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July 2003 - March 2004 IndexElectricity Reforms in India - A detailed study
AMOL PHADKE,SUDHIR
CHELLA RAJAN It has become commonplace to begin articles or speeches on electricity sector restructuring by commenting on how privatisation has become a worldwide ‘trend.’ In large part, this is because it is indeed a truly remarkable development, being perhaps the most profound, widespread and rapid shift in financial, political and ideological terms that the energy sector has ever witnessed. But one of the reasons why many in India make that obligatory comment is to convey the sense that the nation shouldn’t be left behind while the rest of the world is galloping full steam ahead towards prosperity. We believe, however, that in this instance India may already be ahead of the curve and could escape serious adverse consequences if it exercises caution while considering the state-level adoption and implementation of new legislation for the electricity sector. For more than three quarters of a century electricity was widely and uncontroversially regarded as a regulated public good that had to be delivered to customers by vertically integrated entities. These were mostly publicly owned, the US being an important exception whose investor-owned (and vertically integrated) utilities were nevertheless closely monitored by regulatory agencies for service quality and rates. But in the course of a decade or so after economists began to claim that electricity generation doesn’t have to be a natural monopoly, private operators in over 40 countries have gained control of perhaps a trillion or so dollars worth of electricity assets (including generation and transmission) through new construction or purchases from public utilities.1 The general driver for this transfer has been stated as ‘efficiency,’ the logic being that private sector involvement and competition would lead to better resource allocation and eventually improved services for end-users of electricity services. In developed countries, where access is generally not a major concern, the main selling point for restructuring has been greater consumer choice and better pricing.2 In developing countries and countries in transition the argument of the so-called ‘Washington consensus’ was that only privatisation would raise capital for power sector investments, reduce political interference, address the problems concerning non-performing public investments and public sector corruption, establish more efficient pricing (including the reduction of socially based subsidies) and, again, reap efficiency gains (i e, reduce losses and theft, improve performance and streamline operations) to enhance economic development.3 Reform efforts in the developed world mainly involve establishing a competitive electricity market by deregulating the private sector with an intended shift from a regulated private or public monopoly to a competitive wholesale or retail electricity market. In developing countries, though the reform efforts are currently focused on privatisation of the publicly owned sector and establishment of an independent regulator, they also envision market competition in the sector in the longer run. Privatisation efforts are thus at least partly justified on the basis of future potential gains from competition. Almost identical reform models of unbundling and privatisation are being implemented in all developing countries with formulaic procedures passed around to countries in diverse circumstances. Apart from being ’political’ in the narrow sense of having local party and interest-group origins, the reforms are undoubtedly influenced by multilateral development agencies, international consultants, power producers, financiers, lawyers, traders, and so on. In our opinion, there is insufficient analysis of and debate over the theoretical underpinnings and the actual outcome of power sector reforms. Crucial lessons could be learnt by comparing experiences of electricity reforms in different parts of the world but unfortunately such assessments are rare. Oddly, therefore, while the justification of the reform agenda is often led by the notion that ‘everybody else is already on the boat,’ the actual details of how other countries fared is hardly ever the subject of debate once local players have bought into the idea. As Gregory Nowell (1994:5) reminds us, in the context of restructuring in the oil sector: Everywhere transnational structuring occurs, it looks like a local (national) political event. Multinational corporate interests usually enlist local national elites, such as bankers, to represent their case. They pursue their local objectives without needing to make any statements about the larger picture, except perhaps on rare occasions. Reporters write up the story from the local, national perspective, and historians writing about [regulation or deregulation] in Romania will seldom bother to look at what happened in the United States. India has not been immune to the worldwide changes in the power sector. In fact, around the time that the sector was first opened to private participation in generation, the World Bank chose India as the test case for its ‘model’ of power sector restructuring [Dubash and Rajan 2001]. The reforms were conducted in response to significant crises in technical and financial performance and capital availability, and to a lesser degree, to continuing problems of access and the environment. In the present circumstance of the Electricity Bill 2001 having just been passed in arliament, and while there is still a narrow window of opportunity before national legislation is cast in stone and state governments ponder adoption of reforms within their own jurisdictions, it is especially important to review closely the experiences of other countries to see where the reforms have in fact led to, relative to their stated objectives. The main features of EB2001 include: – Generation free from licensing except for hydro units (no need for techno economic approval) – Captive generation free from control – Licensing for transmission and distribution and trading – Open access to transmission – – State-level regulatory commissions (RCs) – – Retail tariff to be determined by RCs – Open access in distribution to be allowed by RCs in phases Except for the increased role for RCs in retail rate setting, which has positive institutional impacts by providing independent regulatory authority in the sector, there are issues of concern in several of the other provisions. But rather than identify the specific features of the legislation that are problematic, we examine a broader set of issues relating to liberalisation of electricity, primarily unbundling (separation of the utility into generation, transmission and distribution entities), privatisation and the creation of market structures that have characterised reforms in other countries. In this paper we analyse these efforts and their outcomes in developed as well as developing countries, with special reference to the Indian context.
II Our central argument is that the success of reforms in India will depend critically upon the existence of some sort of restraining or disciplining mechanism in the sector, in the absence of which current efforts will likely result in a transition from inefficient public ownership to profit-gouging monopolies or oligarchies. In principle, such a mechanism could be strong, independent and effective regulatory oversight over public or private monopolies or significant competition among a large number of public and private entities. But it is important to examine without bias, and as thoroughly as possible, the feasibility and effectiveness of both these sector-disciplining mechanisms before making any claims regarding the desirability of privatisation. We also argue that issues related to protecting the environment, extending access to the poor and other off-grid populations and strategic concerns related to import dependence and foreign private ownership need to be addressed up-front in order for the reforms to be in the broader public interest. Since the reform efforts in developing countries generally see as their ultimate goal the institution of some sort of market structure involving unbundled and privatised entities, we look at the experience of deregulation and transitioning to a competitive electricity industry in the developed world. The main questions we are trying to address in the next section (Section III) are: Are the many experiences of electricity market failures in the developed world anomalous or is competition inherently difficult to achieve in the electricity sector? If competition is hard to achieve even in developed countries, what are the prospects of ever achieving robust electricity markets in developing countries? In the absence of competition, one has to rely on strong, independent and effective regulation to bring down prices and costs. We look at the feasibility of such regulatory oversight in the Indian context in Section IV. We look at the experience of regulation of the private electricity industry in the US and its relevance in the Indian context. We also examine the past experience of regulation in the Indian electricity sector and make the case that in the absence of either effective competition or regulation, whatever benefits privatisation has to offer may never reach the common people. At this point, it is also noteworthy to make the distinction between reforms in generation and distribution.4 In India, there is general agreement that the sector’s key problems are in distribution and that priority should be given to reforms here, including privatisation. There are two key elements of such reforms: one concerns tariff rationalisation (removing cross subsidy and introducing marginal cost pricing); the other relates to improving performance by reducing theft and technical losses and improving power quality. If an independent regulator were to set retail prices, tariff rationalisation would not require privatisation. The comparative advantage of private over public ownership with an independent regulator for reducing theft and technical losses needs to be analysed carefully. We discuss various benefits and risks of distribution privatisation in Section V. Power sector reforms need to address the challenge of extending access to the rural poor who are still deprived of this vital developmental input. Various strategic issues related to import dependence and foreign private ownership of the electricity sector also need to be addressed comprehensively. We take up these in the context of power sector reforms in Section VI. We conclude that focusing primarily on privatisation might not lead to desirable outcomes and that we must rethink objectives and goals in the context of sustainable development. Based on our understanding of the root causes of the current problem, we suggest some guiding principles around which reforms should be structured.
III Markets with Unbundling and Deregulation? In this section we look at the empirical evidence on the successes and failures of international efforts to instil effective competition in the sector through deregulation, provide possible theoretical explanations of these outcomes and discuss the applicability and relevance of these results in the Indian context. Economic Efficiency Losses Due to Market Power In developed countries, the fully restructured model involves vertical disintegration and deregulation. In its most general form, the model calls for unbundling of the electricity utility into generation, transmission and distribution entities, privatisation of generation and/or distribution, and open access to the transmission grid, with pricing and dispatch determined through a variety of means. The model places quite a complex burden on the system, since a number of structural changes are expected to be in place for its implementation: restructuring implies dividing physical and financial assets among new companies; open access requires real-time coordination of generators with transmission and distribution companies; trading arrangements and/or a system operator are needed to manage transactions; the transmission business needs to be regulated to the extent that it remains a natural monopoly; supply side barriers to entry need to be removed; reasonable reserve margins need to be maintained for system integrity; long-term grid expansion requires incentives for long-term expansion of the grid; and so on [Hunt 2002]. There are various points at which bottlenecks could appear in the restructured system, and the experience of the last several years has shown that private players have every incentive to exploit – if not actively seek to create – them. The worst possible impacts of this model were witnessed in California where unbridled market power, in this case the unilateral and collusive actions of players to raise prices well above competitive levels, led to the complete collapse of the market. But Australia, the UK, New Zealand, among others, have also seen major problems of market power, leading to substantial price increases at or close to peak demand periods. There are a few cases where market power has been less of a burden on the functioning of the system (e g, PJM market in the US, Chile) but it is not clear that the outcomes are necessarily better than what were or could have been achieved under the regulated structure.5 The fact that much of this has been glossed over by the repeated claim that California’s experience was an aberration because of ‘botched design’ only makes the problem even more scandalous; after all, California’s plan was intended to protect retail consumers in the reasonable belief that there would be a transition period with significant price volatility, which would have been politically unacceptable. The size of the California market (around 50 Gigawatts of peak demand) simply exposed the rapacious greed of traders and generators in that state, after virtually all controls on their behaviour had been removed at the state and federal level. This is not a surprise, private firms are profit maximising and as a leading energy economist, Frank Wolak, says, “All privately-owned firms in all markets continually attempt to exercise all available unilateral market power” [Wolak 2002]. Hence, what the Federal Electricity Regulatory Commission has termed an ‘epidemic’ scale of manipulation of electricity and natural-gas markets for billions of dollars by Enron, Reliant and another dozen or so companies, was opportunistic only in the sense that these companies exploited what the trading system as a whole offered; the fact that retail customers failed to see significant price changes merely maintained a certain degree of political stability in the near term [Price 2001, Lynch 2002, CA-ISO 2002, FERC 2003]. Interestingly, the one instance where there is no evidence of market power in a restructured market-based electricity industry is Norway, most likely due to extremely low ownership concentration in generation, and the fact that much of the generation is in the hands of public entities [Hjalmarsson 2000]. In fact, even after deregulation, the electricity supply industry in Denmark, Finland and Norway is almost entirely under public (and therefore domestic) ownership. Obviously, this is a model that merits considerable attention in the reform debate. Theoretical Explanation of Market Power The non-competitive behaviour observed in many of the above cases is neither anomalous nor simply due to bad market design. The fundamental nature of the electricity sector makes competition quite hard to achieve and there is a clear theoretical explanation for the widespread failure of electricity markets. First, and perhaps most important, unlike many other commodities, electricity is very costly to store and needs to be produced at precisely the same instant it is required. Second, it is transmitted through a complex and interconnected network with highly variable capacity with bottlenecks that can shift around. Third, the long lead times to build capacity necessitate certain periods of overcapitalisation in order to match growth in demand. Conversely, power plants have short-term capacity constraints (i e, the ability to increase supply when plant capacity is reached is very limited) and transmission constraints further hinder the flexibility in supply of electricity. Fourth, demand is itself generally very inelastic in the short run.6 Together, these factors greatly increase the potential for exercising market power. Analysis by reputed economists using economic simulation models that considered these peculiar factors of electricity markets had predicted the California crisis as early as 1996 [Borenstein 1996]. In fact, established research on this subject has shown that competition in an electricity market perhaps requires a combination of extensive divestiture, significant reserve margins and real time demand response, an arrangement that is quite hard to achieve in practice. Only blind faith in deregulation seems to have prevented such analyses from having any impact on policy-making as California and other states went ahead with restructuring plans. Are Cases of the Market Failures Due to Improper Market Design Rules? Can They Be Corrected Simply by Modifying These Rules? Bad market design is repeatedly cited as the explanation for the widespread failures of electricity markets. Market design includes policies relating to bidding and auction rules (pay-as-bid vs uniform price), the degree to which long-term contracts and risk hedging are allowed, and so on. There is, however, no consensus about the influence of these market rules on the competitiveness of the electricity market. The uniform price auction (a type of auction where every player in the market gets the same market price for his or her generation irrespective of what s/he bid in the market) adopted in the California market is considered one of the important causes of the crisis there. It has been suggested that a pay-as-bid auction (where every generator in the market gets what the s/he bid in the market) would have significantly mitigated the effect of market power. There is no theoretical or empirical evidence supporting this claim. In a typical pay-as-bid auction, the bidders do not tender their marginal costs but generally bid their expected market-clearing price; hence its results would really be no different from a uniform price auction. Consider how either type of auction would actually work in an electricity market. Imagine a situation where there are 10 firms able to provide 100 MW each and demand varies from 500 to 850 MW, which would maintain a reserve margin of about 15 per cent. While in other markets this alone would fulfil the conditions of robust competition, in the case of electricity this translates into a situation of repeatable games with vast potential for strategic bidding. For instance, if all the bidders were to place their half-hour day-ahead bids competitively, they would almost be certain that one or more of them will never be dispatched. Consider a situation where one or more bidders decide to place his or her plant(s) in maintenance. Immediately, the price of electricity for a number of hours close to peak would increase significantly, and the system operator would have to scramble to import additional electricity for that period. In a uniform price bid auction, all the suppliers during that period would receive the price offered to the last bidder being dispatched (in California, this often turned out to be one or two orders of magnitude higher than the bid price of baseload dispatchers). In a pay-as-bid auction, the assumption is that there would be less incentive for all generators to bid strategically, since the rewards wouldn’t be as great. But it is important to remember that even here, while the last few bidders are king, every dispatcher has an interest in a high market clearing price during the hours expected to be peaky, and would bid accordingly during that period. If one or more large firms dominated the market, they would of course have an even greater incentive for exerting market power. It is also averred that long-term contracts and a futures market would mitigate the effect of market power. However, repeated interaction through a futures market could either increase or decrease prices.7 Besides, studies that suggest that contracting would reduce the impact of market power assume sufficient players in the market, and incentives for market entry, both of which could be problematic [Andersson and Bergman 1995, Green 1996, 2000]. In general long-term contracts might reduce price volatility but not reduce prices themselves. It seems important, therefore, to be sceptical of the argument that the many cases of failure in restructured electricity markets are anomalous or that they are due to inappropriate design, and that both could be addressed simply through better market design and market operation rules. Feasibility of Market Power Mitigating Measures One of the most important measures for instilling effective competition is considered to be extensive divestiture (creating a large number of players in the electricity market) and increasing the demand elasticity by real-time demand response achieved through real time pricing. Additional divestiture would not, however, inevitably increase competition; there is no guarantee that the new set of players would bid at marginal cost if they could increase their profits through strategic bidding. Indeed, the mere presence of a large number of market participants may not be sufficient to reduce the risk of market power (unilateral or collusive). Often, despite the high level of excess capacity in the systems, there could be a number of large players in a position to adopt non-competitive bidding [e g, Brennan and Melanie 1998]. Moreover, if participants did not have an opportunity to engage in strategic gaming, it seems likely that they would have a relatively small incentive to make the investment in capacity and sizeable reserve margins. The steep supply curve of electricity, the relative inelasticity of demand, and the substantial lead times to set up most types of power plants are simply too much of a hindrance to elicit serious investment interest to maintain sizeable reserve margins. In general, therefore, private players would find it difficult to make investments in a highly competitive market that has huge fixed costs and requires capacity additions. This is also true for the expansion of transmission capacity, whose financing depends even more complicatedly on congestion revenues [see, for instance, Deb et al 2000]. Accepting that it is difficult to expect sufficient investment in electricity generation and transmission under a system where the players bid in their marginal cost and receive the market clearing price, the argument has been made that they should be allowed to collect ‘scarcity rents’ and charge for ancillary services (including selling insurance against loss of load and pricing reserve margins). But it is by no means clear why, if the market is already suboptimal in this way, policy-makers should go through these various hoops in order to satisfy the need for new investment. Instead, a regulated market using cost-of-service pricing methodology for a vertically integrated utility would be at least be openly ‘second-best’, with far fewer opportunities for market power and gaming [see Stoft 2002, Rosen 2002b]. Another problem with highly dispersed ownership is that generators can no longer exploit economies of scale and scope in operating power plants. In general, compared with multiply situated and owned facilities, large vertically-integrated utilities can expect to take greater advantage of the gains of specialisation (which increases with size) and need to invest less per employee in training and systems management [Lee 1995]. They could also benefit from joint use of production facilities and other inputs, marketing and administration relating to both upstream (generation) and downstream (distribution) activities. The argument for unbundling was based on the premise that these economies of scale and scope are far weaker now than before, because of developments in power and communications technologies, but there is little evidence of these being reflected in prices. Anecdotal evidence from utility employees suggests that numerous problems of poor coordination have resulted in California and elsewhere where utilities underwent radical disintegration both vertically and horizontally.8 What about the demand side? Real time demand response achieved through real time pricing (RTP) could certainly help to make markets competitive, but the feasibility of RTP on a large scale has not been adequately assessed even in developed countries. Further, given the state and costs of metering technology, RTP looks viable only for large industrial and commercial consumers and not for small residential consumers, which limits the demand response that could be achieved. It may be the case that even with RTP demand would be sufficiently inelastic to make markets non-competitive. For instance, the bulk of industrial consumers have constant loads that would be difficult, if not impossible, to turn off during peak demand periods without causing serious impairment to plant operations. One could, of course, expect time-of-day metering to provide a psychological influence on residential and commercial demand over the medium to long term, and cause people to switch towards more efficient lighting, for instance (typically, lighting is the single most important cause of daily ‘peakiness’ in demand). Nevertheless, given the significant costs of installing real-time metering in households and small businesses, it is unlikely that they would truly experience the ‘true’ price-signals, even without bundled pricing. Industrial consumers, even though they make up a smaller fraction of peak demand, will likely be more responsive in the short term, wherever process changes are feasible, but even then only in those sub-sectors where energy costs make up a significant part of their overall turnover. Hence, although RTP is considered as one of the most important measures for increasing competitiveness of the electricity markets, it is not clear how successful it would be in achieving this objective. To sum up, competition in power markets is difficult to realise for a variety of reasons, as described succinctly by Robert Wilson: In the long run, imperfect competition in power markets stems from the same factors as in other industries, such as economies of scale and other entry barriers, and oligopolistic ownership. Competition is imperfect in intermediate time frames because production is capital intensive and construction delays are long compared to variations in supply and demand conditions. On short time scales, prices are inherently volatile and competition is often imperfect because of technical rigidities on the supply side, and inelastic demand [Wilson 2002:1301]. Implications for Developing Countries In developing countries it would be even more difficult to instil competition and mitigate the exercise of market power. Factors like the small size of markets with large centralised power plants, a tight demand-supply situation with low reserve margins, and virtually no real time demand response mechanisms in place will increase the potential to exercise market power in the generation sector substantially in a developing country market. Analysis of the competitiveness of markets is generally based on the Herfindal-Hirschman Index (HHI). HHI measures the concentration of firms in the market. In simple terms, it measures how big the firms are relative to the market. But while this index is widely used as a measure of competitiveness of various other markets, it is misleading to use it for electricity markets [Rudkevich et al 1998, Borenstein Bushnell et al 1999]. Concentration indices miss key aspects of the electricity supply industry that enhance the ability of firms to exercise market power (i e, high cost storage, need for matching supply and demand in real time, the cost of grid failure if they are not matched, transmission congestion). Despite its ineffectiveness as a measure for electricity markets, analysis of potential competitiveness of the electricity sector continues to be based on the HHI, particularly in developing countries [e g, World Bank analysis, Besant Jones and Bacon 2002, of the competitiveness of the electricity sector in various countries]. In the twenty countries considered in the World Bank’s analysis, California has the second lowest HHI. Thus, based simply on this analysis, one would expect California to have the most competitive electricity market among twenty countries! The feasibility of the two most important instruments to mitigate market power, namely, divestiture leading to large number of players in the market and real time demand response, needs to be well thought-out in a developing country context. The inherent nature of electricity markets requires extensive divestiture compared to other markets to make them competitive. There are physical, economical, and political constraints on extent of divestiture. Physical limits play a role because one cannot effectively divest below the level of a single generation plant. For example, preliminary market simulations of a potential electricity market in the Maharashtra state indicate that markets would be substantially non-competitive even under the scenario of extensive divestiture (where every plant is assumed to be owned by a separate company). These simulations were undertaken using models that considered the physical nature of electricity markets as well as strategic behaviour of profit maximising private firms.9 In the case of Maharashtra, the 2000 MW Chandrapur coal plant limits the extent of physical divestiture and the existence of this large plant is sufficient to make the Maharashtra electricity market highly non-competitive during the peak periods. One could argue that it is possible to have different companies owning different units of the plant but one might also reasonably contend that there is a high probability of collusion among such companies due to physical proximity and shared facilities and that firms owning different units would find it in their best interest to behave as a single plant. There could also be a minimum economic scale of operation for electricity firms, which could be larger than that required for the markets to be competitive. The political feasibility of extensive divestiture leading to a large number of players in the market is also questionable. Experience till date has shown that reforms have facilitated the growth of mega multinational companies. For example, Enresis, a Chilean company, is the supplier to 55 per cent of the Chilean, 22 per cent of the Colombian, 19 per cent of the Argentine, 24 per cent of the Peruvian, and 5 per cent of the Brazilian populations [Wamukonaya 2002]. Most of the private participation in developing countries has been carried out by a handful of these multinational companies. Reforms have brought some major international players into Latin America, resulting in a reduction in the total number of players in the market [Wamukonaya 2002]. Indeed, the experience so far of divestiture is not encouraging, to expect that the Indian electricity sector will have sufficient players to meet the needs of a competitive market is a tall order. The other most important measure for instilling competition is real time demand response where the consumers adjust their demand in response to RTP. In the case of India, where 30 per cent of delivered electricity is not metered, RTP on a wider scale will be no less than a fantasy. RTP programmes for large industrial customers may be possible but the ability of the Indian industry to respond to real time prices is also an open question. Other programmes such as time-of-use pricing are useful in peak load shifting but do not affect the elasticity of demand, which would be required to mitigate the effect of market power. One could imagine schemes such as interruptible tariffs where consumers are offered lower rates on the agreement that their supply would be cut off when prices go above a certain level. The practicality and effect of such options on demand elasticity have yet to be determined. Long-Term Viability of Unbundling
In Orissa and Chile the extent of vertical re-integration is startling [Dubash and Rajan 2001, Zolezzi 2001, cf de Sol 2002]. The ironic trend in the UK, the developed country with the longest experience in restructuring, is that it is headed for a significant degree of vertical re-integration, as distribution companies are repurchasing generation assets. Similarly, in the US, investor-owned electric utilities are merging in record numbers. Investments in the power sector are made within the climate of many uncertain factors such as future electricity demand, hydro-electric power availability and the investment choices of other private firms. Vertically integrated franchise monopolies are an attractive and simple way of dealing with these price risks [Delmas and Tokat 2003]. It is conceptually possible to think of contracts that will replace this structure. But in many ways, contracts are a form of vertical integration and the important questions are: Is it possible to have effective vertical disintegration given the risk associated with uncertainty and lumpy investments in the sector? Would the sector be competitive in the presence of significant vertical integration of some form or the other? These issues have been largely ignored within the current reform paradigms. Indeed, it has become a mantra to claim that unbundling (separating generation from transmission and distribution) will pave the way for competition. But unbundling means dividing physical and financial assets among completely new entities, which could lead to a loss of what economists call positive network externalities in potentially imperfect markets.10 In other words, all the benefits of organisational coordination relating to issues like maintenance schedules and fuel procurement, ‘demand side’ management all through supply chain and firm-level planning would be lost. As the California experience shows us, strategic maintenance scheduling can help firms increase their potential to game the market. This not only results in increased prices but a loss of economic efficiency because maintenance is undertaken at the same time that the system most needs the capacity.11 In short, having effective competition in a developing electricity sector looks hard even in the longer run. Undertaking privatisation in anticipation of future efficiency gains and lower prices due to effective competition is certainly erroneous.
IV Notwithstanding all the arguments we have made above about the slim chances of achieving it in the power sector, it is certainly reasonable to assume that the key driver for efficiency improvement under private ownership is competition. After all, it would make little sense to insist on private ownership if there is no likelihood of competition. But in the absence of competition in the electricity sector, the only other available disciplining mechanism is effective regulation. We examine the experience of regulation in the US and the prospects for regulation to act effectively in developing countries. Experience of Electricity Regulation in the US The US electricity industry is composed of investor owned utilities, rural cooperatives, municipal utilities, federal government managed utilities, and IPPs. Apart from a few states that have undergone a significant degree of deregulation, the bulk of the industry remains regulated, as it has been for about three-quarters of a century, by independent state-level public utility commissions (http://www.naruc.org/resources/state.shtml).The outcomes of regulation of the US electricity industry have been mixed. In some states, operations and investments were quite efficient while in the others (especially in California) consumers paid a high price for inefficient investments by the regulated private sector. In many cases, high prices were the result of cost recovery from stranded investments tied to nuclear power. It is important to mention that integrated resource planning and demand side management under regulation in many cases also resulted in enhanced energy efficiency. Pro-deregulation advocates like to claim that such interventions are economically inefficient because they are top down; typically, government or a regulator would decide what levels of energy efficiency improvement are feasible and would accordingly set targets. But this is misleading not only because social and environmental costs would likely not be borne by the market in the absence of specific policy measures. Also, the comparative advantage of a regulated private firm over a public entity is not clear from the US electricity experience. Kwoka (1997) reviews important studies comparing regulated public and private ownership in the US electricity industry till date and shows that while most indicate that prices are lower under public ownership than private ownership there is no significant difference between the costs of public and private ownership. This may be a reflection of the higher expected and awarded rates of return for private entities. Theoretical Explanation Inefficient investments under regulation and the failure of the private ownership to achieve lower costs are partly explained by regulatory failure, i e, the inability of the regulator to observe the costs of a firm realistically and force them down [Joskow, 1989 for a detailed analysis of such regulatory failures]. The fact that regulation can impede effective competition, one of the primary drivers for efficiency improvement in the private sector, also explains inefficiencies in private sector regulation. Still, while it is believed that public firms are generally inefficient, under regulation they may have comparatively less incentive to gold plate (make unnecessary investments), evade real costs, and gouge profits compared to a profit maximising private firm. As shown by the US experience, under regulation, a public firm may not necessarily be more undesirable than a private firm. Implications in a Developing Country Context The success of effective regulation depends, among many other factors, upon the independence of regulatory commissions, regulatory capacity within the regulatory body and effective public participation in and oversight of the regulatory process. The US electricity sector has a history of nearly three quarters of a century of regulatory development and extensive public participation through well organised and capable civil society organisations (e g, advocacy groups such as the Consumer Federation of America, http://www.consumerfed.org/). Despite all this, the outcomes of this model of regulated private electric utilities are equivocal. In terms of regulatory capacity and effective public participation, most developing countries, including India, are a stark contrast with the US. Effective representation and protection of the consumers’ interests will depend critically upon consumer awareness and capabilities (analytical, financial, advocacy, etc), which are generally absent in developing countries, where the resources at the disposal of the regulatory commissions are also quite limited. It could be argued that these processes will develop slowly, but the relevant question to ask is whether they will develop sufficiently to match the lobbying and analytical power of a private firm given the socio-economic context in these countries. This is not to say that efforts in this direction are misguided, on the contrary we emphasise the need to expand all available means to represent and protect the public interest in electricity regulatory forums. Indeed, the development of regulatory and public participation capacity needs to be at the forefront of reforms and constitute a necessary (although not sufficient) condition for privatisation. The experience to date of IPP scandals all across Asia (e g, India, Indonesia, Pakistan, Philippines) has shown that at least the first wave of power sector reforms, namely that of issuing power purchase contracts to investors to increase capacity, was a costly proposition, rife with instances of rent-seeking if not outright fraud. For instance, analysis by Prayas has shown that the average capital cost of the IPP gas based projects in developing countries (gas-based projects also constituted more than 70 per cent of the total number of projects proposed by IPPs in India) is about 30 per cent higher than that of similar power projects in North America [Prayas 2002: Table 1].
In fact, if the low cost of labour available in developing countries were factored in, the cost inflation (in shadow price terms) would be even higher. The conventional explanation is that costs are higher because of high risk premiums due to the poor credit rating of electric utilities in developing countries. However, the rate of return on the capital costs (which is as high as 30 to 35 per cent) is a part of the long-term power purchase contract, and includes the risk premium; hence the capital costs should not reflect the effect of risks. In any case, power purchase contracts are typically designed such that developers bear almost none of the risks relating to fuel price, supply and payment default and face relatively low political risk, which is also ultimately covered by the option of international arbitration. Even the difference in the construction time and transportation costs can explain only a small portion of this difference and must conclude that the rest is simply cost-padding. Indeed, there is fairly clear evidence that existing regulatory institutions have failed to assess the private sector costs and bring their prices down to competitive levels [e g, Tongia and Banerjee 1998]. Perhaps the recently established independent regulatory commissions in India and elsewhere could play this role of ensuring fair and efficient investments more effectively than a public authority (e g, state governments, Central Electricity Authority) that is more prone to state capture. But one needs to be judicious in evaluating this role for regulatory commissions and consider the level and types of civil society capabilities that are required to match the lobbying and analytical resources of private companies. In the absence of such regulatory and civil society capacity, it is hard to see that why the IPP experience of costly investments will not be repeated under large-scale privatisation, where it is unlikely that competition will be an adequate disciplining mechanism. It is sometimes argued that the regulated private sector is in any case just an intermediate step in the reform process, that competition must be phased in slowly as the sector improves and that ultimately markets would reach a mature stage of full competition [see for example, Besant-Jones and Bacon 2002]. There are two serious pitfalls to this logic. First, as we have seen, the term ‘competitive electricity market’ is turning out to be an oxymoron; such entities are not quite in existence even in developed countries. Also it is not clear that characteristics of smaller geographic markets will go away as the ‘sector is developed.’ Higher transmission costs for better market integration only to prevent the exercise of market power and facilitate competition might not be justified even in a developed market (in other words the extra cost of market integration might not be justified to mitigate market power). It is claimed that as the sector improves reserve margins would automatically be augmented, which would increase the feasibility of competition. The percentage of reserve margin depends upon the economic value of reliability as well as the opportunity cost of energy, which in turn depend on the overall economic development of a country. There is therefore absolutely no guarantee that reserve margins would ever reach desirable levels. Overall, the conclusion that competition will be feasible when the sector is “fully developed” is quite unconvincing and seems to be based purely on ideology rather than theoretical or empirical evidence. Second if privatisation were to take place without setting a stage for competition, the private sector players enjoying significant regulatory or monopoly rents will have little incentive to see through the subsequent steps towards competition [WRI 2002]. Hence this progression from a private regulated oligopoly to a deregulated competitive market might never materialise or can be delayed substantially. In short, reform efforts face a serious predicament: there are significant doubts about the feasibility of competition in the electricity sector in a developing country context, yet it is almost certain that the private sector will not bring down costs and prices in the absence of significant competition or regulation in the sector. At the same time, the regulatory system in developing countries has limited ability to force the private sector to be efficient and control its profits.
V In India, one of the major drivers of reforms has been on the basis that the distribution sector is incurring enormous losses because of subsidy and rampant theft. This argument indeed holds merit and serious efforts are needed to address both. The solutions advocated are to privatise the distribution network and to undertake tariff reforms to reduce the cross-subsidy. Is Privatisation Always the Best Solution? Privatisation may address some of the problems in the distribution sector but there are also potentially serious hazards on that course. First, it entails unbundling or at least separate contracting of the ‘wires business,’ which may or may not be feasible depending upon the degree of system integration in the utility. Second, and perhaps most important, is the need to ensure against cherry picking where only commercially viable regions get privatised and the state gets loaded with losses to serve commercially non-viable areas, which would continue to suffer from low quality power. There have certainly been examples where power quality and performance in the distribution sector improved because of privatisation [Besant Jones and Bacon 2002]; but there are also grim instances like Orissa where privatisation of the distribution sector has failed badly. Indeed, in places as diverse as Colombia, El Salvador and Orissa, the second wave of reforms involving unbundling and sale of distribution assets was no better in its record than the IPP experience. They are best characterised in this statement, among several others, in the Kanungo Committee report on power sector reform in Orissa: “Billing and collection efficiency under the privatised distribution companies (DISTCOs) far from improving, actually worsened and rampant theft of electricity continued unabated.”12 In contrast to this, the Maharashtra State Electricity Board was relatively successful in curbing theft under the regulatory oversight of the state’s Regulatory Commission. This suggests that one ought to be sceptical of claim that ownership change would somehow improve the performance of the distribution sector, when so much hinges on prevailing governance and incentive mechanisms. Role and Objectives of Tariff Reforms There are two main issues surrounding the issue of subsidy and tariff reforms: economic efficiency and financial viability. Removing subsidies would improve economic efficiency, as electricity would now be priced at its average marginal cost; it would also improve financial viability of the electricity sector by reducing wasteful consumption and the ensuing high financial losses. Price signals are not, however, the only determinant of efficiency improvements. For example, farmers using diesel pump sets effectively pay marginal costs but still use very inefficient pump sets [TERI 1994] This example, among many others, indicates that there are several other barriers than subsidies that need to be overcome to improve energy and economic efficiency. Hence the role of price signals needs to be analysed carefully before undertaking tariff reforms for economic efficiency reasons. At any rate for price signals to improve economic efficiency, all other inputs also need to be priced at marginal cost. If water and fertilisers continue to be subsidised, pricing electricity at marginal cost might not necessarily improve economic efficiency. Such intra-sector dynamics need to be considered for assessing the role of price signals [Reddy 2000]. Electricity is an important input for development and has many intangible benefits and in many cases extending subsidy is necessary for accelerating economic development. At the same time the poor design of subsidies or their blanket elimination, coupled with elaborate administrative procedures for monitoring and enforcement, could actually cause wastage of scarce public funds. Careful analysis of the need and appropriate targeting of subsidy should be a central part of the discussion on distribution reforms.
VI Privatisation as a Way to Bring in Investment in the Sector Capacity shortages and lack of adequate investments are considered to be among the most important challenges faced by the energy sector in developing countries and privatisation is advocated to facilitate the necessary investments in the energy sector. Cost and Efficiency of Investments In the context of such scarcity in capacity, the focus tends generally to be on the size of investments and not on their cost and efficiency. For a financially sustainable power sector, it is important that the investments be low cost and efficient. As discussed earlier, private sector investment in the generation sector through the IPP route has turned out to be costlier than necessary because of a combination of factors like higher risk premium, higher expected profits and rents, and regulatory failure (negotiated cost padding). Also in a lot of cases, these investments were inefficient [Phadke 2001]; for example, when the Maharashtra State system needed an intermediate-load plant, a long-term contract that effectively mandated base-load operation was signed with Enron’s Dabhol power project [Prayas 1996]. High cost and inefficient investments produce three major detrimental effects. First, the resulting high cost of energy, a major input for production, can significantly harm developing economies in an era of increasing global competition. Second, because of the limited paying capacity of some consumers, the government will inevitably take on a substantial part of the extra cost burden (through some type of transfer payment, if not direct subsidy), which will continue to drain its scarce resources. Third, they lead to higher tariffs and increase the probability of default, which further increases the risk premium of the private sector, producing a vicious cycle. Financial Independence and Adequacy of the Private Sector Investments The private sector has not been as financially independent as expected and has required government as a guarantor thereby placing the public sector at relatively higher risks. Over one third of the IPP projects in developing countries were financed by IFC and many of which involved government guarantees. In cases like Senegal, where the private sector has not performed as expected, the government has had to buy back shares at higher prices than it had originally sold them [Wamukonaya 2002]. Also, since the crises of the late 1990s and early 2000s, the private sector itself has lost a great deal of capital and can no longer be expected to be a saviour, in the unlikely event that it sees itself as one. For instance, Table 1 shows how the major energy suppliers and traders have lost much of their capital base during the past year; thus, there is no longer even the cash available from what some of the largest private companies to infuse funds into the sector.13 If private investments are inherently expensive, or if they are not capable of catering to actual needs, one must look hard for alternative means to raise capital. Additional revenue generated by reducing the inefficiencies in current operations could be one of the sources of financing new investments. For example, in many state electricity boards in India, T and D losses worth at least 15 per cent of energy generated are accounted for by power theft (which is largely metering, billing and recovery problem). Eliminating this loss would lead to roughly 67,500 GWh in additional energy in the states. Theft appears to be higher among large industrial and commercial customers; hence it reasonable to assume that the losses could be recovered at about 3 Rs/kWh and would thereby generate an additional revenue of approximately Rs 20,000 crore every year. If we assume generation capacity to cost around Rs 4 cr/MW, one could pay for the cost of about 5,000 MW of new capacity very year! In comparison, IPPs have added about 8,000MW in new capacity in the past decade.
Access One cannot assume that the private sector will automatically extend access to electricity to the poor in developing countries who are largely deprived of this basic need. For instance, a recent UNDP/World Bank ESMAP study of reforms in Bolivia found that “the necessary expansion of the grid to connect the poor will not take place as a consequence of privatisation and restructuring” [ESMAP 2000]. Privatisation could in fact reduce access to electricity. In Argentina, Georgia, Kazakhstan, Moldova, and the Dominican Republic privatisation has meant at least a few instances where distribution companies shut off supply to the poorest neighbourhoods and emergency settlements in order to reduce losses [Bayliss 2001, WRI 2002]. Power sector reform should address the issue of access up front, but this has not been part of the discourse on reform in India or elsewhere [Dubash and Rajan 2001]. Import Dependence and Forex Risk – Strategic Dependence The IPP experience in India shows that over 70 per cent of the proposed power projects were based on imported liquefied natural gas (LNG) despite the fact that LNG power is much costlier than alternatives like coal [Phadke 2001]. In most cases, the contracts have been structured in such a way that foreign exchange risks are not borne by IPPs but are passed on to consumers. If this trend continues in generation privatisation (which is the case in many other countries where the reforms are at an advanced stage), consumers will inevitably face a substantial foreign exchange risk. Experience also shows that foreign investors dominate private sector investment in reformed markets. In the UK, for instance, there is growing alarm that over around 55 per cent of electricity generation is foreign owned, and largely by giant transnational corporations. Electricity is a key sector of strategic importance in any economy, but especially in developing countries any increased dependence on fuel imports and on transnational corporations to manage services needs to be viewed cautiously from the perspective of energy security and national sovereignty.
VII We have argued in this paper that it implausible to assume that developing countries will somehow work themselves through a transition from public ownership to private ownership with independent regulation and, ultimately, towards private ownership with competition, along an extended trajectory with efficiency and public services improving progressively. The success of reforms will depend decisively on the existence of effective sector-disciplining mechanisms in the form of regulation or competition or some combination of both. In the absence of such mechanisms, there is a serious danger that simply sticking to the endeavour on ideological grounds will quite likely lead us from inefficient public ownership towards rent-extracting private oligarchies, with painful costs along the way. We have also made the case that instilling effective competition is quite hard to achieve because of the inherent nature of the electricity sector and the many cases of market failure in the developed world best describe this challenge. Overcoming all these obstacles in a developing country like India will be even more difficult. It is important to note this fact because even though competition is generally an important driver of efficiency improvements, it is unlikely to be realised in the electricity sector, particularly in developing countries. Effective regulation of the private electricity is also a daunting challenge in a developing country context given the status of governance disparity in the resources available to common consumers and regulators on one hand, and to private electric utilities on the other. The global experience also suggests that claims regarding privatisation and deregulation need to be analysed rigorously and critically. It is hardly apparent that the current reform legislation will address these challenges, but it is certainly not too late to go back to the drawing board. It is beyond the scope of this paper to suggest an entirely different blueprint of electricity reforms for India (although we hope to produce a sequel with that motivation). Instead, we propose three equally important axes for defining such an agenda:
One of the most fundamental problems with the existing solutions is that they are based on a limited diagnosis of state failure, which is seen as having arisen narrowly from the financial and performance crisis of state-owned utilities. Thus, “getting the state out of the way” through privatisation is mooted as the answer, rather than finding ways to address the failure and to get the state sector operational for the long haul. As Prayas has pointed out, at the root of the financial and performance crisis in the state owned Indian power sector is a crisis of governance, principally, the subversion or absence of various transparency, accountability and public participation (TAP) mechanisms [Prayas 2002]. The inadequacy of governance also helps to explain the failure and the subsequent high cost of the early efforts of privatisation, namely the IPP experience. Hence the focus of reforms should be on improving governance in the sector by creating and enhancing various TAP mechanisms. In the absence of such mechanisms either the public or the private sector are likely to fail or underperform. At the core, outcomes in the energy sector are influenced by incentives faced by various actors in the sector. The task of setting incentives goes beyond just the ownership change; in the other words, ownership change is only a limited determinant of incentives. For example, private monopolists face very different incentives from private firms under competition, a regulated private firm would face very different incentives from a deregulated firm, and so on; there will be different outcomes in terms of costs and prices in each of these cases.
(2) The focus should be on
meeting energy service needs rather than on merely attracting investments for
centralised capacity additions. By the early 1990s, the US economy was consuming 30 per cent less energy than it would have consumed had it maintained the same efficiency level as the 1970s, and there is still substantial potential for further efficiency improvement [Schipper et al 1990, Holdren 1991, Thorne et al 2000]. Even more impressively, the cumulative impact of appliance efficiency standards alone that were set in the late 1980s and beyond were sufficient to offset 21GW of peak demand by 2000 [Geller et al 2001]. Such cost-saving approaches will be extremely beneficial especially in a capital scarce country like India and reforms ought to be centred on the question of how to mainstream them in utility planning.
(3) Reforms should address up
front the issues that are unlikely to be taken care of the private sector such
as access, strategic and import dependence, and other social and environmental
issues. Address for correspondence:
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