51-percent interest being retained by Unipetrol--a newly established holding company, which currently owns the remaining petrochemicals industry, and Benzina, the partially privatized petroleum distributor {see Endnote 139}. In November 1995, the largest refinery privatization in eastern Europe and the Former Soviet Union took place when the Czech government signed a $672-million agreement to sell the remaining 49-percent state-owned share in Czech Refineries to IOC, a consortium including Royal Dutch/Shell, Agip, and Conoco.
Slovakia is largely dependent upon imported oil and gas. Slovnaft, the country's third largest petroleum company, is the industry's refiner and petrochemical company. By the time of Slovakia's separation with the Czech Republic, Slovnaft was already 20-percent privatized {see Endnote 140}. In 1995, to increase its attractiveness as an investment prospect, Slovnaft bought a 51-percent stake in Benzinol, which controls 60 percent of the retail gasoline market and is a major Slovnaft customer. The government is negotiating with Agip of Italy to buy an additional 34-percent stake in Benzinol. The company recently offered additional equity through a global-depository-receipt offering to raise money for a modernization program {see Endnote 141}.
There is uncertainty regarding the pace of structural reforms. Privatization virtually came to a halt in late 1994, and decisions to dispose of state property have been reversed on several occasions. In July 1995, the "Golden Egg Law" was passed. It listed dozens of firms that will not be privatized or in which the state will keep a right of veto over key decisions {see Endnote 142}. Utilities will remain under permanent state control, and the state will keep decisive influence on the oil refiner Slovnaft and the energy company Nafta Gbely. Also passed was a law that scrapped the final wave of voucher privatizations and replaced them with a direct sale method. However, foreign participation has been the lowest since the inception of privatization in 1992, with only 3 out of 232 foreign companies accepting direct sales offers between January and August 1995 {see Endnote 143}.
Hungary has embarked on one of the most ambitious of privatization schemes. Hungary is the only country in the region to build a vertically integrated company, the Hungarian Oil and Gas Company (MOL) {see Endnote 144}. MOL was founded in 1991 and is Hungary's largest company. Its utility segment ranks as one of Europe's top 15 oil and gas utilities. Currently, Hungary produces about one-fourth of its oil and half its natural gas needs. MOL accounts for 90 percent of the nation's oil and gas production, refining capacity, and reserves {see Endnote 145}. Political uncertainty in the Ukraine and continuing problems with pipeline access to the Adriatic has jeopardized secure energy supplies. As a consequence, MOL has sought to diversify its gas supplies and to develop oil and gas reserves abroad by acquiring exploration licenses in the Former Soviet Union, Algeria, and Tunisia. In 1994, MOL and OMV, Austria's state oil company, agreed to jointly construct a 120-kilometer pipeline linking Baumgarten, Austria, and Gyor, Hungary, providing Hungary with its first access to western gas {see Endnote 146}. Germany also has agreed to sell western natural gas to the company {see Endnote 147}.
In addition, MOL is seeking joint venture partners in oil and gas exploration and production. After several postponements, the first bids for domestic exploration were offered in 1994, with the five concessions being awarded to a consortium of Blue Star, Coastal, and affiliates of Occidental and Mobil {see Endnote 148}.
Before privatizing, MOL began restructuring. In May 1995, the assets of Mineralimpex (previously Hungary's gas importing monopoly and, at the time, the country's second hydrocarbons trader after MOL) were transferred to MOL {see Endnote 149}. Both MOL and its new Mineralimpex subsidiary have been cutting staff, and MOL expects a profitable 1995 {see Endnote 150}.
In June 1995, the Hungarian parliament passed the long-awaited Privatization Act. After a promising beginning and several false starts, the first wave of energy sector privatization went forward with a "combined offer" during October/November 1995. Companies in western Europe, Russia, and the U.S. competed for stakes in Hungary's oil, gas, and electricity businesses. In November 1995, Hungary sold an 18.8-percent stake in MOL, the first time ownership in an eastern European oil company had been sold {see Endnote 151}.
Foreign investment and competition have been visible in the retail sector for some time. Two decades ago, Shell Hungary was allowed its first franchised filling station through a local agreement with the state trading company, Interag {see Endnote 152}. By 1993, the company was 100-percent Shell-owned. By 1994, Shell had 15 percent of all service stations and held a 20-percent share of product sales. MOL still leads the retail gasoline market in Hungary, with 50-percent of the service stations and a 35-percent share of product sales. Other major gasoline marketers in Hungary include Mobil, Exxon, Conoco and Total, with each holding about a 5-percent share of the country's gasoline market {see Endnote 153}.
Since 1989, Poland has undergone several changes in government, a fact that has delayed privatization {see Endnote 154}. In 1995, after a three-year delay, Poland finally took the first serious steps to privatize major state-owned enterprises by launching their long-awaited mass privatization initiative. Instead of a voucher system, Poland has set-up 15 National Investment Funds (NIFs). The NIFs are joint stock companies that were allocated 60-percent shares in 44 industrial companies created from the privatization of state enterprises.
The government is currently deciding on how to restructure and privatize the Polish oil and gas industry {see Endnote 155}. Poland intends to rapidly modernize its energy industry, but to date no part of its energy industry has yet been privatized. As a result of legislation passed in 1995, privatization in most energy sectors, including coal mines, oil and gas sectors, and energy distributors, requires parliamentary approval. Poland's modest oil onshore production is in the hands of the Polish Oil and Gas Company (POGC) and offshore production is performed by the joint stock company Petrobaltic. The POGC, one of the last fully integrated, state-owned monopoly petroleum enterprises in Europe, has sole responsibility for exploration and production of both gas and oil, gas imports, transmission, storage, and distribution. The government has tentatively adopted a restructuring plan for the POGC intended to transform it (in stages) into separate, independent companies for exploration, drilling, production, transmission and distribution. The government is considering limiting foreign ownership in such privatized major companies to minority stakes.
The country produces only around 1 percent of its domestic oil needs {see Endnote 156}. Russia supplies Poland with 60 percent of its natural gas. However, unlike other eastern European countries, Poland is less dependent on Soviet crude oil due to its Baltic Sea ports. In 1991, licensing for gas exploration was opened to domestic and foreign companies. Since then, two licensing auctions have been held. Several foreign companies have participated, including Exxon, Shell, British Gas, and Amoco.
Downstream, seven refineries organized as joint stock companies supply the bulk of the country's product needs. Under preliminary government plans, they are to be merged with CPN, the state-owned gasoline distribution network. Shares in refineries are to be offered separately to strategic investors. Minority shares (of 20 to 30 percent) in refineries may go on sale under a plan to consolidate and later privatize the oil sector. Poland's second largest oil refinery, Rafineria Gdanska S.A., has signed a contract with Chevron to use the company's licensed technology in a planned $400-million upgrading {see Endnote 157}. Plock and Gdansk, the two main refineries, are embarking on modernization programs worth more than $1.5 billion.
Polish authorities have introduced competition in gasoline wholesaling and retailing, and both foreign and domestic suppliers are entering the market. Foreign investment in the Polish gasoline retailing business has been modest so far due to uncertainties. Norway's Statoil and Finland's Neste have 11 gasoline stations each, Conoco has nine, Esso and Royal Dutch/Shell have six each, and Germany's Aral has four {see Endnote 158}. Amoco is expanding into gasoline retail operations in Poland {see Endnote 159}. The company opened its first stations in Poland this year, with plans to build 150 of them over the next decade. Texaco is about to start its own gasoline station building program and Sweden's OK Petroleum bought a controlling interest in Va-Po SA, which owns 22 gasoline stations.
The Romanian oil and gas industry is eastern Europe's largest oil and gas producer. It also has the region's largest petrochemical industry {see Endnote 160}. With 1.6 billion barrels of proved oil reserves, more than four times the total of other eastern European countries combined, it has the most to gain from energy foreign investment. However, along with Bulgaria, its reform is one of the slowest in eastern Europe.
Romania's oil and gas industry was restructured twice, in 1990 and in 1993 {see Endnote 161}. It now consists of a series of state-owned units. These include: Rompetrol (responsible for oil and gas imports, and licensing foreign companies), Petrom (oil exploration and production), Conpet (oil distribution), Peco (gasoline distribution and sales), and Rafirom (refining). Romgas is the nation's gas distribution company. There is a possibility that further restructuring will take place, creating a single, vertically-integrated company in which up to 49 percent of the equity could be sold.
After a decade of declining crude oil production (attributed both to neglect and to the use of outdated technology), production between 1994 and 1995 began to level off {see Endnote 162}. Currently, the country produces about half its oil requirements and consumption is rising rapidly. Romania needs to invest in further exploration and has therefore attempted to encourage foreign investment.
Even though privatization legislation was passed in 1991, the lack of progress in restructuring and privatizing has thus far been discouraging to foreign capital. However, even with later modifications, the law still lacks clear guidelines for negotiating leases and does not allow disputes to be settled by international arbitration. Due to these uncertainties, Amoco, which has an onshore concession, has threatened to pull out of its proposed $60-million investment to build a network of 60 filling stations {see Endnote 163}. Most foreign investment in the energy sector is performed through joint ventures.
In 1992, Romania held its first licensing auction since the end of Communism, offering both onshore and offshore concessions. Shell and Amoco each were awarded an onshore block and an Enterprise Oil-Canadian Occidental consortium was awarded two offshore blocks {see Endnote 164}. Romania's National Agency for Mineral Resources (NAMR), a newly formed agency created in 1995, is currently holding its first, and the country's second, licensing auction that includes 15 new blocks, all onshore, except one that includes an offshore block in the Black Sea continental shelf.
Romania's refining industry is inefficient and suffers from overcapacity. The use of outdated technology raises the price of the end product to over twice that of imported refined products. Romania is seeking foreign investment to help finance a $230-million planned investment program to upgrade its five largest refineries (which account for nearly 85 percent of the country's total capacity) to western standards by 1999 {see Endnote 165}. The other five refineries will be devoted to petrochemicals. Many problems have delayed the project, and western companies, including Amoco and Texaco, are reevaluating prior commitments {see Endnote 166}.
In marketing, Royal Dutch/Shell was the first western firm to open and operate retail gasoline stations in Romania {see Endnote 167}. Other western companies, such as Amoco, are considering retail investment options {see Endnote 168}.
China and Vietnam are largely agrarian societies ruled by Communist parties. To rebuild their economies and maintain their monopoly power, the ruling parties have allowed fragments of a market economy to develop in a move towards socialist market economies. These reforms include opening up areas to foreign participation previously inaccessible. Privatization in these areas has been restricted mainly to production-sharing agreements (PSAs) and joint ventures.
Unlike the countries of the FSU and Eastern Europe, both China and Vietnam in the past decade have experienced tremendous growth, which has increased the demand for energy supplies. In recent years, both countries have maintained a positive trend in the production of energy resources. However, China's energy sector recently has had trouble keeping up with its rapidly expanding economy, which is outstripping its energy supplies and raising its dependence on imported oil. Vietnam's emerging energy industry, on the other hand, is developing as a potential major net exporter of petroleum products and gas in the Asian-Pacific market.
China's petroleum industry is still under strong central control. Little has been done to allow foreign ownership of China's assets in its oil and gas industry. The industry is dominated by four large state-owned corporations: two state petroleum companies and two downstream companies {see Endnote 169}. The largest of the two petroleum companies is the Chinese National Petroleum Corporation (CNPC), an integrated industrial organization founded in 1949 to plan, organize, and manage the exploration and development of onshore oil and natural gas resources. The CNPC controls more than 95 percent of China's onshore oil and natural gas fields. All offshore oil and gas exploration andproduction is under the control of the second petroleum company, the China National Offshore Oil and Gas Corporation (CNOOC). It was founded in 1982 to act as the state representative in joint developments with foreign companies of China's offshore oil and gas reserves. The China National Petrochemical Corporation (Sinopec), the state refiner, was formed in 1983 to develop an integrated Chinese refining and petrochemical system. The China National Chemical Import and Export Corporation (Sinochem) is the import and export company responsible for trading international crude oil and oil products. It is the country's main importer of crude oil.
In 1993, China became a net oil importer for the first time. China's strategy is to increase domestic oil and gas output by stabilizing production in eastern China's mature fields, by increasing the focus on exploration and development in the western regions and by continuing to encourage offshore development. Central to this strategy is an expansion of exploration and production joint ventures with foreign companies.
Thus far, China has adopted a very limited form of privatization. Most foreign activity is in production-sharing contracts. Most oil and gas production comes from onshore activity; however, until recently, most foreign activity had been limited to offshore exploration and development. In 1993, the need to meet production targets led China to open up onshore areas to foreign investors with the first of three investment auctions.
Eastern China, the country's traditional producing region, is where most of the country's large oil and gas fields are located. Oil production from eastern fields accounts for more than 90 percent of the country's total crude oil production of 3 million barrels per day {see Endnote 170}, but these aging fields are beginning to decline.
China has recently emphasized exploration and development expenditures in western regions, particularly in the Xinjiang region of the northwest. Most onshore tracts offered to foreign investors in the three investment auctions are located in this area. Crude oil production in 1994 from the Xinjiang region in northwest China was 225,000 barrels per day {see Endnote 171}. The three major basins in the Xinjiang region are Tarim, Turpan-Hami, and Junggar. Experts believe Tarim is the most promising as far as the possibility of finding "elephant-class" discoveries. However, Tarim's remoteness and lack of infrastructure have made it difficult for transportation facilities to keep up with discoveries, temporarily reducing production. To entice foreign companies who are concerned about getting their oil to market, China has launched a massive infrastructure expansion program in this region which will include pipelines, a trans-desert highway, parallel rail lines, and expanded storage.
Offshore crude oil production in 1994 averaged 130,000 barrels per day {see Endnote 172}, 4.5 percent of China's total crude oil production. Until recently, all foreign activity was limited to offshore exploration and development. Offshore China was opened to foreign investors in 1982. Since then, the CNOOC has held four investment auctions. By 1994, foreign investment in China's offshore oil and gas exceeded $4 billion. Currently, there are 12 offshore oil and gas fields in operation, of which four include participation with foreign partners - ACT Operating Group of Agip SpA, Amoco and partners, Chevron, Japan's JHN Group, Phillips Petroleum, and Texaco {see Endnote 173}.
Natural gas makes up only about two percent of China's domestic energy production and has long been overshadowed by the country's coal and oil production. However, environmental concerns have led China to recently shift its oil and gas exploration and development emphasis towards natural gas, both on-and offshore. The CNPC plans to step up gas exploration and development in western China. Gas production is expected to increase offshore since China's largest offshore gas field, Yacheng 13-1 {see Endnote 174}, began producing in early 1996. In addition, the Sichuan gas project has been proposed to develop and rehabilitate fields in the Sichuan province, where most of China's gas is produced, in order to halt the decline in field productivity {see Endnote 175}.
By the end of 1994, China's total refining capacity had reached 3.4 million barrels per day, making it the fourth largest refiner in the world, after the United States, the FSU, and Japan {see Endnote 176}. The country's refining capacity is rising, but not fast enough to accommodate China's soaring domestic demand for refined products. Thus, China has embarked on a major restructuring and expansion plan and started to encourage foreign joint venture participation. The focus is to modernize the industry to international standards and to add an additional refining capacity of about 1.4 million barrels per day by year 2000 {see Endnote 177}. Beginning in the early 1990s, Sinopec led efforts to expand capacity and build new "grassroots" refineries by decentralizing the refining industry. It began to allow other Chinese oil companies, such as the CNPC, to build refineries. However, government restrictions limiting market access have made it difficult for potential foreign investors to finalize projects. For example, France's Elf Aquitaine pulled out of a proposed $2.5-billion refinery project in Shanghai at the end of 1995, while Shell has yet to reach an agreement with Chinese officials to build a refinery in the Guangdong province, after seven years of negotiations {see Endnote 178}. As a result, although many proposals have been submitted by foreign companies, presently there are only two foreign companies with investments in China's refining industry--France's TOTAL owns a 20-percent stake in a northeastern Chinese refinery, while ARCO owns a stake of 9.9 percent in the Zhenhai Refining and Petrochemical Company {see Endnote 179}.
Unlike the countries of the Former Soviet Union and Eastern Europe, who are restructuring their mature oil and gas industries, Vietnam is building a nascent oil and gas industry, spurred by foreign investment. Due to this investment, Vietnam with virtually no hydrocarbon production a few years ago--produced 171,000 barrels per day of oil in 1995 {see Endnote 180}. The country is already on its way to becoming a major source of petroleum in the Asian-Pacific energy market. Vietnam opened its economy to foreign investment in 1988. However, U.S. companies did not begin investing until 1994, when the twenty-year U.S. trade embargo was lifted. Vietnam has tried to make the country more attractive to foreign investors by various reforms in its petroleum law. The country's first petroleum law was ratified in July 1993. This law assigns upstream and downstream petroleum operations to the state-owned enterprise, Petrovietnam, founded in 1977. It also gives the company the power to parcel acreage to select contractors based on competitive investment auctions or other government-announced programs. Most foreign investments are in the form of production-sharing agreements or joint ventures. Vietnam also is directing foreign investor activity toward the building of infrastructure to include refineries, gas pipelines, and hydrocarbon-fueled power plants. Unlike many former Communist economies in transition, where uncertainty is causing lengthy delays, Vietnam has established a stable legal and tax environment that reduces uncertainity and enables companies to quickly move from the initial stage of signing agreements to the stage of producing the fields.
However, regional territorial disputes are an impediment to the development of some of Vietnam's offshore petroleum resources. Hydrocarbon potential off the Spratly Islands in the South China Sea and competition for additional energy reserves recently reignited a long-standing feud between China and Vietnam surrounding ownership of the Islands and adjacent waters. The territorial dispute arose again when China awarded an exploration block in the disputed waters to the U.S. independent oil company Crestone Energy Corporation. Later, Vietnam awarded an adjacent block to a Mobil-led consortium. Six countries China, Vietnam, Taiwan, Philippines, Brunei, and Malaysia all lay claim to this part of the South China Sea {see Endnote 181}.
Virtually all Vietnamese exploration and production activity occurs off Vietnam's southeastern coast. By the end of 1994, after two licensing auctions and the signing of 25 offshore production-sharing agreements, the number of exploratory wells rose considerably {see Endnote 182}. Most petroleum production in Vietnam occurs in three fields, Bach Ho, Rong, and Dai Hung. The Bach Ho and Rong fields are operated by VietSovPetro, a Vietnamese-Russian joint venture. Bach Ho, the country's first and largest producing oil field, was discovered in 1975 by Mobil, which abandoned the well when the U.S. withdrew from Vietnam. The well was later developed in 1986 by VietSovPetro. Both the Rong and Dai Hung fields led by a BHP consortium composed of BHP, Petronas of Malaysia, Total, Sumitomo, and the Vietnam Oil and Gas Corporation came on line in 1994 {see Endnote 183}. Newly discovered fields could be on line soon, raising the country's production even further. For example, Petronas is developing its Ruby field, while Mitsubishi and Japan National Oil are developing the Rang Dongfield, with production in both fields to start by 1997. Other fields that could come on line are the Flying Horse, discovered by Lasmo; the Red Orchid and the West Orchid (both located in disputed waters), and the Sunflower North and South Fields, discovered by BP; as well as two other unnamed fields, one discovered by Total and the other discovered by Shell/Pedco. These major fields are all located in the Nam Con Son Basin {see Endnote 184}. Despite initial exploration successes, geological difficulties are making it hard to estimate recoverable reserves, raising concerns over the viability of some projects. Several fields that were originally thought to be quite large are now being downgraded--for example, the BHP consortium's Dai Hung field and the Mobil consortium's Thanh Long block. Further, BHP is considering abandoning its Dai Hung project if new terms cannot be negotiated {see Endnote 185}. Several recent gas discoveries have opened up the future of the gas industry in Vietnam. Perhaps the most significant activity involves two major gas field strikes in southern Vietnam drilled by British Petroleum (BP) and its partners, India's ONGC, and Norway's Statoil, with reserves estimated at a combined 2 trillion cubic feet {see Endnote 186}.
Another area of discovery with potential gas reserves is at the Hai Thach gas field. It may take a few years before reserve estimates can be formulated, but if the country's proven natural gas reserves are estimated between 12-35 trillion cubic feet, Vietnam plans to commit itself to the development of a natural gas industry for domestic use as well as possible export markets {see Endnote 187}. In April 1995, Vietnam commissioned a consortium comprised of BP, British Gas, Mobil, and Mott Ewbank Preece to develop a master national gas plan {see Endnote 188}. In the meantime, Vietnam's first gas pipeline (built by Hyundai of Korea) went into operation in 1995, bringing production ashore from the Bach Ho field {see Endnote 189}. Vietnam also is studying the possibility of exporting gas via pipeline to Thailand {see Endnote 190}.
Substantial upstream activity has led to Vietnam's generating plans for downstream oil and gas infrastructure projects. As Vietnam's economy grows, it plans to reduce its reliance on imports by building its first oil refinery by the year 2000. Vietnam commissioned two feasibility studies regarding the possible construction of a 130,000 barrels-per-day refinery. France's TOTAL, a consortium member of the study, withdrew from the project over objections concerning the chosen site, located in a remote area of central Vietnam. South Korea's LG Group, Petronas of Malaysia, and Conoco were chosen to replace TOTAL, but the companies said that no decision has been made beyond a feasibility study since there are doubts about the viability of the project {see Endnote 191}. Vietnam hopes to build a second 100,000- barrels-per-day refinery after the first plant comes on line {see Endnote 192}. In the meantime, Petrovietnam has asked for bids to begin studies for a second refinery, likely to be located in the northern part of the country. Despite foreign involvement in upstream activities, Vietnam has denied foreign investors access to its retail sector {see Endnote 193}.