After decades of structural immobility in the electricity sector, during the past twenty five years governments around the world have been allowing market forces to play an increasing role in generation and supply. When well designed and implemented in proper sequence, a combination of institutional reforms—privatization, vertical and horizontal unbundling, and effective regulation—can lead to significant improvements in several dimensions of operating performance and in a variety of country settings. However, there are lingering concerns about investment in transmission and generation capacity in liberalized electricity markets.
*Lead Economist, Development Research Group, The World Bank
The findings, interpretations, and conclusions are the author’s own and should not be attributed to the World Bank, its Executive Board of Directors, or any of its member states. Financial support from the Knowledge for Change Program (KCP) of the World Bank is gratefully acknowledged.
The past two-and-a-half decades have seen a dramatic change in views about how the electricity supply industry should be owned, organized, and regulated. Since 1982, when Chile commenced a radical program of restructuring and privatization, a large number (more than half) of advanced industrial and developing countries have introduced a combination of institutional reforms in their electricity sectors. These reform programs have included privatization, vertical and horizontal unbundling, and the introduction of performance-based regulatory mechanisms implemented by independent regulatory agencies.(1)
Pressure for change in mature industrial economies grew with the emergence of excess capacity and the disillusionment with expensive and capital-intensive generation projects precipitated by the oil crisis of the 1970s. The circumstances in developing countries differed in important respects. Most of these countries had very high rates of demand growth for electricity, at least in periods when their economies were expanding. Whereas investment needs were low in advanced industrial countries with excess capacity, they were high in many developing countries. Most of the latter were faced with a tight demand/supply balance and periodic blackouts. Market clearing prices in such cases are politically difficult and could derail any attempts at radical liberalization. While the performance of electric utilities in advanced industrial countries was tolerable, in the developing countries these entities suffered from low labor productivity, chronic revenue inadequacy, deteriorating fixed facilities and equipment, poor service quality, and serious problems of theft and nonpayment. Finally, advanced industrial economies had developed commercial law and institutions to the point that private ownership of natural monopolies could be regulated in the interests of consumers while protecting the ability of the owners to finance investment. In contrast, when the electricity reforms were introduced, developing and transition economies had few precedents to guide the design of regulatory mechanisms. Thus developing effective regulation has proven one of the most challenging aspects of the restructuring process in developing countries.(2)
The standard reform model
A new paradigm has emerged for the organizational restructuring of the electricity industry. The reform steps have included some of the following:(3)
Corporatization and commercialization to transform state-owned utilities into separate (from the ministry/government) legal entities and restore financial discipline.
Enactment of requisite legislation to provide a legal mandate for restructuring and creation of (independent) regulatory agencieswith adequate information, capacity, and statutory authority.
Vertical and horizontal restructuring to separate potentially competitive generation and retail activities from the natural monopoly segments of transmission and distribution and thus facilitate competitive entry and mitigate market power.
Establishment of regulatory rules to promote efficient access to the transmission network and provide signals for the efficient location of generation facilities.
Privatization to restore financial discipline, provide incentives for cost efficiency and insulate the operating entities from damaging political interference.
Independent Power Producers (IPPs) to facilitate investment in generation even in the absence of comprehensive sectoral reform.
Designation of an independent system operator to direct the safe, reliable and economic operation of the interconnected electric system, determine the order of dispatch, and make arrangements for the expansion and enhancement of the transmission system.
Unbundling of retail tariffs to separate prices for competitive retail supply activities from the regulated network (transmission and distribution) charges.
Creation of markets and trading arrangements for voluntary energy and ancillary services.
Assessing the international experience with electricity market reform
The standard textbook architecture of restructuring notwithstanding, electricity reform in developing and transition countries has been an incomplete, uneven and irregular process that entails a complex set of interactions between the state and the market. Reforms have progressed furthest in most European countries, US, Canada, Australia, and parts of Latin America. They have been slow and unstable in Eastern Europe and Asia and highly problematic in Africa. In fact, no African country and very few developing countries outside Latin America have adopted the standard reform model in its full form. Moreover, IPPs were second only to corporatization as the step most frequently undertaken.(4)
The emerging international evidence suggests that: the standard reform model, if implemented correctly, is a sound guide for successful electricity market restructuring; significant departures from the textbook reform model are likely to lead to performance problems. This evidence on the impacts of electricity reforms is based on a variety of cross-country econometric analyses, firm- level efficiency and productivity assessments, and single-country case studies.(3,5)
Cross-country econometric studies
There is a limited literature that focuses on cross-country econometric estimation of the impacts of electricity reforms on a set of defined performance measures. Cross-country econometric assessment is complicated by challenging model specification issues due to the multi-faceted nature of the institutional reforms that have been implemented and the diverse characteristics of electricity sectors across countries. Such assessment has also been hindered by severe data and measurement problems.
These difficulties notwithstanding, it is possible to identify a set of empirical regularities on the impacts of electricity reforms:
Efficiency gains (improved labor productivity, higher capacity utilization, and lower system losses) from privatization reforms are modest, unstable and contingent on regulatory efficacy, especially in the absence of competition—efficiency may be more contingent on the form of regulation than on ownership.(6) Private sector participation is beneficial only when coupled with the existence of an independent regulator. Independent regulation without privatization (in effect regulation of state-owned utilities), on the other hand, seems to be ineffective.(7)
In contrast to the weak statistical robustness of privatization and regulation effects, there is strong evidence that the introduction of competition leads to significant improvements in performance.(7)
A portion of the efficiency gains may be passed on to consumers, with prices falling for some classes of electricity users. However, liberalization reforms do not always lead to lower retail electricity prices. In many developing countries, regulated prices were inefficiently low. In those countries, liberalization should lead to higher prices and better incentives.(8)
Liberalization reforms have reduced the historic pricing distortions in the electricity sectors of developing countries—cross-subsidies from industrial customers to households have been gradually reduced as prices for the latter are realigned with underlined costs.(2)
Country case studies
It is generally agreed that the Latin American region is where the standard reform model has been most influential and far-reaching. Most, if not all, the reforming countries in the Latin America and Caribbean region implemented performance-based regulation (PBR) for setting multi-year tariffs and monitoring compliance with service quality standards by distribution companies. This mechanism was very effective in Argentina, Chile, El Salvador, and Peru and is in large part responsible for the improvements in the operating efficiency of the region’s electricity systems.
Although Chile is often identified as the country where the first electricity reforms started, its post-reform market involved less restructuring, less competition and more regulation. Still, privatization, incentive regulation, entry by incumbent suppliers in response to administratively determined generation prices, and regulatorily-imposed service obligations on distribution companies have all contributed to large efficiency improvements (Table 1).(3)
Argentina followed most of the features of the standard reform model—it sought to aggressively reduce horizontal market power and developed one of the world’s most competitive wholesale electricity markets. Increasing competition led to a substantial decline in the spot price of electricity while at the same time investments in generation and network expansion increased rapidly—until the economic crisis in 2002 (Figure 1).(9) Service expansion also accelerated in Peru after reforms were introduced.
Figure 1 Argentina: evolution of installed capacity
Source: Pollitt (2008).(9)
Colombia was the first country in Latin America to implement a bidding system for its pool electricity market. The high-powered incentives created by the competitive electricity market had significant positive effects on power distribution efficiency. As the market was liberalized, $6 billion in foreign investment took place and some 2.5 GW of additional gas-fired capacity was built, enticed in large part by the capacity charge mechanism that was put in place.(10)
The reforms in Brazil were much more cautious and gradual than the Chilean and Argentinean cases. They were characterized by mixed ownership, feeble vertical restructuring, and market competition in some areas. More importantly, in contrast to the sequencing prescribed by the standard reform model, the privatization of distribution in 1995 took place before the establishment of an independent regulatory body and without a comprehensive reform blueprint. The distribution and supply companies exhibited significant labor productivity increases after privatization (Figure 2).(11) However, the reform program was overwhelmed by the drought and long-duration water shortages that followed. The drought problems were exacerbated because of the incomplete implementation of the reforms. The experience of Brazil raises serious doubts about the efficacy of private ownership of generation in countries with large-scale multi-use dams that require coordinated regulation.(1)
The incentive-based, multi-year regulatory regime (whose performance targets include an allowance on system losses) seems to have provided the right incentives to the regulated companies to improve their operating efficiency in India’s electricity system which has been plagued with significant technical and especially non-technical losses (Table 1).(12)
Source: Mota (2003).(11)
Limits of the standard template for reform—emergence of hybrid power markets
The full implementation of the standard reform model—especially the establishment of effective regulation, vertical and/or horizontal unbundling, and the introduction of wholesale and retail competition—has several commitment-to-reform, scale-of-the-industry, legal, financial infrastructure, and other institutional pre-requisites that are not present in most developing countries. Thus in recent years, increasing doubts have been expressed about the applicability of the standard template to the unique circumstances of many of these countries—especially in Africa. A new hybrid model has emerged with IPPs playing an important role alongside the state-owned electric utilities.(4)
IPPs have been an important source of new investment in many developing countries. In parts of Sub-Saharan Africa, their introduction has led to a major increase in generating capacity. Moreover, many of these IPPs have exhibited superior technical performance relative to the state-owned utilities. However, the success of IPP schemes is contingent upon a coherent policy framework that pays explicit attention to planning, procurement, and contracting issues. There is greater potential for successful outcomes, both for investors and the host countries, when effective regulatory governance (characterized by coherence, independence, accountability, transparency, predictability, and capacity) is put in place, preferably before the IPPs are negotiated. An effective regulatory oversight can lead to reduction in specific capital costs (capital costs per unit of installed IPP capacity) as well as to improved operating efficiencies.(13) The importance of credible regulatory and political commitment for the viability of IPP investments is highlighted by India's experience. A substantial variation in regulatory systems and political commitment across the different states has led to an enormous variation in outcomes—ranging from the disastrous Dabhol Power Project in Maharashtra to the modestly successful GVK project in Andhra Pradesh and Paguthan project in Gujarat.(14)
Persisting problems of cost recovery
Under-investment, in large part driven by under-pricing, was one of the most important causes for the secular deterioration in the performance of the electricity industries in developing countries prior to the reform era. The challenge of cost recovery has been widespread—across a variety of countries and regions. Underpricing and revenue inadequacy has been pervasive in Africa. While two-thirds of the continent’s power utilities set tariffs that cover their operating expenditures, only one-fifth of them charge prices that are sufficiently high to cover their full capital costs. (15) Cost-coverage ratios in the electricity sector have also been low in many parts of Asia and in the Central and Eastern European countries.
Another notable characteristic of past public policies in the electricity sectors of developing and transition countries is that they have led to prices with systematic elements of cross-subsidization—from industrial customers to households. The publicly articulated rationale for these policies is that they foster desirable social goals (e.g. helping certain classes of customers who would otherwise be disadvantaged). In practice, however, a substantial portion of the benefits frequently flowed to those outside of the intended ambit of the subsidy program.
As expected, electricity reform—especially its privatization component—generated pressures for revenue adequacy which in turn required realignment of prices with underlying costs. Moreover, market liberalization undermined the sustainability of cross-subsidies. During the post-reform era, the historic policies of under-pricing and cross-subsidies in the electricity sector have been gradually reversed in many countries around the world (Figure 3a, 3b).
In recent years, concerns have been expressed about the distributional consequences of electricity privatization and market liberalization--especially their impacts on basic service provision to poor households and other disadvantaged groups. Empirical evidence increasingly shows that these concerns have been largely misplaced. It is true that the reforms led to price increases in countries where such prices were inefficiently low. Moreover, the reforms did have adverse distributive impacts because of the large layoffs in the privatized utilities. Still, the negative effects of layoffs and higher prices were more than offset by increased access for poor consumers, enhanced service quality, and changes in public finances that benefitted poor people more.(17)
Transmission expansion planning has become much more complex in unbundled electricity markets. In such markets, the coordinating planning that enabled the integrated utilities to adjust generation and transmission capacities and internalize their interdependencies has been replaced by a series of decentralized decisions partly based on prices. This new decision structure involves many independent agents and entails a mixture of regulation and market signals. There is an ongoing debate about the ability of liberalized markets to fund the optimal amount of transmission investment. One of the drawbacks of unbundled electricity systems is that frequently no member of the industry has the needed combination of incentives and ability for system-wide planning.(18)
Even greater concerns have been expressed about the ability of competitively restructured electricity markets to provide appropriate incentives for socially optimal investment in new generating capacity—its timing, location, and choice of technology.(3) In deregulated, competitive electricity markets, it is power-company investors and not ratepayers who must bear the bulk of the financial risk of new generating capacity. In such a market environment, investors will naturally tend to favor less capital-intensive and shorter construction lead-time investments (e.g. CCGT). However, there is no empirical evidence to justify the expressed concerns about insufficient investment in generation capacity under liberalized markets.
Distributed generation with renewable energy: a paradigm shift?
The centralized electricity supply model with its underlying countrywide network has traditionally offered important economies of scale and, by and large, high reliability. However, given its historic focus on fossil fuels, it has also led to environmental degradation and in the case of developing countries it has ignored the energy needs of rural areas and the poor.(19)
In recent years there has been a resurgence of interest in distributed generation (DG)—i.e. energy produced on or very near the site of use from relatively small (typically less than 30 MW) and modular generating units. In several developing and transition countries DG is already accounting for a significant share of total electricity generated. Classic forms of DG include combined heat and power (CHP), industrial gas turbines, and small petroleum generators. More recently, the definition has expanded to include renewable technologies—solar, wind power, small hydro, biomass, landfill gas to energy, and waste to energy.
Renewable DG technologies are especially well-suited for off-grid remote applications in rural areas where consumption is low and the distance to the nearest distribution center is high. Most of these off-grid opportunities for distributed generation are in Africa, Asia, and certain parts of Latin America. DG can be effectively deployed to protect households and industries against the risk of costly voltage fluctuations and power outages, especially in developing countries where these power swings can be very extreme. However, problems of intermittency persist for wind and solar and their costs can still be significantly higher relative to traditional fossil-fired generation.
Summary of lessons learned and emerging challenges
There is an emerging consensus, supported by increasing empirical evidence, that in the electricity sector:
When well designed and implemented in proper sequence, a combination of institutional reforms—vertical and horizontal restructuring, privatization, and effective regulation (particularly the application of incentive-based regulatory mechanisms)—can lead to significant improvements in several dimensions of operating performance and in a variety of country settings.
There is a strong the link between good and credible regulation and the objective of securing FDI, and privately financed investment more generally, while delivering efficient service at sustainable but just and reasonable prices.
As a consequence of the reforms, retail prices have become more closely aligned with underlying costs, and cross-subsidies have been reduced and in some countries eliminated.
There is a logical sequence of reforms, and it is costly to undertake reforms in the wrong order—ideally, the reforming country should first raise prices to cost-recovering levels (with a return on capital to finance investment), then create regulatory institutions and restructure the sector, and only after that privatize.
Many if not most developing and transition economies lack some of the institutional and other pre-conditions for the full and effective implementation of the standard reform model. In many parts of the world, electricity markets have evolved or are evolving into hybrid forms—not completely unbundled, privatized, or competitive.
Pricing reform continues to be one of the most important and challenging tasks facing policymakers in the electricity sectors of developing and transition economies. The historic policies of under-pricing and cross-subsidies are being reversed but only very gradually. In many countries, efforts to rebalance tariffs have been encountering considerable public opposition on social equity grounds. There is an urgent need to identify electricity pricing schemes that strike a more satisfactory balance between economic efficiency and social equity.
The world is facing an enormous energy challenge in expanding the availability of adequate, reliable, clean, and competitively priced supply of energy, especially in developing countries. In meeting this development challenge, however, the world is faced with another major dilemma: the need to lower the threat of climate change disruption by lowering emissions of carbon dioxide and other greenhouse gas emissions (GHGs). The latter will require a major transformation of the global energy system and sourcing a significant portion of electricity generation from renewables.
There is widespread agreement that liberalized, unbundled electricity markets are poorly designed to encourage large-scale investment in, and deployment of, renewable and other low-C generating technologies. The transition to a renewable energy will give rise to new regulatory and market design issues. It will also generate important financing challenges because of the cost characteristics of these technologies (the bulk of their costs are accounted by up-front fixed investments). The role of the multilateral institutions could be considerably enhanced in this context—especially in identifying ways to strengthen existing electricity market arrangements and in designing innovative financing mechanisms. Further work is required to analyze the efficacy of alternative structural options and support mechanisms, remedy the drawbacks of the current market design, identify practical demand-side reforms, and evaluate GHG mitigation models.
Table 1 Country case studies of electricity sector reform
Privatization without vertical or horizontal unbundling. Wholesale competition. Market has been liberalized.
Labor productivity (GWh/employee):
Chilectra 1.4 in 1987 – 13.8 in 2002
Endesa 6.3 in 1991 – 34.3 in 2002
Energy losses (total):
22% in 1982 – 5% in 2009
Wait time for repair service:
5 hours in1988 – 2 hours in 1994
2.7 GW in 1982 –6.7 GW in 2002
Length of transmission network:
4310 Km in 1982 – 8555 Km in 2002
Fischer et al (2003)(20); Nagayama (2007)(8).
Privatization with full-scale vertical and horizontal restructuring.
20% in 1992 – 10% in 2002
Non-availability (thermal plants):
50% in 1992 – 20% in 2002
13.2 GW in 1992 – 22.8 GW in 2002
20% in 1992 – 10% in 2002
Spot price of electricity ($/MWh):
50 in 1992 – 20 in 2002
Rudnick and Solezzi (2001)(21); Fischer et al (2003)(20); Pollitt (2008).(9)
Partial privatization, vertical and horizontal unbundling. Single buyer model.
415 in 1993 – 1210 in 2007
48% in 1992 – 80% in 2007
22% in 1993 – 8.2% in 2007
Perez-Reyes (2009)(22); Anaya (2010).(23)
Privatization with unbundling.
Bid-based pool market.
Interruption time (hours):
6.3 in 1997 – 2 in 2002
Pombo and Taborda (2006).(10)
Privatization focused on distribution while generation remained largely state-owned.
Gradual transition to competition in generation and supply.
Labor productivity (MWh/employee) of distribution/supply increased by 147% between 1994 and 2000.
Unbundling and privatization of some State Electricity Boards.
APSEB 38% in 1999 – 20% in 2008
DVB 53% in 2002 – 15% in 2009
Bhatia and Gulati (2004).(12)
Introduction of IPPs with some unbundling and limited progress in establishing independent regulatory mechanisms. The incumbent state-owned utility has remained dominant.
Approximately 4 GW of IPP capacity has been added since the early 1990s.
IPPs have generally exhibited superior technical performance relative to the region’s state-owned incumbent utilities.
Kenya: KenGEN average availability factor 60% versus 95% average for the IPPs.
Gratwick and Eberhard (2008)(4); Eberhard and Gratwick (2011).(13)
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