Power Industry: Regional Export Potential in Central Asia
Loup J. Brefort, Acting Country Manager, World Bank Kazakhstan
There is an increasing realization among the Central Asian Republics (CARs), that the key to completing economic recovery and to further development lies in the increased internal trade among themselves and exports to neighboring states, and this is particularly true in the energy sector.
Four of the CARs, except Turkmenistan, have formed the Central Asian Cooperation Organization (CACO) to among other things, focus on enhancement of energy trade both within and outside Central Asia, and have asked the Bank help in this regard.
The Bank response to this agenda has been two-pronged:
· first, it is engaged in the development of the energy sectors in each of the CARs through policy reform support and investment financing, which when implemented will play a significant role in enhancing the energy trade agenda; and
· second, it is contributing at the regional level through analytical support for the realization of energy trade.
At the regional level, the Bank completed and shared with the countries, the Central Asia Water and Energy Nexus Study which focused on the problems created by post-independence in the use of water for hydropower and irrigation in the Syr Darya river basin.
The Bank has completed a study to identify Regional Potential for Electricity Trade both within the region and with adjoining countries.
Discussions on the results of the study have taken place with selected power experts, electricity industry representatives and government officials in most of the countries concerned. Further dialogue is contemplated in each country, at the regional level and with Central Asia neighbours, as the World Bank is keen to contribute to foster greater cooperation between countries in the power sector.
Basic Features of the Power Sector in the Central Asian Republics
Capacities and Output
At the end of 2002, Kyrgyz Republic, Tajikistan, Uzbekistan and Kazakhstan had a total installed capacity of around 38,000 MW. Total generation amounted to over 134,000 GWh of which 31% was from hydropower plants and the remaining 69% was from thermal power plants.
However, total sales in CAPS to domestic consumers amounted to slightly below 98,000 GWh implying an overall average system loss level of 27%.
Total volume of exports from these four systems was only 2.0% of their total generation. About similar to imports.
Regional Electricity Trade
Indeed, the volume of trade had gone down considerably from the levels in 1990. The total export/import flow in 2000 was only 30% of the 1990 level, even though the consumption levels in each country has recovered to about 80% of the 1990 level.
The Potential of the Region for Electricity Trade and Export
Projection of Future Regional Demand
Taking into account factors of price and GDP elasticity, the Bank projects that total demand in all four CARs would increase only at a modest annual rate of 0.04% in the short term (2005–2010).
Over the longer term (2005–2025), all countries would register an increase in demand, resulting in an annual compounded growth rate of about 1.95% for the region. Kazakhstan would experience the highest annual rate of growth (2.74%), and Uzbekistan the lowest (1.14%).
Seasonal variations in electricity demand are significant in CARs. For the region as a whole, 58% of the annual consumption takes place in winter. This is a key factor to be considered in the assessment of supply/demand balances and for determining the exportable surplus.
What are the Supply Options to Meet the Demand in the Region?
· projects for rehabilitation of the transmission and distribution system to reduce the high level of losses;
· projects for rehabilitating the existing generating units; and
· construction of new generating plants.
Loss reduction programs. Reduction of technical losses in the transmission and distribution system is the most economical method of meeting the incremental demand when the loss levels are high compared to industry standards. Much of the losses are occurring in the low voltage distribution systems, since the consumption structure has shifted more towards residential consumption in all countries. Though losses in the transmission systems, reported to be about 8%, are higher than the industry standard of 4% to 5%, most of the system is still carrying loads significantly lower than their design capacity; and considerable investments have already been made in the transmission systems.
The focus of future investment should thus be first on distribution rehabilitation, reinforcements and expansion.
The total value of investments on such transmission and distribution loss reduction projects in all four countries is estimated at over $3 billion in 2004 prices. If implemented, this would make available an annual incremental supply of over 13,000 GWh of electricity by 2010.
Rehabilitation of Existing Generation. Major hydropower stations in the region are generally in a reasonably good condition. On the other hand there is considerable scope for rehabilitation of thermal power stations, particularly in Uzbekistan and Kazakhstan.
In Uzbekistan Uzbekenergo estimates that out of the total installed thermal generating capacity of 9,870 MW (11 thermal plants), only about 8,200 MW is actually available. If units well beyond the age of 35 years and/or 200,000 hours of operation are also excluded, the available capacity would be even lower at 7,800 MW.
UzbekEnergo is undertaking rehabilitation of the country’s electric generation capacity through several projects, including an $81 million loan from EBRD for the renovation of the Syrdarya plant and a $200 million loan from JBIC for the rehabilitation of Tashkent coal fired station. Further rehabilitation of two units at Syr Darya as well as the rehabilitation of the Angren and Navoi units are planned.
When all the planned rehabilitation of power plants is implemented over the 2004–2023 period at a cost of $1.15 billion, the operational life of all major power plants would have been extended avoiding the loss of generation of about 32,000 GWh (during 2005-2025) due to retirements.
In Kazakhstan, there is a need for rehabilitation of Ekibastuz, Aksu and Karaganda coal fired thermal power plants since all of them are operating at low plant use factors, and 58% of the total installed thermal capacity, or about 10,600 MW, will reach the end of its operational life before 2015.
The Kazakhstan Electricity Association (KEA) estimates that roughly $1,070 million is needed to rehabilitate the thermal power plant ($770 million for national power plants and $300 million for the regional plants owned by the Regional Electricity Companies) to extend the operational lives of the units and improve the plant factor to 60%.
With such rehabilitation, the incremental annual generation from those plants would amount to 17,118 GWh.
New Generation Projects. Large new power plant projects are contemplated in all four countries.
· Expansion of Ekibastuz II Thermal Power Station in Kazakhstan: The existing Ekibastuz II power station has all the infrastructure and site facilities to accommodate easily two more units of 500 MW each. A recent study has estimated the cost of construction of these additional units at $1,085 million. This project is expected to be implemented during 2008–2011 and is expected to result in an incremental annual generation of 7,446 GWh.
· Bishkek Thermal Power Plant in the Kyrgyz Republic: The construction of this plant, referred to sometimes as Bishkek CHP II, began in 1985 but has been put on hold since 1992. The original scheme was to develop a combined heat and power plant of 800 MW, including seven heat-only-boilers as Phase 1 of the plant. This plant could provide an annual incremental generation of 2,453 GWh relatively rapidly. Taking into account the site facilities already available the capital cost is not expected to exceed $200 million (or $500/kW).
· Kambarata I & II Hydroelectric Projects in the Kyrgyz Republic are the projects which are actively pursued by the government. Kambarata I is a 1,900 MW storage hydroelectric facility with annual energy generation of about 5,000 GWh with a plant use factor of about 30%. Enabling additional generation of electricity during winter without releasing water from Toktogul would be the most significant contribution of this project. The estimated capital cost of Kambarata I is about $1.67 billion, and together with transmission line costs needed to evacuate power, the total costs would amount to $1.94 billion (or $1,000/kW).
Kambarata II would be a run-of-the river hydro project downstream of Kambarata I but upstream of Toktogul. The installed capacity would be 360 MW if Kambarata I is developed, or 240 MW if it is a stand-alone scheme. The average energy production would amount to about 1,100 GWh at 240 MW and 1,260 GWh at 360 MW. About 20% of the project had already been completed and the incremental costs for completing this project are estimated at about $280 million for a 240 MW plant, including the necessary transmission lines. It is important to note that Kambarata II project would merely add to the summer surplus and would not help to remedy the winter shortage of electricity. Construction is proceeding very slowly but RAO UES of Russia has agreed to fund the study to update the feasibility report.
· Rogun Hydropower Project of Tajikistan. The project was planned to be constructed in two phases with an ultimate installed capacity of 3,600 MW. The construction commenced during the Soviet regime but, since 1992 no further progress had been made for want of funds. The electricity output of Phase I with two 800 MW units would be about 4,300 GWh, and it would also enable the generation of an additional 400 GWh at Nurek. The funds needed to complete this phase is estimated at $785 million. Phase II involving completion of the dam to its full height of 335 meters and installation of additional power capacities of 2,800 MW is expected to cost $1.67 billion. After completion of Phase II, the whole Rogun scheme would generate roughly 13,000 GWh and the additional generation at Nurek will increase to 1,300 GWh.
· Sangtuda Hydropower Project in Tajikistan. The construction of this project was suspended in 1992 after completing a sizeable amount of work. The planned installed capacity on this run-of-the- river scheme is 670 MW and expected annual electricity generation would be about 2,700 million kWh. About 60% of the generation will be in the summer months and the remainder would be during the winter months. It is estimated that about $368 million are needed to complete the project.
· Talimardjan Thermal Power Project in Uzbekistan is a gas fired steam turbine project with 4 units of 800 MW each. It is located in the Mubarek gas field, one of the larger producing gas fields in Uzbekistan, less than 50 km from the Afghanistan border. The first unit is expected to come on stream in 2005. It is estimated that about $100 million would be needed to commission this unit, which at a plant factor of 60% would annually produce about 4,537 GWh. A second phase would involve construction and commissioning of the three remaining units and could take place during 2009–2013 after firming up possible export sales agreements. The capital cost for this phase is estimated at $1.2 billion ($500/kW) taking into account the infrastructure which is already in place. These three units would provide an annual incremental generation of about 13,613 GWh.
Overall Supply Increases.
As a result of the implementation of the above mentioned projects the overall gross supply in all four countries would rise from 140 TWh in 2003 to 230.5 TWh in 2025.
About 56% of this incremental supply would come from new generating units, about 16% from loss reduction programs and the balance 28% from the rehabilitation of old generating units.
Kazakhstan would contribute 47% of the incremental supply, followed by Uzbekistan and Tajikistan (22% each) and the Kyrgyz Republic (9%).
Demand and Supply Balance and Export Potential.
When the supplies for each country for each year during the period 2005–2025 are compared to the demand projections for each country for each year, and winter/summer seasonality factors are taken into account, the analysis shows that in 2005 all the exports would only be in summer and no firm power export would be possible. Thereafter, however, firm power exports would become possible.
In 2010 firm power exports of the order of 22.0 TWh (i.e., twice the winter surplus) could be achieved. The balance of 9.6 TWh would be for seasonal exports, part of which could be for peak hour supplies in the importing countries fetching a price premium.
The firm power export volume would rise to 41.2 TWh in 2015, and 42.6 TWh in 2020 and drop to 20.2 TWh in 2025. The decline in the export surplus after 2020 is a result of the cumulative demand growth within CARs and the retirement of old units. If the export volumes have to be maintained new capacity additions have to be thought of well in time.
Regional Trade. The Demand/Supply analysis at the individual country level and the regional level concludes that least-cost option for the CARs to meet their respective demand at least up to 2020 comprises: reduction of (technical) losses (which requires investments in transmission and distribution); implementation of efficiency and demand management measures; rehabilitation of thermal power plants (mainly in Kazakhstan and Uzbekistan); and trading for electricity at the margin.
There is a case for enhanced regional trade within the CARs, to smooth over peak demands and seasonal fluctuations. For example, the short run marginal cost of thermal generation in Uzbekistan is 2.5 cents/kWh, compared to 0.3 cents/kWh for hydropower in Kyrgyz Republic and Tajikistan. The pricing policy reforms that Uzbekistan is implementing makes it more and more likely that such trade between Kyrgyz Republic and Tajikistan on the one hand and Uzbekistan on the other should take place, which would also enable Uzbekistan to conserve its gas. In other words, to the extent that Uzbekistan pursues a self-sufficiency policy in electricity, it is incurring an avoidable cost of 1.5 to 2 cents/kWh on its thermal generation in the summer.
However, such trade is currently limited by the (simultaneous) winter peaking nature of systems in CARs, whereas the peak hydro generation occurs in the summer. To overcome these constraints, new strategic assets are needed but, as important, is further reform of the policy regimes.
Indeed, trade within the region could increase if:
· Payments for electricity, water services, and fuels are fully monetized and if the annual IGIAs are based on least cost solutions for the river basins as a whole;
· The transmission systems in all four systems provide non-discriminatory third party access on the basis of transparent transmission tariffs.
· While independent regulation is a final objective (which may take many years to realize), bringing transparency to regulation; and providing multi-year regulatory certainty (e.g., adopting a tariff policy that covers several years), is a necessity;
· Metering, payment discipline and settlement mechanisms have to be improved.
· Further, in order to arrive at rational trade decisions, prices of electricity in all four systems need to reflect the cost of supply.
· Finally, Private Sector Participation is a necessity, in view of the huge investment needs and, in some systems, weak management capacity.
The current policy frameworks are generally in the right direction in all countries, but policy implementation needs to be accelerated to assist sector development.
Export Beyond the Region. At the same time, in view of the fact that the peak consumption in Afghanistan, Pakistan and Iran occurs during summer, there is a natural complementarity between these countries and CARs. The current summer surpluses can be supplied to these countries even now, with the building of the transmission lines.
Some projects in CARs, especially Sangtuda, Rogun in Tajikistan and Talimarjan II in Uzbekistan, would be pure exporters, and are likely to be quite competitive in the target countries, even after considering transmission costs.
Projected Electricity Demand: The study estimates the demand would grow from 911.4 GWh in 2002 to 5,208 GWh in 2020 at an average annual rate of 10.17%.
Electricity Import Strategy: The least-cost and the most practical option for Afghanistan to meet its electricity demand in the short and medium term is to import electricity from the Central Asian Republics and from Iran. The available scarce international aid funds are best used to rehabilitate and reinforce the transmission and distribution systems to expand the consumer base and to be able to provide reliable supply.
Afghanistan as a Transit Country: Afghanistan has the potential to wheel power from the Central Asian Republics to Pakistan. In addition, since Turkmenistan is operating in an island mode in relation to CAPS, Afghanistan may be able to wheel power from Tajikistan to Iran via Herat. Thus Afghanistan has the potential to earn significant transit fees from such electricity trade. To play this role effectively Afghanistan has to rehabilitate and reinforce its transmission system and be in a position to offer transparent transmission tariff and third party access.
Demand Growth and Outlook: Demand growth has accelerated considerably and given interconnections bottlenecks, 19 out of the 31 provinces are currently experiencing serious shortages of power supply affecting industrial production. Given its rate of GDP growth projections, and its relatively low level of present per capita annual electricity consumption (1,062 kWh), the forecasted long term electricity consumption growth rate of 4.5% per annum through 2020 may prove conservative.
Export Possibility to Xingiang Province: The installed generation capacity in Xingiang province at the end of 2001 was 4,744 MW and its annual power generation is about 19.6 TWh. It experienced recently an annual electricity demand growth at rate of about 8%. In the context of electricity prices in China rising as a result of the tightening of coal supplies and increasing oil and gas costs and in the context of electricity shortages, Kyrgyz Republic and Tajikistan could hope to capture a part of Xinjiang market demand for the export of their hydroelectric power.
With a population of about 65 million (2000) and a per capita GDP of about $1,000, Iran is endowed with an abundance of energy resources. Nonetheless, it is a potential market for exports of electricity from the Central Asian Power System on account of its summer electricity shortages as well as the isolated nature of the grid adjoining Turkmenistan.
Demand Outlook: Electricity consumption during 1990–2000 grew at average annual rate of 7.7%. Recent estimates are that the annual shortage in the Iranian system is about 6 billion kWh. and most of this shortage arises during summer. A peak demand of 40,000 MW and an energy generation of 239 TWh are forecast for 2010. The installed capacity is planned to be tripled by 2020 to about 96,000. But, while fuel sources are available, financing for the new capacity is proving to be a major constraint. Invitations to private investors on a build, operate and own (BOO) basis did not elicit much response.
Electricity Trade: Iran is seriously looking at electricity imports from Central Asia for several reasons
· First, high rates of growth in electricity demand and the continued financing constraints to build the needed capacity in time to meet the demand is more than likely to result in demand/supply gap widening, if solely dependant on indigenous supply.
· Second, the lack of a unified grid in the country will also hamper the ability to generate power where the necessary resources (e.g., gas and hydro) are available, and importing from neighbors (e.g., as is happening in the Mashad province) is often more economic.
· Third, entering into electricity trade relationships serves Iran’s foreign policy agenda and would serve commercial interests as well–Iran has offered to help Tajikistan build the Sangtuda hydro-power scheme, and given that Iran would have spare capacity (in the medium term) in the winter, can even export to its neighbors.
Demand Outlook: For the period 2000–2010, forecasts based on moderate GDP growth rates seem to indicate an average annual electricity demand growth rate of about 6%. These forecasts further indicate that notable capacity and energy shortages would appear in FY 2005–06 and that capacity shortages could grow from 411 MW in that year to about 5,500 MW by FY 2009–2010.
Electricity Trade: The policy makers in Pakistan are fully aware that the indigenous energy resource base is insufficient to meet such demand over the medium and long term. Accordingly, they recognize that imports of energy would have to increase, and they are seriously considering import of electricity from the Central Asian Republics, via Afghanistan.
Russian power system, one of the largest in the world, represents a market with significant potential. The ongoing construction of the second 500 kV north-south line in Kazakhstan would greatly enhance the power transfer capability between the Russian system and CAPS.
Electricity Trade: Export of electricity is viewed as a priority by RAO UES as providing one of the sources of funds for investment. In 2002, RAO UES exported a total of 16.7 TWh of which 7.4 TWh went to the CIS. The remaining 9.3 TWh went to China, Latvia, Mongolia, Norway, Poland, Estonia, Turkey and Finland. The largest volume of export went to Finland (7.5 TWh). The company aims to maximize its exports to West European destinations with higher electricity prices. A recent conservative forecast estimates that exports might grow to the level of 40 TWh by 2020.
Strategies and Prospects: Russia seeks the Nordic markets through Baltic ring arrangements, markets in Turkey through Georgia, and markets in Moldova, Romania and the Balkans (constituting the so called second UCTE systems) through Ukraine. It has also long term interests in supplying the profitable markets in China, South Korea and Japan making use of the large hydro resources in the Far East Russian regions. It also aspires to synchronize its grid with west European systems in not too distant a future.
Inter RAO UES is also eyeing the possibility of importing inexpensive hydropower from CAPS, partly for balancing the regional systems like Omsk and partly for augmenting its pool of exportable surplus. Offers to buy summer power from Kyrgyz republic and Tajikistan, and offers of help to construct Kambarata and Rogun hydro power projects are probably part of this strategy. The prevailing low wholesale market prices in Russia need to rise considerably to make imports from the new large projects in CAPS attractive. However, if Russia succeeds in exporting its electricity to the UCTE countries at prices around 4.0 cents/kWh then import of power from CAPS can become very attractive for Russia.
While there is real potential, realization of this export potential of the CARs calls for tackling at least three groups of significant institutional issues.
The first group of issues (Water and Energy Nexus Issues) relate to the institutional arrangements necessary to operate the existing and proposed large multipurpose reservoirs and the associated hydropower facilities in a manner acceptable to all riparian states and for the optimal benefits for the entire river basins.
The second group of issues (Power System Operation Issues) relate to the need to reform and operate the power systems of CARs to maximize electricity trade within CARs and with external electricity markets.
The third group of issues (Investment Issues) relate to the organization and financing of the legal corporate entities to raise financial resources, construct, operate the new large hydro and thermal projects and market the electricity generated. Indeed, the size of the investments discussed above are large–about $13 billion in real terms over the next 20 years.
Given the existing and anticipated dominant role for hydroelectric power in these systems, these three groups of issues are inseparably intertwined and call for a coherent resolution.
The recent formation of the high-level CACO which now will include Russia and its focus on regional cooperation in water and energy sectors through the establishment of a Water and Energy Consortium (WEC) seems to be an auspicious start to enable the operation of existing reservoirs to derive optimal benefit for all riparian states and to facilitate the construction and operation new multipurpose reservoirs.
The Bank stands ready to continue helping the region fulfill its potential in the power sector.
Mr. Loup J. Brefort graduated from the Ecole des Hautes Etudes Commerciales de Paris (France) in 1975 and holds a Master of Business Administration (MBA) from McGill University (Canada).
Prior to joining the World Bank in 1990, Mr. Brefort worked for more than 12 years in private sector in Canada and in Europe. When he joined the World Bank, Mr. Brefort was Manager of the International Management Consulting Department of Coopers and Lybrand, Europe, based in Brussels.
In the World Bank, Mr. Brefort focused on private sector development, privatization and infrastructure investment issues, most notably in the power and water sectors. He worked on projects in North and Southern Africa, in the Russian Federation and in Central Asia, and in several countries of East Asia, most notably in China, Vietnam, the Philippines and Indonesia.
Prior to relocating from Washington D.C. to the World Bank Regional Office for Central Asia in Almaty as Advisor, Energy and Infrastructure, in September 2002, Mr. Brefort was Senior Manager of the Private Sector Development Unit of the World Bank’ East Asia and Pacific Region. In addition to his role as Advisor, Energy and Infrastructure for Central Asia, Mr. Brefort is currently Acting Country Manager for Kazakhstan.
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