IPPS and buts
Power systems are restructuring on a global scale. Nation-states
are ordering the privatization of their power systems. Independent
power producers (IPPs) are finding an increasing number of
countries that offer development opportunities. Generating capacity
is being divested from transmission and distribution to accommodate
competition. This article describes the ways that global power
systems are restructuring and provides a case study of Indonesia's
Java-Bali power market to explain the potential pitfalls of
competitive power in developing countries.
Exhibit 1 illustrates the restructuring activity that is taking place in countries with power systems smaller than 100 GW1. In its most basic form, restructuring may involve only the privatization of state-owned power systems where ownership is transferred from the public sector to private enterprise. Exhibit 1 illustrates the total capacity in systems that are in various stages of state-owned power privatization. According to US Energy Information Administration (EIA) data, only 28% of the capacity in power systems smaller than 100 GW resides in countries that have no stated plans for privatization.
With or without privatization of state-owned power companies, countries are increasingly allowing the participation of IPPs. Under various market structures, IPP participation ranges from building new capacity and selling the capacity and energy under a Power Purchase Agreement (PPA), to competing with other IPPs for energy sales in spot power markets2. Exhibit 1 illustrates that 65% of the installed capacity in countries smaller than 100 GW resides in countries that have IPP development opportunities.
In a more advanced stage of restructuring, governments may require the functional unbundling of the power system, requiring generation to be spun off or divested from transmission and distribution. This is usually done to facilitate wholesale or retail competition in the generation sector. Exhibit 1 shows that the majority of installed capacity in countries smaller than 100 GW is in countries that have either divested their generating capacity or plan to do so.
Competition is widely viewed as a means to introduce efficiency and reduce power prices over the long term. Competition can be implemented to varying degrees, and incremental increases in the level of competition may carry a higher level of risk to suppliers and consumers. Under the simplest form of competition, where prospective suppliers bid for the right to build capacity under a PPA, prices paid to generators are defined to some extent by contract. Risk is generally limited to the supplier's ability to economically procure the inputs to production (such as fuel) and physically deliver power, and the purchaser's ability to pay for the contracted power. However, once a competitive spot market is introduced, prices are driven by short-term supply and demand and can become extremely high and volatile to the potential detriment of both suppliers and consumers. The reason for this goes to the nature of electric power production and delivery.
The nature of competitive power
Among commodities, electric power is unique. The lack of large-scale storage and the absence of suitable short-term substitutes mean that electricity must be produced at the instant it is demanded. High outage costs, volatile and inelastic demand, and the need to instantaneously match supply and demand can result in highly volatile prices.
Spot market price volatility is driven by the very short-term relationship between available supply and non-price-responsive, constantly changing demand. When there is ample generating capacity, prices are usually close to short-run marginal costs (variable costs of the last plant dispatched). However, during high demand periods when the supply-demand balance tightens, suppliers are able to exercise limited market power and prices rise above short-run marginal costs, providing fixed cost recovery for necessary capacity additions. If there is an oversupply of generating capacity, prices may remain lower than what suppliers require to recover their fixed costs. On the other hand, when there is a shortage of generating capacity, spot prices may rise to very high levels.
High spot power prices can be an effective signal that capacity additions are urgently needed, providing incentives for developers to enter the market as quickly as possible. However, if non-economic barriers to entry prevent the introduction of new capacity, competitive prices may remain high. Persistent high prices may require that regulatory intervention substitute for a correction of the supply-demand imbalance that lead to high prices. However, regulatory intervention could aggravate the capacity shortage problem by reducing incentives for developers to bring new capacity to market and by increasing regulatory uncertainty and risk.
The relationship between prices and new generating capacity can be demonstrated by example. In the summers of 1998 and 1999, hot weather combined with capacity shortages resulted in short-term price spikes to over $4,000/MWh (compared to the typical $35/MWh) in the Midwestern US Since then, developers have announced upwards of 75,000 MW of additional capacity and it is likely that over 17,000 MW will have achieved commercial operation by the end of 20013. While not an instantaneous solution, it is clear that competitive price signals have given rise to an appropriate developer response.
On the other hand, in California, permitting requirements have stretched the time to bring a new plant into service to as much as 4 years compared to the typical 2 years for the rest of the country. The lack of new resources combined with atypical high weather-related demand and dry conditions that diminished the availability of hydropower created unmanageable, persistently high prices from May 2000 to May 2001. In June 2001, the Federal Energy Regulatory Commission was forced to put price caps (price mitigation) in place for the entire US western power grid to prevent further price increases and potential economic damage. While these price mitigation measures relieve the immediate problem of high power prices, they may distort the effectiveness of price signals and diminish the incentives for suppliers to bring the appropriate amount of generating capacity to market. Additionally, the resulting regulatory uncertainty may reduce investment in generating supply.
In summary, where electric energy is offered in a competitive spot market, prices reflect the supply-demand balance and provide important signals to would-be suppliers. However, new generating capacity must be brought to market quickly when needed, particularly given the inability of most consumers to reduce consumption when high prices signal that available generating capacity is in short supply.
Indonesia
Until the 1997 Asian monetary crisis, Indonesia was experiencing brisk economic and electricity demand growth. Under Suharto's regime, which ended in 1998, 27 Independent Power Producer contracts were executed. However, when Indonesia suffered a serious devaluation of its currency in 1997, power demand growth slowed and it became clear that the national utility, Perusahaan Listrik Negara (PLN), could not afford the terms of many of these PPAs, priced in US dollars at an average $60/MWh. Work to renegotiate these contracts is ongoing, but the situation has damaged Indonesia's credibility with international developers.
In September 1999, the Asian Development Bank provided a technical assistance loan to PLN to restructure its power sector and design a competitive electricity market. The objective of the restructuring initiative is to produce a financially viable and economically efficient marketplace that encourages private participation and protects the interests of end-users.
Among the mandates from the Asian Development Bank, Indonesia must initiate operation of a multi-buyer power market on the islands of Java and Bali by 2003. In this multi-buyer market, competitive suppliers (generators) would compete to sell power into a power market where multiple buyers bid for energy from multiple suppliers. A spot clearing mechanism and system operator combined into a System and Market Operator (SMO) would be required to support such a structure. Pace and its partners on the project (KEMA Consulting, Professor Frank Wolak of Stanford University, PT Connusa Energindo, and Institute Teknologi Bandung) proposed this model as it is simpler to administer than the model being implemented by most US competitive systems where the market clearing mechanism (for example, the PX in California) and system operator (ISO) are separate entities.
Pace simulated the market rules and tested the viability of a competitive multi-buyer power market on the islands of Java and Bali. Java and Bali are interconnected electrically and are collectively called Java-Bali.
The Java-Bali power system currently has just over 15,000 MW of formerly state-owned generating capacity and over 3,000 MW of IPP capacity in commercial operation. Additionally, the 1,300 MW Tanjung Jati B generating plant is expected to be on-line by 2004. By US standards this is a small system. On the other hand, Java-Bali's reserve margins are currently over 50%, high by US standards, but a small system generally requires a larger reserve margin as a percent of peak demand in order to maintain reliability.
Java-Bali encounters transmission congestion moving power from east to west into the heavily populated Jakarta region. Combined with high reserve margin requirements over the next several years, this transmission congestion creates an urgent need for new capacity additions as soon as 2003. Over the longer term, as Java-Bali's system grows, the necessary reserve margin falls in percentage terms, but with an expected 9 percent growth in demand, Java-Bali needs an additional 50,000 MW of capacity by 2020. Further, Java-Bali's shortage of gas resources dictates that a large portion of the required baseload additions may need to be coal-fired. Coal-fired capacity will likely have higher capital costs and longer lead times than gas-fired combined cycle generation, increasing the urgency of immediate development and the risks that developers must bear.
Exhibit 2 illustrates the declining reserve margin requirements in the Java-Bali power market as the system grows and planned upgrades relieve transmission congestion. The declining reserve margin is an estimate of the necessary reserves to maintain Java-Bali's reliability target of 1 day loss of load per year (compared to the US standard of 1 day loss of load in 10 years). Exhibit 3 illustrates the timing of necessary capacity additions that will provide the reserve margins shown in Exhibit 2.
Exhibit 4 shows Java-Bali's projected power prices for the period 2003 through 2020. These price projections are based on Pace's demand and cost assumptions under competitive conditions, and are higher than the average current subsidized Indonesian rate of 240 Rupiah/kWh. It is highly unlikely that residential consumers will be able to afford these competitive prices, so government subsidies would continue to be required.
Java-Bali's transmission problems and need for additional capacity in the short-term have led the Pace team to advise its Indonesian clients against full implementation of a multi-buyer competitive power market until transmission constraints are relieved, possibly by 2006. As of September 2001, Java-Bali does appear to be moving toward an interim single-buyer competitive market.
Conclusion
The potential for efficiencies and cost reductions of competitive power are material. However, seeking that potential is not risk-free. All of the key market elements must be structured to support competitive market operations, including those that support the introduction of new generating capacity when it is needed. This is more difficult in developing countries, so the risks of competitive power may be significantly higher.
The degree of risk that is borne by consumers and producers varies by the type of competitive market structure that is implemented. While competitive procurement of capacity resources under PPA structures limits risk, a competitive spot power market subjects prices to both the discipline and uncertainties of supply and demand, and the character of electric power means that prices can move very far very quickly. Competitive power markets must be designed to limit the risks inherent to the competitive structures that are implemented. For example, where a competitive spot market is present, it may be appropriate to facilitate the execution of bilateral contracts, including long-term contracts to promote capacity investments and price stability.
A benefit of a competitive spot market for electrical energy, such as Java-Bali's proposed multi-buyer market, is that price signals can reflect the short-term supply-demand balance and facilitate appropriate responses from market participants. However, competitive spot power prices become dysfunctional and potentially destructive to economic well being if new capacity cannot be brought to market when needed. Like California, Indonesia and other developing countries may benefit by requiring term commitments to support capacity investments, while enabling a spot market to correct temporary and seasonal supply-demand imbalances.
In developing countries, there are often significant barriers to entry for would-be power suppliers. The credit-worthiness of purchasers may be insufficient due to the inability of many of their customers, particularly residential consumers, to pay the full price for electric service. Power theft can be a serious problem in developing countries. The transmission and distribution infrastructure may not support new capacity. Limitations on fuel resources can inhibit power plant development. Finally, as has been charged in Indonesia, the legal and criminal justice systems may not be adequate to support transactions or resolve commercial disputes. These structural impediments to investment require as much focus as the market structure if market reform is to prove effective.
In conclusion, efficient and reliable power is a key requirement of sustained economic growth, and competitive power can facilitate economic growth in developing countries. Therefore, some form of competitive power is right for most developing countries, but it is critical that Indonesia and other developing economies find the correct market structures for their power sectors and eliminate non-economic barriers to entry if they are to successfully exploit competitive forces while avoiding the pitfalls.
Footnotes
1 Countries with capacity greater than 100 GW were excluded to prevent the policies of a small number of countries from biasing the analysis results. 81 countries were reviewed. Countries with power systems greater than 100 GW that were not included in the analysis are the United States, China, Russia, Germany, Canada, France, and India. Data source: Country Analysis Briefs; Energy Information Administration; June 1999 ? July 2001.
2 As referenced here, a spot power market is a centralized price clearing mechanism where physical electricity is priced hourly or less on the basis of supplier bids and market demand. In its June 18, 2001 order establishing ?price mitigation? in the western U.S. power grid, the Federal Energy Regulatory Commission defined spot sales as any power transaction, including bilateral trades, of less than 1 hour in duration.
3 Referenced capacity additions are in the East Central Area Reliability Coordination Agreement Region (?ECAR?) and Mid-America Interconnected Network (?MAIN?) regional councils of the North American Electric Reliability Council (?NERC?).
Exhibit 1 illustrates the restructuring activity that is taking place in countries with power systems smaller than 100 GW1. In its most basic form, restructuring may involve only the privatization of state-owned power systems where ownership is transferred from the public sector to private enterprise. Exhibit 1 illustrates the total capacity in systems that are in various stages of state-owned power privatization. According to US Energy Information Administration (EIA) data, only 28% of the capacity in power systems smaller than 100 GW resides in countries that have no stated plans for privatization.
With or without privatization of state-owned power companies, countries are increasingly allowing the participation of IPPs. Under various market structures, IPP participation ranges from building new capacity and selling the capacity and energy under a Power Purchase Agreement (PPA), to competing with other IPPs for energy sales in spot power markets2. Exhibit 1 illustrates that 65% of the installed capacity in countries smaller than 100 GW resides in countries that have IPP development opportunities.
In a more advanced stage of restructuring, governments may require the functional unbundling of the power system, requiring generation to be spun off or divested from transmission and distribution. This is usually done to facilitate wholesale or retail competition in the generation sector. Exhibit 1 shows that the majority of installed capacity in countries smaller than 100 GW is in countries that have either divested their generating capacity or plan to do so.
Competition is widely viewed as a means to introduce efficiency and reduce power prices over the long term. Competition can be implemented to varying degrees, and incremental increases in the level of competition may carry a higher level of risk to suppliers and consumers. Under the simplest form of competition, where prospective suppliers bid for the right to build capacity under a PPA, prices paid to generators are defined to some extent by contract. Risk is generally limited to the supplier's ability to economically procure the inputs to production (such as fuel) and physically deliver power, and the purchaser's ability to pay for the contracted power. However, once a competitive spot market is introduced, prices are driven by short-term supply and demand and can become extremely high and volatile to the potential detriment of both suppliers and consumers. The reason for this goes to the nature of electric power production and delivery.
The nature of competitive power
Among commodities, electric power is unique. The lack of large-scale storage and the absence of suitable short-term substitutes mean that electricity must be produced at the instant it is demanded. High outage costs, volatile and inelastic demand, and the need to instantaneously match supply and demand can result in highly volatile prices.
Spot market price volatility is driven by the very short-term relationship between available supply and non-price-responsive, constantly changing demand. When there is ample generating capacity, prices are usually close to short-run marginal costs (variable costs of the last plant dispatched). However, during high demand periods when the supply-demand balance tightens, suppliers are able to exercise limited market power and prices rise above short-run marginal costs, providing fixed cost recovery for necessary capacity additions. If there is an oversupply of generating capacity, prices may remain lower than what suppliers require to recover their fixed costs. On the other hand, when there is a shortage of generating capacity, spot prices may rise to very high levels.
High spot power prices can be an effective signal that capacity additions are urgently needed, providing incentives for developers to enter the market as quickly as possible. However, if non-economic barriers to entry prevent the introduction of new capacity, competitive prices may remain high. Persistent high prices may require that regulatory intervention substitute for a correction of the supply-demand imbalance that lead to high prices. However, regulatory intervention could aggravate the capacity shortage problem by reducing incentives for developers to bring new capacity to market and by increasing regulatory uncertainty and risk.
The relationship between prices and new generating capacity can be demonstrated by example. In the summers of 1998 and 1999, hot weather combined with capacity shortages resulted in short-term price spikes to over $4,000/MWh (compared to the typical $35/MWh) in the Midwestern US Since then, developers have announced upwards of 75,000 MW of additional capacity and it is likely that over 17,000 MW will have achieved commercial operation by the end of 20013. While not an instantaneous solution, it is clear that competitive price signals have given rise to an appropriate developer response.
On the other hand, in California, permitting requirements have stretched the time to bring a new plant into service to as much as 4 years compared to the typical 2 years for the rest of the country. The lack of new resources combined with atypical high weather-related demand and dry conditions that diminished the availability of hydropower created unmanageable, persistently high prices from May 2000 to May 2001. In June 2001, the Federal Energy Regulatory Commission was forced to put price caps (price mitigation) in place for the entire US western power grid to prevent further price increases and potential economic damage. While these price mitigation measures relieve the immediate problem of high power prices, they may distort the effectiveness of price signals and diminish the incentives for suppliers to bring the appropriate amount of generating capacity to market. Additionally, the resulting regulatory uncertainty may reduce investment in generating supply.
In summary, where electric energy is offered in a competitive spot market, prices reflect the supply-demand balance and provide important signals to would-be suppliers. However, new generating capacity must be brought to market quickly when needed, particularly given the inability of most consumers to reduce consumption when high prices signal that available generating capacity is in short supply.
Indonesia
Until the 1997 Asian monetary crisis, Indonesia was experiencing brisk economic and electricity demand growth. Under Suharto's regime, which ended in 1998, 27 Independent Power Producer contracts were executed. However, when Indonesia suffered a serious devaluation of its currency in 1997, power demand growth slowed and it became clear that the national utility, Perusahaan Listrik Negara (PLN), could not afford the terms of many of these PPAs, priced in US dollars at an average $60/MWh. Work to renegotiate these contracts is ongoing, but the situation has damaged Indonesia's credibility with international developers.
In September 1999, the Asian Development Bank provided a technical assistance loan to PLN to restructure its power sector and design a competitive electricity market. The objective of the restructuring initiative is to produce a financially viable and economically efficient marketplace that encourages private participation and protects the interests of end-users.
Among the mandates from the Asian Development Bank, Indonesia must initiate operation of a multi-buyer power market on the islands of Java and Bali by 2003. In this multi-buyer market, competitive suppliers (generators) would compete to sell power into a power market where multiple buyers bid for energy from multiple suppliers. A spot clearing mechanism and system operator combined into a System and Market Operator (SMO) would be required to support such a structure. Pace and its partners on the project (KEMA Consulting, Professor Frank Wolak of Stanford University, PT Connusa Energindo, and Institute Teknologi Bandung) proposed this model as it is simpler to administer than the model being implemented by most US competitive systems where the market clearing mechanism (for example, the PX in California) and system operator (ISO) are separate entities.
Pace simulated the market rules and tested the viability of a competitive multi-buyer power market on the islands of Java and Bali. Java and Bali are interconnected electrically and are collectively called Java-Bali.
The Java-Bali power system currently has just over 15,000 MW of formerly state-owned generating capacity and over 3,000 MW of IPP capacity in commercial operation. Additionally, the 1,300 MW Tanjung Jati B generating plant is expected to be on-line by 2004. By US standards this is a small system. On the other hand, Java-Bali's reserve margins are currently over 50%, high by US standards, but a small system generally requires a larger reserve margin as a percent of peak demand in order to maintain reliability.
Java-Bali encounters transmission congestion moving power from east to west into the heavily populated Jakarta region. Combined with high reserve margin requirements over the next several years, this transmission congestion creates an urgent need for new capacity additions as soon as 2003. Over the longer term, as Java-Bali's system grows, the necessary reserve margin falls in percentage terms, but with an expected 9 percent growth in demand, Java-Bali needs an additional 50,000 MW of capacity by 2020. Further, Java-Bali's shortage of gas resources dictates that a large portion of the required baseload additions may need to be coal-fired. Coal-fired capacity will likely have higher capital costs and longer lead times than gas-fired combined cycle generation, increasing the urgency of immediate development and the risks that developers must bear.
Exhibit 2 illustrates the declining reserve margin requirements in the Java-Bali power market as the system grows and planned upgrades relieve transmission congestion. The declining reserve margin is an estimate of the necessary reserves to maintain Java-Bali's reliability target of 1 day loss of load per year (compared to the US standard of 1 day loss of load in 10 years). Exhibit 3 illustrates the timing of necessary capacity additions that will provide the reserve margins shown in Exhibit 2.
Exhibit 4 shows Java-Bali's projected power prices for the period 2003 through 2020. These price projections are based on Pace's demand and cost assumptions under competitive conditions, and are higher than the average current subsidized Indonesian rate of 240 Rupiah/kWh. It is highly unlikely that residential consumers will be able to afford these competitive prices, so government subsidies would continue to be required.
Java-Bali's transmission problems and need for additional capacity in the short-term have led the Pace team to advise its Indonesian clients against full implementation of a multi-buyer competitive power market until transmission constraints are relieved, possibly by 2006. As of September 2001, Java-Bali does appear to be moving toward an interim single-buyer competitive market.
Conclusion
The potential for efficiencies and cost reductions of competitive power are material. However, seeking that potential is not risk-free. All of the key market elements must be structured to support competitive market operations, including those that support the introduction of new generating capacity when it is needed. This is more difficult in developing countries, so the risks of competitive power may be significantly higher.
The degree of risk that is borne by consumers and producers varies by the type of competitive market structure that is implemented. While competitive procurement of capacity resources under PPA structures limits risk, a competitive spot power market subjects prices to both the discipline and uncertainties of supply and demand, and the character of electric power means that prices can move very far very quickly. Competitive power markets must be designed to limit the risks inherent to the competitive structures that are implemented. For example, where a competitive spot market is present, it may be appropriate to facilitate the execution of bilateral contracts, including long-term contracts to promote capacity investments and price stability.
A benefit of a competitive spot market for electrical energy, such as Java-Bali's proposed multi-buyer market, is that price signals can reflect the short-term supply-demand balance and facilitate appropriate responses from market participants. However, competitive spot power prices become dysfunctional and potentially destructive to economic well being if new capacity cannot be brought to market when needed. Like California, Indonesia and other developing countries may benefit by requiring term commitments to support capacity investments, while enabling a spot market to correct temporary and seasonal supply-demand imbalances.
In developing countries, there are often significant barriers to entry for would-be power suppliers. The credit-worthiness of purchasers may be insufficient due to the inability of many of their customers, particularly residential consumers, to pay the full price for electric service. Power theft can be a serious problem in developing countries. The transmission and distribution infrastructure may not support new capacity. Limitations on fuel resources can inhibit power plant development. Finally, as has been charged in Indonesia, the legal and criminal justice systems may not be adequate to support transactions or resolve commercial disputes. These structural impediments to investment require as much focus as the market structure if market reform is to prove effective.
In conclusion, efficient and reliable power is a key requirement of sustained economic growth, and competitive power can facilitate economic growth in developing countries. Therefore, some form of competitive power is right for most developing countries, but it is critical that Indonesia and other developing economies find the correct market structures for their power sectors and eliminate non-economic barriers to entry if they are to successfully exploit competitive forces while avoiding the pitfalls.
Footnotes
1 Countries with capacity greater than 100 GW were excluded to prevent the policies of a small number of countries from biasing the analysis results. 81 countries were reviewed. Countries with power systems greater than 100 GW that were not included in the analysis are the United States, China, Russia, Germany, Canada, France, and India. Data source: Country Analysis Briefs; Energy Information Administration; June 1999 ? July 2001.
2 As referenced here, a spot power market is a centralized price clearing mechanism where physical electricity is priced hourly or less on the basis of supplier bids and market demand. In its June 18, 2001 order establishing ?price mitigation? in the western U.S. power grid, the Federal Energy Regulatory Commission defined spot sales as any power transaction, including bilateral trades, of less than 1 hour in duration.
3 Referenced capacity additions are in the East Central Area Reliability Coordination Agreement Region (?ECAR?) and Mid-America Interconnected Network (?MAIN?) regional councils of the North American Electric Reliability Council (?NERC?).
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