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INCORPORATING ENERGY CYCLE EXTERNALITY COSTS AND BENEFITS IN INDIA’S POWER SYSTEM PLANNING MECHANISMS

PREPARED BY STEPHEN POWELL1

APRIL 11, 2007

1 I should like to thank Mustafa Zakir Hussain, Ashish Khanna, Sunil Khosla, Peter Meier, Tapas Paul and Alan Townsend for helpful comments and suggestions on a first draft of the paper; and Professor Anil Markandya for his insights during the field trip in April 2006. I also acknowledge the many useful and illuminating discussions I had with representatives of the Government of India and other relevant authorities during that field trip. Errors and omissions remain my responsibility.

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TABLE OF CONTENTS

Executive Summary………………………………………………………………………………………...11 Introduction..............................................................................................................................4

1.1 Background.........................................................................................................................41.2 Scope of the Paper...............................................................................................................5

2 Conclusions of the Markandya Paper............................................................................................73 The Power Sector Planning Framework......................................................................................10

3.1 Industry Structure..............................................................................................................103.2 Electricity Act, 2003..........................................................................................................113.3 Current Generation Expansion Planning Process..................................................................12

3.3.1 Central Electricity Authority.......................................................................................123.3.2 State level planning....................................................................................................13

3.4 Procurement......................................................................................................................153.5 Summary and Conclusions.................................................................................................16

4 Internalisation of Environmental Externalities............................................................................174.1 Background.......................................................................................................................174.2 Changing Sector Structure..................................................................................................184.3 Options for the Internalisation of Environmental Externalities..............................................18

4.3.1 Inclusion of adders.....................................................................................................184.3.2 Tighter standards........................................................................................................204.3.3 Economic instruments................................................................................................21

5 Conclusions & Recommendations.............................................................................................31

Incorporating Externalities in India’s Power Sector Planning Mechanisms

Executive Summary


EXECUTIVE SUMMARYIntroduction

The power sector in India plays a fundamental role in the economic development process. The country faces formidable challenges in meeting its energy needs in an environmentally sustainable manner and at reasonable costs. The planning and operation of the sector has hitherto been conducted without due regard to the environmental consequences. As a result, additions to capacity in recent years have been sub-optimal. Moreover different types of capacity are treated differently. Hydropower is required directly to bear more of its external environmental costs than other sources. The recent Supreme Court ruling has reinforced this tendency. Looking forward, much of the large capacity additions required over the next few years are likely to be coal-fired, with concomitant effects on the country’s environment.

Against that background, the paper looks at India’s power generation planning process; whether and how it might adapt in the light of increased attention to environmental costs and benefits; and if there are other, better ways of internalizing environment externalities. It takes as its starting point the conclusions of the companion paper by Anil Markandya. These are that the external environmental costs of fossil fuel generation are as high or higher than estimates derived for developed countries; that estimates of the external costs of both fossil-fuelled and hydro for India should now be determined more precisely and used at the strategic level in planning, at the regulatory level in setting standards, in designing economic instruments and in plant siting decisions; and that the polluter pays principle, which currently applies in the case of hydro, should also be applied in other power sector developments.

Planning

Under the Electricity Act 2003, planning of the power sector as a whole is formally undertaken by the Central Electricity Authority. But it would be misleading to describe the planning done by the CEA as central planning. The CEA no longer has the ability to influence the choice and location of generation additions. It is at the State level that the real planning decisions about future additions to capacity now get made. The State Electricity Boards (or their unbundled successors) are the de facto single buyers of electricity. It falls to them to plan to acquire the necessary means to meet anticipated future growth in demand for electricity.

Generation and transmission expansion planning and procurement are currently based entirely on the financial costs of additions to capacity. No allowance is made for economic costs (i.e., including the external environmental costs). This is because only the actual project costs incurred by the SEBs can be recovered through the tariff.

Internalizing externalities

Internalizing an environmental externality refers to the process of incorporating environmental costs in the private decisions of producers and consumers, thereby offsetting the tendency to treat the environment as a “free good.” This can be done directly, effectively by raising the cost of the activity in question, e.g., by taxing the cause of the environmental externality or by setting higher standards. Or it can be achieved

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Executive Summary

indirectly, by ensuring that the environmental externality is acknowledged in the planning process, through the use of so-called ‘adders’, even if private costs remain unaffected.

The indirect method will work, but only for as long as planning has a role to play in effecting capacity additions and only if the regulatory commissions accept the resulting plan. As the single buyer structure disappears, using ‘adders’ in the planning process will have progressively less effect. Moreover, international experience of their use is not encouraging.

Of the direct methods, a tightening of emission standards would have the advantage of building on the existing approach to environmental regulation. It would also be the most direct way of internalizing environmental externalities, in the sense that tighter environmental standards would be directly reflected in higher capital or operating costs and would thus directly alter the relative costs of generation sources. And, if compliance was strictly enforced, it would result in lower emissions. On the other hand, the command and control approach is economically inefficient, since additional emission reductions that could economically be made are not made. And it creates free rider problems if enforcement is weak.

Direct methods which create financial incentives for emissions abatement by putting an explicit or implicit price on emissions, but which do not themselves dictate abatement decisions, are referred to as economic instruments. They work by changing the commercial incentives that generators face, thereby influencing their behavior. Those with low abatement costs have an incentive to emit less than those with higher abatement costs; and are continuously incentives to do so. This makes economic instruments more cost-effective than the traditional command and control approach. The main examples of economic instruments are the removal of subsidies; environmental taxes; emissions fees and tradable emission schemes.

The removal of subsidies on activities associated with environmentally harmful emissions has the same impact as an environmental tax, since it will raise the cost of inputs and outputs, just as an environmental tax would; and the removal of subsidies and cross-subsidies at the end-user price level would reduce demand, thereby indirectly reducing pollution. The Indian energy sector suffers from distorted pricing at several levels. Removing long-standing fuel subsidies elsewhere has done more by all accounts to improve environmental quality than any explicit environmental policy. The existing extent of subsidization and cross-subsidization in the Indian energy sector suggests that a similar step could have a significant impact.

The most common economic instrument is the environmental tax. There are generally three types: taxes on final products associated with a polluting activity (i.e., electricity); taxes on inputs into the polluting activity (i.e., oil, coal); and taxes on polluting substances contained in inputs (e.g., the carbon content of coal). Environmental taxes are less demanding of environmental regulators than instruments that rely on monitoring and compliance enforcement for their effectiveness; and they are easy to administrate. But they do not create incentives to abate emissions per se, only to limit purchases of an input or an output linked with harmful emissions. But this should not rule them out: for example, an environmental tax on the consumptive use of water by thermal generation in India would internalize the cost and provide operators with better incentives to manage their use of water.

Emission fees are fees paid by generators per unit of emissions of a particular pollutant (e.g., ash, CO 2, NOx etc.). Emission fees directly reduce emissions by creating incentives to reduce emissions; and they reduce emissions at lower aggregate costs than a command and control approach would do. But fees need to be set high enough to have an impact, which may be politically difficult to do. And they require some minimum level of credible monitoring and enforcement, which could require the installation of costly continuous monitoring systems.

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Executive Summary

Taxes (or fees) and tradable allowance schemes are, in principle, very similar. All rely on price signals and on financial incentives for generators to reduce the external costs they impose. The majority of countries using economic instruments for environmental policy purposes have hitherto relied more on taxes or fees than on tradable allowances. This may be because taxes are a more familiar tool than tradable allowances; and because a tradable allowance scheme imposes greater administrative costs than using the tax system. This is because participants must have confidence in the integrity of the monitoring, measuring and verification/certification systems put in place. These systems are required to ensure that the prices of permits in the market truly reflect the fundamental drivers of the price. Without confidence in those systems, the scheme will not work effectively, if at all.

Conclusions and recommendations

First, the environmental consequences of generation in India are best mitigated by pushing ahead with power sector reform. This will yield environmental benefits from raising end-user tariffs in real terms; reducing technical losses in the transmission and distribution systems; increasing the efficiency of state-owned thermal plants; reforming the structure of tariffs; restoring the financial health of the sector; and eliminating the health impacts of small diesel generators in highly populated urban areas by reducing shortages through adequate grid-based generation.

Second, ensuring that fuels are priced at their economic cost is another step that could be taken to ensuring that the environmental costs of generation are internalized.

Third, using externality adders in power sector planning at either the state or central level to reflect environmental externalities is unlikely to be either feasible or effective.

Fourth, tightening emission standards, both for existing plants and for new plants, is unlikely to have much effect. The priority must be to ensure compliance with the existing limits, before contemplating tighter ones.

Finally, of the economic instruments an environmental tax high enough to have an environmental impact is likely to be difficult for political reasons; emissions fees depend for their effectiveness on the institutional capability and political will to provide a minimum level of monitoring and enforcement, but are a viable option if those demands can be met; and an emissions trading scheme is unlikely to be feasible in the foreseeable future in India, where a lack of monitoring, enforcement, and administrative capabilities is a critical constraint

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Introduction


1 Introduction

1.1 Background

Environmental issues in the power sector are of major importance in India, where electricity plays a fundamental role in the economic development process. As the Planning Commission’s recent Draft Report of the Expert Committee on Integrated Energy Policy says, India faces formidable challenges in meeting its energy needs and providing adequate energy of desired quality in various forms to users in an environmentally sustainable manner and at reasonable costs.

According to that Report, India needs to sustain an 8% to 10% annual rate of economic growth to eradicate poverty and meet its economic and human development goals. To deliver that growth, India would need to see its power generation capacity increase by 2031-32 to almost 800GW (compared with installed capacity in mid-2006 of 125GW). The environmental consequences of this growth in generating capacity will be significant.

Yet in India, as in many developing countries, the planning and operation of the generation and transmission system has generally been conducted without due regard to the environmental consequences. The root causes of this include:

(i) the perpetual shortage of supply capacity, owing to a combination of factors, including low and distorted tariffs, leading to inadequate financial resources in the sector, resulting in the difficulty of acting against power stations not in compliance with central or state environmental regulations;

(ii) a distorted system of incentives which throws the burden of meeting electricity needs heavily onto supply from conventional coal-fired power stations;

(iii) the failure of power-system planning at the level of the states to incorporate the environmental effects of alternative policy options;

(iv) the failure of the environmental regulatory system, in which environmental impact assessments (EIAs) are more of a justification than a meaningful analysis and which fails to monitor or enforce compliance.

Heightened sensitivity about the environmental implications of power generation technology choices in India have resulted in additions to capacity in recent years have been sub-optimal, both in terms of the generation mix and of the total amount of capacity that has been commissioned.

Moreover, the cost structure for generation and transmission projects going forward may be influenced by the recent Supreme Court ruling that:

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Introduction

hydro-electric generation project developers should compensate the state for the diversion of forest land used to fund environmental protection, including regeneration of forest, the maintenance of ecological balance and eco-systems and forest conservation; and

that the level of compensation paid should reflect the net present value of the land diverted will influence.

The impact is relevant for large storage hydro projects, which are likely to be sited in protected areas and which could cause a large loss of forested land due to inundation, and which already face a 10% ‘tax’ imposed on hydro generation by many State Governments (in the form of the requirement on a hydro generating station to provide 10% of its output free to the State in which the project is based). Moreover, certain transmission projects, particularly those that would link hydro projects with market areas, could also see their cost structures change depending on the methodology for calculating the NPV of forests. This could result in unintended consequences, such as less hydro being developed and, as a consequence, an even greater reliance on coal-fired power plants to meet demand, though in current circumstances (i.e., high world oil and gas prices), hydro project costs would have to be significantly increased by these factors before they became uncompetitive with gas-fired combined cycle peaking plant.

While the immediate concern of the two papers is with the effects of the recent Supreme Court decision, a strong case can be made that now is also an appropriate time to focus on the whole issue of the environmental impact of power generation in India. The demand for power in India is growing at a significant rate. Much of the capacity additions required to meet increments in demand and to satisfy currently unmet demand is likely to be coal-fired. While India’s large reserves of coal are a major asset, excessive use of this form of energy production will cause the country’s air, land and water resources to deteriorate, threatening human health and property. Disposing of the ash that is produced will require large amounts of land and leaching ash can contaminate ground water. Finally, CO 2 released from the combustion of coal will contribute to global warming and climate change.

1.2 Scope of the Paper

Against that background, this paper looks at India’s power generation planning process and how it might adapt in the light of increased attention to environmental costs and benefits by policymakers. It has been prepared in accordance with the terms of reference, which are reproduced at Annex I.

According to the terms of reference, the key issues to be considered include:

whether and how to incorporate identified cost and benefit streams within individual energy projects (on the assumption that revenues to the project are sufficient to cover these costs, and that revenue streams from benefits are also established)

which costs and benefits to recognize outside the project structure (and if so, who absorbs the costs or gains the benefits), which costs and benefits to leave aside until some future date

how the existing generation expansion planning institutional framework should be adapted, including the potential for creating markets for specific externalities

bearing in mind the financial environment for investments in power generation and how this is affected by the weak financial conditions of many state-level distribution companies, whether generators can expect fair regulatory treatment for recovery of their costs; and the way in which

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Introduction

treatment of environmental externalities affects those costs and results in optimal levels of investment and mixes of technology

The paper is organized as follows:

Section 2 summarizes the findings and recommendations of the companion paper by Professor Anil Markandya.

Section 3 looks at the existing power sector planning framework and at how environmental externalities are currently taken into account in the generation and transmission expansion planning process.

Section 4 examines how, in the event that a decision is taken to put greater emphasis on internalizing the external environmental costs of generation and transmission might best be internalized, that might best be done, whether through the adaptation of the existing planning process, through tighter emissions standards or through economic instruments, such as emission fees, environmental taxes or emission allowance trading schemes.

Section 5 offers some conclusions and recommendations.

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Conclusions of the Markandya Paper

2 CONCLUSIONS OF THE MARKANDYA PAPER

The companion paper by Professor Anil Markandya reviews estimates of external costs of generation and transmission in India and other countries. It also discusses the use of external cost estimates in power system regulation in India and elsewhere and reviews the current arrangements for financial compensation in the case of hydropower power development in India.

The paper notes that estimates of the cost of negative externalities of generation from fossil fuel sources are now available for most developed countries as well as for a number of developing ones and that the state of knowledge in this area has improved significantly in the past ten years or so. Professor Markandya’s review of the work in this area shows that:

external costs of generation, particularly for coal-fired plant, are relatively high, reflecting its adverse impact on health;

external costs in US¢/kWh in developing countries are not much lower than in developed countries, and can be higher. This is partly the result of less efficient technologies and partly because of the greater populations affected by air emissions in the developing countries;

India does not have a comprehensive set of such external cost estimates but what recent information is available suggests that external costs can be high, in some cases higher than the direct costs of power generation and not dissimilar to cost estimates derived for developed countries;

while comparisons between the external costs of fossil fuel based generation in India and elsewhere are valid and instructive, the same does not hold for hydropower. In developed countries estimated values of such costs tend to be very low; partly because there are significant restrictions on any development that has negative environmental consequences and partly because some of the ecological costs have not been valued in monetary terms;

external cost estimates can be useful in power system regulation at various levels: in plant siting decisions, in determining specific standards and in undertaking strategic planning for the sector:

o at the plant level the use of such cost data is limited: it can provide some support to a risk assessment exercise but is not a major component of the decision-making process, which focuses on the environmental impact assessment that is required to be undertaken;

o at the regulatory level, however, external costs estimates feature significantly: in evaluating technological standards, emissions standards etc. for plants; in setting ambient air quality standards; and in designing economic instruments. In developed countries the application of external costs in this context has increased sharply over recent years where it is generally considered to have been useful in the regulatory process.

for hydropower projects in India the main external costs relate to loss of forest resources. The Supreme Court has mandated the payment by any hydro developer of an amount equal to the NPV of forest resources lost resulting from its development. This causes four problems:

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o the issue is both one of externality and of the principle that the ‘polluter should pay’ (PPP), which is a distributive principle and not one of efficiency.

o the NPV calculation needs to be adjusted to take account of the fact that ongoing payments are being made by hydro developers to compensate for loss of forest resources (including afforestation, environmental remediation etc.).

o the NPV amount to be paid by hydropower developers should be based on actual loss of services, which vary substantially from one site to another.

o hydropower projects also provide external benefits. While it would not be appropriate to introduce compensatory payment for these externalities in a manner analogous to the NPV payments for external costs, developers are justified in seeking to capture positive externalities wherever possible – e.g. where there provide irrigation benefits, recreational benefits etc.. In some respects, the issues arising from the sharing of such benefits are more serious for hydro developers than the environmental and NPV questions. There are many examples where hydro projects were scaled down, delayed, and even cancelled, because of interstate water disputes.

hydropower projects are controversial because of the resettlement and rehabilitation issue. This is a particularly sensitive issue in India, where developers and governments have been subject to large protests at a number of sites. Professor Markandya concludes that the principles on which compensation for loss of assets in India is based and the Government of India’s regulations for resettlement and rehabilitation are not out of line with those demanded by international bodies or those used in other countries in the region. The differences arise in the implementation of the programs. Income restoration schemes have often not delivered what was expected of them; there are frequent delays in making the compensation payments; and the provision of alternative assets for housing and employment generation are often late. In a number of cases the activities of relocation and resettlement have not been synchronized.

Professor Markandya recommends that:

estimates of the external costs of generation and transmission should be used in India both at the regulatory level - in evaluating technological standards, emissions standards etc. for plants, in setting ambient air quality standards; and in designing economic instruments – and at the strategic level, i.e., in the indicative planning done by the Central Electricity Authority and at the state level;

if this recommendation is accepted, the Government of India should then undertake a study to determine more precisely the external costs of fossil fuel based power generation;

the Government should also make better estimates of the techno-economic feasibility of compliance with new regulations. The lack of good sense of what power generators can actually implement, and in what time frame has been a major reason why regulations have not been successful in their implementation;

once data have been collected on external costs and compliance feasibility, the authorities should draw up appropriate plans for implementing a regulatory framework. The timing of the introduction of new measures will need to take account, among other factors, of the current

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shortage of power in India. It would not be desirable, for example, to close a polluting power station if it implies increases in even more polluting auto-generation;

to the extent that the polluter pays principle has validity, as implicit in the Supreme Court NPV decision, the principle should also be applied to fossil fuelled power sector sources;

the Government of India may want to reconsider the amount of the ongoing payments made by the hydropower sector to the forestry authorities for afforestation etc.;

to avoid the double counting that is inherent in the existing methodology for calculating the additional NPV payment, the NPV calculation needs to be adjusted to take account of the fact that ongoing payments are being made by hydro developers to compensate for loss of forest resources. These include afforestation, environmental remediation etc.

if NPV is to be paid it should be based on actual loss of services, which vary substantially from one site to another. A classification based on forest type and on detailed calculations of loss of services has been proposed by the Chopra Committee. This can form a sound basis for actual payments

a thorough assessment of both the full economic costs (i.e. including direct resource costs externalities) and full financial costs by fuel type for a range of representative plants would serve a useful purpose for Indian policy making in the power sector;

the problems associated with resettlement and rehabilitation urgently need to be addressed, by:

o ensuring capability in the institutions responsible for the plan (with external support where needed);

o carrying out adequate consultations with affected parties at the appropriate stages and allowing for the time lags in getting income restoration activities functioning;

o undertaking baseline and follow-up surveys to monitoring progress regularly and in a timely manner and react to findings which show that objectives are not being realized.

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The Power Sector Planning Framework

3 THE POWER SECTOR PLANNING FRAMEWORK

This section looks at:

the current generation and transmission expansion planning process and the roles of the various players (Planning Commission, Ministry of Power, Central Electricity Authority, the States, NTPC, NHPC etc.)

how expansion planning is done and how environmental factors are currently taken into account, both at the detailed costing level (e.g., what costs are explicitly included in candidate plant costs - e.g., reforestation charges) and at the higher strategic level (e.g. are constraints put on the modeling to ensure that a diversity of technologies, or a particular technology, is chosen);2

how the planned additions to generation and transmission capacity are effected, both by the centre and the state and the reasons for the differences between plan and outcome;

the extent to which non-economic factors (e.g., diversity and security of supply, environmental factors) impinge on the implementation plan.

3.1 Industry Structure

To put the question of planning into context, it is worth looking briefly at the structure of the electricity sector, since who does what type of planning will depend on how the industry is organized.

The original sector legislation (the Indian Electricity Act 1910 and the Electricity (Supply) Act 1948) promoted a state-owned, vertically integrated electricity sector through the creation of the Sate Electricity Boards (SEBs). The SEBs were given responsibility for generation, transmission, distribution and supply within the geographical limits each State. While the sector made considerable progress under the SEB regime, a number of problems arose, owing to the increasingly poor financial condition of the SEBs.

In the 1970s, the legislation was amended to allow participation of the Central Government in power generation through large-scale projects serving more than one State.3 These projects were beyond the financial capability of individual State Governments. Central Government participation led to the creation of successful generating companies such as the National Thermal Power Corporation (NTPC) and the National Hydroelectric Power Corporation (NHPC), collectively called the central sector power corporations (CSPCs).4 The sector remained vertically integrated, with some generation now coming from central-sector projects, and being sold to the SEBs. Captive power, i.e. the generation of electricity

2 The Tenth and Eleventh Plans aim together to add 100,000 MW of generation capacity during the period 2002-2012. About one-third of this total would be hydro, about half thermal (most of which will be coal-fired), and the balance nuclear and non-hydro renewable.

3 India’s federal system creates an institutional environment of shared authority over electricity. Under the Constitution, electricity is on the “concurrent list” of responsibilities. This means that the States as well as the Central Government can exercise legislative powers in the electricity sector.

4 These come under the Ministry of Power and include the National Thermal Power Corporation (NTPC), the National Hydroelectric Power Corporation (NHPC), the North Eastern Electric Power Corporation (NEEPCO), the Power Grid Corporation of India Ltd. (PGICL), the Power Finance Corporation (PFC) and the Power Trading Corporation (PTC).

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for own use, was allowed under certain circumstances.5 The objective of both amendments to the legislative framework was to reduce the gap between the demand for and supply of electricity.

In the early 1990s, private participation in generation was also allowed, again through amendments to the 1910 and 1948 Acts. Independent power producers (IPPs) were offered attractive terms to build and operate power plants, selling under traditional Power Purchase Agreement (PPA) contracts to the SEBs. In the mid-1990s, some states took the initiative to restructure their electricity sectors by separating generation from transmission and from distribution/supply. The so-called single buyer model was introduced, whereby the transmission utility/power procurer acts as the single buyer of all generation, selling to one or more distribution/supply licensees within the State, each with a monopoly franchise within a defined geographical area. A State Electricity Regulatory Commission (SERC) was set up in each liberalizing State to regulate the transmission, distribution and supply elements of the sector.

3.2 Electricity Act, 2003

A growing realization that these incremental changes were not sufficient to address the problems faced by the sector towards the end of the 1990s led to the passing into law of the Electricity Act, 2003. The 2003 Act creates a multi-buyer, multi-seller structure, without resort to a fully specified wholesale market in electricity.6 Under this structure:

generators no longer need a license to generate or techno-economic clearance from the Central Electricity Authority (CEA), except for hydroelectric power stations above a certain capital value, which is determined by the Central Government;

generators can sell electricity to any licensee (except transmission licensees) and, if permitted by the SERC, to customers directly;

no restriction is placed on the setting up of captive power plants by any consumer or group of consumers for their own consumption, though the sale of excess power to third parties requires the approval of the SERC;

the tariffs on which generators sell to distribution/supply licensees are determined by the Central Electricity Regulatory Commission (CERC), in the case of central sector generators selling to SEBs or generators selling to more than one SEB; and by the SERC in the case of within state generators who do not fall under the CERC’s jurisdiction;

the tariffs of power station projects awarded contracts under a competitive bidding process are protected through a provision that requires the CERC or SERC as the case may be to adopt tariffs as determined through the bidding process. For other projects, tariffs are determined by the regulatory commission according to guidelines set out in the national Tariff Policy;7

5 Captive power generation required approval from the SEB (exercising regulatory power) or the SERC if established. Decisions on captive power had to be based on two considerations: whether the SEB could supply power and whether the SEB could ensure the required supply at the desired time.

6 The introduction of an availability based tariff for contracted generation and the unscheduled interchange fee, dependent on system frequency, has resulted in something like a bilateral contracts market with a market in imbalances.

7 The first Tariff Policy drawn up under Section 3 of the 2003 Act was published on 6th January 2006.

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transmission is a regulated activity requiring a license. Transmission licensees are prohibited from undertaking generation or trading of electricity. The Central Government is required to designate one state-owned company as the Central Transmission Utility (CTU); and each State has to designate a state-owned company as a State Transmission Utility (STU);

transmission utilities are required to give open access to their transmission systems to any other licensee or to generators;

trading in electricity is recognized for the first time as a separate licensed activity;

distribution is a licensed activity and distribution licensees are allowed to trade electricity without requiring a separate trading license. No distinction is made between distribution and supply (i.e., the retailing of electricity);

allowance is made for the progressive introduction of retail competition (i.e., the selling of electricity directly to end-customers by a supplier other than the customer’s local SEB), though the timing and degree of such competition is left to the discretion of the SERC.

The 2003 Act says relatively little about planning within this multi-seller, multi-buyer structure. The Central Government is required under the Act to prepare a national electricity policy, in consultation with State Governments, based on the optimal utilization of resources such as coal, natural gas, nuclear substances or materials, hydro and renewable resources of energy. The first such National Electricity Policy was published on 12th February 2005.

The Act requires the CEA to draw up a National Electricity Plan, in accordance with the National Electricity Policy, and notify such a Plan every five years.8 The CEA also has a duty under the Act to:

co-ordinate the activities of the planning agencies for the optimal utilization of resources in the interests of the national economy and to provide reliable and affordable electricity for all consumers; and

promote and assist in the timely completion of schemes and projects for improving and augmenting the electricity system.9

Once drawn up by the CEA, the Plan has to be approved by the Central Government before being notified by the CEA. Once approved, according to the National Electricity Policy, it “can be used by prospective generating companies, transmission utilities and transmission/distribution utilities as a reference document.” This is the only reference to medium term generation expansion planning in the Act.

3.3 Current Generation Expansion Planning Process

3.3.1 Central Electricity Authority

Under the Act, planning of the sector as a whole is formally undertaken by the CEA. 10 But it would be misleading to describe the planning done by the CEA as anything like central planning. Generation expansion planning has gradually become more decentralized over the years as the financial limit for 8 See Section 3(4) of the Electricity Act, 2003.9 See Section 73(a) of the Electricity Act, 2003.

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techno-economic approval of power projects by CEA has been raised. The 2003 Act now removes the requirement for any CEA approval, other than for large hydroelectric schemes. This effectively removes the ability of the CEA to influence the choice and location of generation additions and means that the planning now done by the CEA is little more than indicative, similar to the type of generation adequacy planning done by transmission system operators in Europe.11 The CEA’s role in this area is now restricted to reviewing projects developed by the central power sector utilities (NTPC, NHPC etc.).

The CEA recognizes in its planning the environmental consequences of generation expansion. Indeed, a separate chapter is devoted to power generation and the environment in the Draft Eleventh National Electricity Plan of January 2006. But, as far as we are aware, there is little recognition that the environmental costs of generation are taken into account in drawing up the plan, except to the extent that:

for thermal plant, the costings of particular candidate plant include the costs of complying with the existing Central or State Pollution Control Board environmental standards (e.g., in terms of emission limits on particulate matter, SO2 and NOx; stack heights/limits; cooling water temperature limits effluent concentrations, ash utilization targets etc.);

for hydro and thermal plant, the site specific costs of land acquisition and of rehabilitation and resettlement;

for hydro plant, environmental management costs through Catchment Area Treatment Plans.

3.3.2 State level planning

It is at the State level that the real planning decisions about future additions to capacity now get made. This partly reflects the legislative environment, in that distribution licensees are obliged under the 2003 Act:

“on an application by the owner or occupier of any premises, to give supply of electricity to such premises, within one month after receipt of the application requiring such supply, provided that where such supply requires extension of distribution mains, or commissioning of new sub-stations, the distribution licensee shall supply the electricity to such premises immediately after such extension or commissioning or within such period as may be specified by the Appropriate Commission.12”

But it also reflects the reality of the situation, given the structure of the sector. It is the SEBs (or their unbundled successors) who are the de facto single buyers of electricity in the states and it falls to them to plan to acquire the necessary means to meet anticipated future growth in demand for electricity. So, to the extent that anything more than indicative planning is done, it is done at the State level. The CEA is no longer the agent that causes power generation projects to be built.

10 The CEA is currently drawing up the first five-year plan since the 2003 Act was passed, to cover the years 2007-2012. This will be the eleventh plan since 1951, when the first five year plan was drawn up by the Planning Commission, at a time when total installed capacity in India was 1,700MW and the planned for addition over the five years to 1955 was 1,465MW.

11 Examples include the Seven Year Statement of the National Grid in Great Britain, which also covers the period from 2006/07 to 2012/13; Eirgrid’s Generation Adequacy Report in Ireland, which also looks forward seven years; and the European Transmission System Operator Association (ETSO) Assessment of Generation Adequacy in the Interconnected European Power Systems, 2008-2015.

12 See Section 43 of the Act.

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Some SERCs have issued guidelines of what is required of an SEB (or its unbundled successor) in terms of generation, transmission and distribution expansion planning.13 Those of the Andhra Pradesh Regulatory Commission require the licensee:

to demonstrate to the Commission that its resource planning will ensure, to the maximum extent of its own control and influence, that all consumers connected to its transmission or distribution system will receive an adequate, safe, and economical supply of electricity, having regard to quality, continuity and reliability of service;

to demonstrate, through a process of integrated resource planning, that it has examined the economic, technical, system, and environmental aspects of all available reasonable options to satisfy the energy needs of its consumers;

to produce such a resource plan every second year, or at such other frequency as the Commission may from time to time require, to cover a plan period of be at least ten years;

to undertake a least cost plan (in the sense of least financial cost to the licensee), the ultimate objective being to make available a secure and reliable power supply at economically viable rates to all consumers while satisfying planning and security;

to describe the licensee’s plan for additional power procurement indicating unit sizes, type, gross capacity, year of commissioning, incremental net energy generated, and expected unit cost (to include energy, capacity and where appropriate transmission costs). The plan should show the options that were evaluated, the method of evaluation or proposed competitive solicitation, and the results or expected results of evaluation of alternative options. The plan should justify, in terms of economic advantage, the licensee’s preferred options for meeting new capacity requirements

It is instructive that, while the licensee is required to demonstrate that it has taken the environmental aspects of meeting the anticipated demand for energy within its area of supply, it is also required to plan on the basis of least financial cost. This means, as is the case with the CEA’s generation expansion planning, that unless the environmental costs of a particular candidate plant have been internalized, no additional recognition of the environmental impact of an addition to the capacity available to the SEB will be taken into account, despite the reference to the need to examine “the environmental aspects of all available reasonable options to satisfy the energy needs of its consumers.”

Similar regulations have been made by other SERCs. In the case of Rajasthan, it is the State Transmission Utility (STU) that is responsible for making an assessment of the SEB’s capacity requirements on an annual basis for the next five and ten years, in consultation with all concerned generating companies, distribution licensees, trading licensees and transmission licensees, the Regional Electricity Board and the CEA.14 An Energy Assessment Committee, comprised of representatives of the STU and the distribution licensees, makes recommendations on what additional generation and power purchases, or their curtailment, are required for the next 5 or 10 years.

3.4 Procurement13 See, for example, Andhra Pradesh Electricity Regulatory Commission Guidelines for Load Forecasts, Resource

Plans and Power Procurement, published on 28th February 2000.14 See RERC (Power Purchase & Procurement Process of Distribution Licensee) Regulations, 2004.

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Generation capacity procurement decisions are taken at the State level. The choices open to the SEBs in procuring new capacity are:

additional generation capacity within the State, either from the unbundled state-owned generation companies or the private sector, including captive power plants;

a share of additional generation capacity from outside the State, which could be either centrally provided (by one of the central sector companies, such as NTPC or NHPC) or privately provided.

In either case, the process of procurement is now regulated by the SERC, under Section 86 of the 2003 Act, in the case of capacity additions from within the State, or by the CERC, under Section 79 of the 2003 Act, in the case of capacity built, owned or controlled by the central sector companies for the SEBs or, in the case of companies other than those owned or controlled by the Central Government, where they sell to more than one SEB.

Broadly, the tariffs of competitively tendered capacity additions are determined (and accepted by the CERC or SERC) as part of the competitive tendering process.15 For projects that are not competitively tendered, for example where they involve the extension of an existing power plant or where there is a State controlled/owned company identified as a developer, tariffs are determined by the regulator, against the principles set down the Central Government.16 The CERC’s tariff principles, as set out in the Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 26 th March 2004 allow only the actual capital and operations and maintenance cost of any project to be recovered through the tariff.

In practice, the first place the SEBs look for new capacity is the central sector companies (i.e., NHPC and NTPC). This is partly because new hydro and thermal capacity developed by NHPC, NTPC and the other central sector companies is likely to be more economic than the alternatives (e.g., the state-owned generation companies); and partly because of the relatively strong financial position of the central sector utilities. One reason for this is a security mechanism put in place to protect NTPC receivables from state non-payment.17

Any new power purchase agreement (PPA) and amendments to existing PPAs entered into by the SEBs with generating companies within the state are subject to SERC scrutiny under section 86 of the Act. In the case, for example, of the Rajasthan Electricity Regulatory Committee, the criteria the RERC uses against which to judge PPAs include “conformity with safety and environmental standards”, among other criteria.

This suggests that regulators will take into account only the cost of meeting existing environmental standards, as determined at a central or state level by the Pollution Control Board or the Ministry of the 15 Under the Guidelines for the Determination of Tariff by Bidding Process for Procurement of Power by Distribution

Licensees, published by the Ministry of Power on 19th January 2005, as amended on 30th March 200616 See the Ministry of Power’s Tariff Policy, published on 6th January 2006. This states explicitly that “new capacity

addition should deliver electricity at most efficient rates to protect the interests of consumers”, though it does also say that “in the case of coal based generating stations, the cost of the project will also include reasonable cost of setting up coal washeries, coal beneficiation system and dry ash handling and disposal system.” Whether this allows for costs over and above those that require to be incurred to meet Pollution Control Board standards is unclear.

17 This arrangement has its origins in the early 2000s, when unpaid bills to NTPC were becoming unsustainable. It was agreed at that time that the debt would be converted to state guaranteed bonds, and NTPC would enjoy claw-back rights on any funds moving from the federal government to the state government to protect payment on these bonds.

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Environment and Forests in the case of hydroelectric schemes (under The Forest (Conservation) Act, 1980).

But also, and more importantly, the SERCs are under pressure to minimize load shedding and to keep tariffs down. These twin constraints mean that in practice the only environmental factors the SERCs (or the CERC at the central level) will take into account are the direct financial costs of complying with existing statutory environmental standards.

3.5 Summary and Conclusions

Existing generation and transmission expansion planning, whether done by the centre or at state level, is based entirely on the financial costs of future additions to capacity. Where appropriate, these include in the case of new or extensions to existing thermal plant the emissions control mitigation costs required to meet central or state statutory environmental standards; or, in the case of hydro electric plant, the resettlement and rehabilitation (R&R) costs associated with the local population displaced by hydroelectric schemes.

Similarly, the procurement process at central or state level makes no allowance for environmental costs other than the financial costs of complying with pre-existing environmental standards and R&R costs, as embodied and reflected in the tariff determined by a competitive bidding process or by regulation in conformity with the central government’s Tariff Policy and the CERC or SERC’s regulations as the case may be.

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Internalisation of Environmental Externalities

4 INTERNALIZATION OF ENVIRONMENTAL EXTERNALITIES

4.1 Background

This section looks at how the planning process might be adapted in the event that greater emphasis is put on internalizing environmental externalities. Particular attention is put on looking at economic instruments, including emission allowance trading schemes.

Externalities arise when the actions of producers or consumers have unintended external (indirect) effects on other producers or/and consumers. Externalities may be positive or negative. Environmental externalities are usually negative and arise when an action by an individual or group (in this context an electricity generator or transmission utility) produces harmful effects on others. When a generator emits e.g., SO2, NOx or particulates, this has an effect on the surrounding environment and the local population will bear costs in the form of adverse health effects, damage to buildings and crops etc.. The environment is effectively treated as a “free” good. So generators and transmission utilities take no account of the adverse environmental effects that their activities have in their private decisions. The social cost of generation and transmission is higher than the private cost.18

‘Internalizing’ an environmental externality broadly refers to the process of incorporating environmental costs in the private decisions of producers and consumers, to offset the tendency to treat the environment as a “free good.” This can be done directly, effectively by raising the cost of the activity in question, e.g., by taxing the cause of the environmental externality or by setting higher standards. Or it can be achieved indirectly, by ensuring that the environmental externality is acknowledged in the planning process, even if private costs remain unaffected.

The section looks first at the question of what other environmental externalities should be explicitly included in the planning process, drawing on Section 2.

It then goes on to consider the options for ‘internalizing’ those externalities, including:

reflecting environmental externalities directly in the Central Pollution Control Board’s emission standards or in technology standards - so-called command-and-control regulations;

the incorporation of adders in the generation and transmission expansion planning process i.e., in the candidate plant costs) and how that might be done (e.g., as an Rps/kWh charge);

economic instruments, including emission fees (i.e., charges on emissions), marketable allowances and environmental taxes (i.e., taxes on emissions intensive inputs and outputs).

In each case an assessment is made of the advantages and disadvantages of each option, including where possible lessons from the experience of other countries and the implications of each option for compliance and monitoring.

18 Externalities generally arise because of market failures. The market fails in the case of environmental externalities because markets for environmental goods and services do not generally exist. Markets can exist and function efficiently only when property rights on goods and services exchanged are well defined and the transaction costs of exchange are small.



The section concludes with an assessment of how to treat identified costs and benefits that it is recommended should not be explicitly incorporated in the planning / implementation process.

4.2 Changing Sector Structure

By way of introduction, it is worth making the point that the effectiveness of some approaches to recognizing to a greater extent than hitherto the environmental effects of generation will depend on the market structure. As was noted in Section 3 above, the structure of the electricity sector in India is changing from a vertically integrated to an unbundled one, in which consumers will eventually be able to choose a supplier other than the local SEB. Incorporating externalities other than through an economic instrument (i.e. one that directly affects costs) will be increasingly difficult the more unbundled the sector becomes.

This may take some time to develop at the retail level, though the opening up of captive generation to groups of consumers might well mean that large industrial customers will soon find themselves able to be supplied by a supplier other than their SEB. As the change takes place, it will inevitably be associated with a move from prescriptive to indicative planning of the sector. In other words, planning as it is currently conceived and practiced at the State level will become less effective as a tool with which to determine the future evolution of the generation sector. Decisions will increasingly be taken at a decentralized level by private generators and private consumers. Planners may be able to influence decisions by publishing indicative plans, of the type now done by the CEA. But, once customers can choose to be supplied by someone other than their incumbent SEB, the decisions themselves on what to build and where will be capable of being influenced only by statutory environmental standards. Moreover, with generation now an unlicensed activity, the CERC and SERCs will be unable to stipulate through license conditions what type of plant can be built or what standards such a plant should meet.

This changing market structure will generally mean that instruments that rely for their impact on planning will become less effective through time. To put it another way, the more decentralized the decision-making approach becomes, the more the authorities will have to rely on measures that directly internalize the external environmental effects of generation and transmission by increasing private costs.

4.3 Options for the Internalization of Environmental Externalities

4.3.1 Inclusion of adders

One simple means of giving greater emphasis than hitherto to the environmental costs of generation and transmission would for the relevant body responsible for expansion planning, in this case the SEBs, to quantify and include external environmental costs, using so-called “externality adders,” when making generation expansion planning decisions; and for the SERC to accept the subsequent expansion plan. 19 In electricity generation, these adders might be expressed in terms of a Rs/kWh addition to the liveliest cost of the particular candidate plant imposing the environmental externality. They might be determined using estimates of the marginal environmental damage costs imposed by a particular candidate plant or generic type of plant.

Unlike other options discussed in this paper, environmental externality adders do not directly affect the costs of the sources of emissions. They act as a shadow price for the purpose of determining an

19 In the context of electricity generation, an externality adder is defined as the unit externality cost added to the standard resource cost of generation to reflect the difference between the social and private cost of generation.

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expansion plan that better reflects the environmental consequences of additional generation or transmission. The use of adders does not in itself not add to the costs of the projects. This typically has limited consideration of externalities elsewhere to the planning or acquisition of new generating capacity within the context of a vertically integrated structure and where such decisions are subject to explicit regulatory review.

This approach was used in the early 1990s in the US. By 1995 seven States had mandated the use of monetary externality values within a so-called integrated resource planning (IRP) process, in which utilities were required to evaluate supply- and demand-side options on a consistent basis in planning reliably to meet future demand at the lowest system costs. The general consensus is that the requirement to incorporate externalities in the resource planning process had negligible impacts on the planned resource mix of the utilities in those States, though this may have been because of a number of particular factors applying at the time (e.g., low natural gas prices resulting in gas-fired generation being the capacity of choice to meet increments in demand; little need for new capacity; and inter-state jurisdictional issues).20

In India’s case, internalization through the use of adders would involve the Central or State Pollution Control Board specifying particular numerical adders to be considered in the generation expansion planning process. The CERC or SERC, as the case, would then accept the generation/transmission plan that is generated using these externality adders, even though the actual financial costs of each generation or transmission option would be unaffected. The SEB and the SERC would effectively be required to make decisions as if a direct cost were imposed. If the SEB was required to use appropriate adders in all its capacity addition decisions, an optimal plan would be chosen. And if the estimated externality adder was an accurate estimate of the difference between the social and private cost of the particular candidate plant option, a least social cost plan would be achieved.

It can be argued, however, that a least social cost plan would not be achieved in practice if external costs are only factored into capacity addition decisions and not into operation. The external environmental costs of capacity expansion would be considered, but the SEB would effectively dispatch the generating plant then at its disposal to minimize private cost. This is inefficient because efficient alternatives almost always include some degree of emissions dispatch. These inconsistent incentives could lead to inefficient decisions, such as the adoption of expensive emission controls when changes in dispatch order would accomplish the same emission reductions at less cost. Adders are, at least in this respect, inferior to an economic instrument such as an emissions tax.

In sum, the advantages of using quantitative adders in expansion planning are that external environmental costs would be reflected in a different generation and transmission expansion plan than if nothing was done.

On the other hand:

since private costs would remain unaffected, regulatory pressure to minimize the effect on end-user tariffs by choosing the least financial cost expansion plan would remain, thereby negating the intention of the use of adders;

20 See Energy Information Administration: Electricity Generation and Environmental Externalities: Case Studies. September 1995, Washington D.C.

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operational decisions would remain unaffected, since adders would be unlikely to be feasible at the dispatch level;

use of externality adders, and indeed the use of prescriptive generation expansion plans, will be increasingly difficult to maintain as the sector changes from a single buyer model to a more competitive wholesale market, where multiple buyers take decisions to buy from multiple sellers at a decentralized level;

the more competitive the sector becomes at both a wholesale and retail level, the less effective the use of adders would be as a means internalizing environmental externalities, because central planning has no meaning in a decentralized market structure.

4.3.2 Tighter standards

In India, as in most other developing countries, environmental regulation is currently exclusively in the form of what is known as command and control (CAC) regulation. This undoubtedly reflects a mistrust in the past in economic solutions, in turn reflecting a belief that property rights in air, water, and other environmental resources are impossible to allocate or to enforce. The rise and dominance of CAC regulation was a necessary response to the inability of the legal framework and markets adequately to prevent environmental damage.

CAC approaches require groups of similar generating plant (e.g., coal plant) to use a specific control technology or to comply with a uniform emission rate requirement. Standards typically must be met either through the use of a specified fuel (e.g., coal with a sulphur content less than a specified amount) or by the installation of a specified control technology (e.g., low NOx burners, electrostatic precipitators etc.). Once these measures have been taken and internalized, there is little or no value to the generator in achieving further emission reductions through improved efficiency or changes in operations.

Tightening standards within the existing CAC approach would have advantages:

it would build on and utilize the current approach to environmental regulation, one that is familiar to policy-makers and regulators in India

it would be the most direct way of internalizing environmental externalities, in the sense that tighter environmental standards would be directly reflected in higher capital or operating costs and would thus directly alter the relative costs of generation sources;

if the monitoring system was adequate and if compliance were strictly enforced, tighter standards would result in lower emissions.

On the other hand:

the CAC approach is economically inefficient, since additional emission reductions that could be made at a marginal cost that is lower than the cost of some required reductions and potentially lower than incremental environmental damage costs are not made;

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setting uniform requirements for broad categories of generating plant ignores site-specific differences in the costs of control or the impacts of emissions from different sources;

monitoring and enforcing CAC standards imposes high costs and creates free rider problems if the authorities fail to monitor and enforce compliance effectively. For example, a firm that complies will incur costs in doing so, while one that does not need not face penalties if enforcement is weak. The failure of the authorities strictly to enforce standards may depend on how well firms on average comply. This will create an incentive for firms to ‘free-ride’ (i.e. fail to comply) in the hope or expectation that others will in sufficient numbers.

4.3.3 Economic instruments

4.3.3.1 General advantages

Policies that create financial incentives for emissions abatement by putting an explicit or implicit price on emissions, but which do not themselves dictate abatement decisions, are referred to as market-based or economic instruments.

The main examples of such policies are:

the removal of subsidies;

environmental taxes, which are taxes on the inputs used by generators (e.g., therms of gas, tonnes of coal); or on the characteristics of the inputs (e.g., the sulphur or ash content of coal); or on the amount of generation (i.e., GWh) produced;

emissions fees, which are fees paid by generators per unit of emissions (e.g., tonnes of CO 2, SO2); and

tradable emission schemes, wherein generators are allocated "allowances" to emit a certain amount of CO2, SO2 etc. which they can trade with other generators if there is a commercial advantage in doing so.

The common element among all economic instruments is that they work through the market and alter the behavior of generators and consumers by changing the incentives/disincentives they face. Economists have long argued that economic instruments are superior to CAC policies in terms of static efficiency, dynamic efficiency, and flexibility.

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4.3.3.1.1 Static efficiency

The static efficiency advantages of economic instruments stem in part from the fact that generators are free to choose abatement technologies that minimize costs, given their individual circumstances. By contrast, under CAC emissions standards, the relevant Pollution Control Board more or less dictates that whole classes of generators chose certain technologies.

Perhaps more important for static efficiency, economic instruments create incentives for individual generators to choose levels of abatement such that aggregate costs of achieving a given level of emissions are minimized. Specifically, generators with low abatement costs are incentives to emit less than those with higher abatement costs:

in emissions fee schemes, generators whose marginal abatement costs are lower than the fee will abate, while those whose marginal abatement costs are higher than the fee will not abate - they will pay the emissions fee instead;

in emissions trading schemes, generators with abatement costs below the market price of emission allowances will abate and will sell their emissions allowances, while those with marginal abatement costs above the allowance price determined in the market will not abate - they will buy allowances instead.

This type of behavior is sufficient by itself to make economic instruments more cost-effective than most CAC policies. For a CAC policy to achieve the same result, the relevant Pollution Control Board must know the marginal abatement cost of every generator. Economic methods effectively rely on the market to process the relevant information and to create incentives for firms to adjust their behavior accordingly to generate the most efficient outcomes. This reduces the burden on the policy maker/regulator of determining costs and preferences.

4.3.3.1.2 Dynamic efficiency

Although static efficiency arguments are the ones that are usually brought to bear by advocates of economic instruments, the advantages of dynamic efficiency may be of greater long-run importance.

Because generators can always increase profits by reducing emissions, economic instruments provide continuing incentives for emission-reducing innovation. By contrast, in a CAC system, the incentive to innovate is often offset by the enforcement risks associated with using a non-approved technology and the risk that a well performing new technology will serve as the technology-based standard in a new round of CAC standards.

4.3.3.1.3 Conclusion

However, despite strong theoretical arguments and some empirical evidence of the advantages of economic instruments over CAC, it is striking how rare economic instruments are, even in countries such as the USA with strong free-market traditions.21 Worldwide, almost all countries have adopted CAC

21 See Blackman, A. & Harrington, W.: The Use of Economic Incentives in Developing Countries: Lessons from International Experience with Industrial Air Pollution Using Alternative Regulatory Instruments to Control Fixed Point Air Pollution in Developing Countries: Lessons from International Experience, May 1999. Resources for the Future, Discussion Paper 99-39.

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policies as the primary means of controlling emissions. Blackman and Harrington cite three factors as to why economic instruments have not been applied more often:

the main advantage of economic instruments - improved economic efficiency - is something that policy makers do not concern themselves with, since there is rarely a constituency for maximization of efficiency as such. And since economic instruments can have significant revenue distribution effects, this will create opposition to such policies;

the monitoring requirements of economic instrument schemes, which will be particularly significant in developing countries, may be more demanding than those associated with CAC schemes. For example, a CAC technology standard only requires evidence that the designated technology has been installed. In an emission fee scheme, the monitoring data are used to compute fees, so monitoring must be accurate to avoid jeopardizing political support;

in most countries CAC policies are the status quo. If CAC policies had manifestly failed to improve air quality, pressure for moving to economic instruments might be greater. But CAC policies have not generally failed. The air quality improvements observed in many countries might have been achieved at much lower cost using economic instruments, but that is unlikely to impress policy-makers.

4.3.3.2 Types of economic instruments

4.3.3.2.1 Removal of subsidies

While strictly not an economic instrument in the usual sense of the term, the removal of subsidies on inputs associated with harmful emissions has the same impact as an environmental tax, since it will raise the cost of inputs just as an environmental tax would; and the removal of subsidies and cross-subsidies at the end-user price level would reduce demand, thereby indirectly reducing emissions.22

The Indian energy sector suffers from distorted pricing at several levels:

while important steps have been taken in recent years to raise oil and coal prices to economic levels, fuel prices are not yet set at economic levels:

o domestic coal (in rupees per unit of heat) is priced below its long run marginal cost, including environmental costs and well below the price of imported coal, suitably adjusted for (economic) domestic transportation costs and the 30% customs duty borne by imported coal;23

o domestic gas is priced below the price of the marginal source of supply, i.e., liquefied natural gas (LNG);

taxes and customs duties on petroleum products are not uniform across products.24

22 In Central and Eastern Europe, for example, removing long-standing fuel subsidies has probably done more to improve environmental quality than any explicit environmental policy.

23 See Environmental Issues in the Power Sector: Long-Term Impacts and Policy Options for Rajasthan, World Bank/ESMAP, October 2004

24 See Draft Report of the Expert Committee on Integrated Energy Policy, Planning Commission, Government of India, December 2005, pp 81-82.

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average tariffs at the end-user level are not cost-reflective, resulting in large and persistent subsidies from government to the sector as a whole;25

individual customer category tariffs are not cost-reflective, resulting in the heavy cross-subsidization of some categories of customers (i.e., agriculture and the domestic sector) by others (i.e., commercial and industrial consumers). The unbundling of tariffs, as was done in the Philippines subsequent to the passing of the 2001 Electric Power Industry Reform Act, would make the detailed structure of the end-customer’s bill more transparent, thereby facilitating the identification of cross-subsidies.

In Central and Eastern Europe, it is argued that removing long-standing fuel subsidies has done more to improve environmental quality than any explicit environmental policy. The existing extent of subsidization and cross-subsidization in the Indian energy sector suggests that a similar step would have a significant impact.

4.3.3.2.2 Environmental taxes

The most common economic instrument is the environmental tax. Instruments such as environmental taxes may stand a better chance of being effective since they are less demanding of environmental regulators than instruments that rely on monitoring and compliance enforcement for their effectiveness.

There are three types of environmental taxes:

taxes on final products associated with a polluting activity (i.e., electricity);

taxes on inputs into the polluting activity - electricity generation/transmission in this case (i.e., oil, coal gas); and

taxes on polluting substances contained in inputs into generation/transmission (such as the sulphur content of coal).

Each of these types of taxes has advantages and disadvantages. Their advantages include:

the fact that they raise revenue, which can be considered a good thing since the proceeds can be used for environmental purposes;

by reducing demand, they reduce the environmental impact associated with the input or output;26

ease of administration, since quantities of goods are easier to monitor than quantities of emissions; because environmental taxes generally operate through government tax collection institutions rather than environmental regulatory institutions.

Unfortunately, environmental taxes have a number of disadvantages.

25 See State Power Sector Performance Ratings, Final Report to the Ministry of Power, Government of India, June 2006, CRISIL & ICRA Limited.

26 Narrowly targeted taxes (e.g., on the ash content of coal) are more likely to have a significant environmental impact than a broadly based tax (e.g., on coal), because the demand for high ash coal is likely to be more responsive to price than the demand for coal, i.e. there are alternatives to high ash content coal. When substitution is costly, the level of the input tax must be high enough to cause the required reduction in emissions

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First, they do not create incentives to abate emissions in themselves, only to limit purchases of an input or an output linked with emissions:

a tax on electricity can reduce emissions by reducing electricity demand (and hence electricity generation and transmission), but cannot create incentives to cut emissions per unit of electricity generated;

a tax on a polluting input, coal, can do this, but cannot create incentives to use clean coal;

a tax on the polluting content of an input, such as a tax on the ash content of coal, can do this but even this type of environmental tax cannot create incentives to install pollution abatement equipment, since plants with such equipment pay the same unit tax as those without them.

Second, an environmental tax may affect non-targeted activities. For example, a tax on gas intended to reduce emissions from combustion will affect manufacturers who use gas as a feedstock, not as a fuel, unless they are exempted from the tax.

A good example of an environmental tax can be found in Sweden. Sweden introduced a tax on sulphur in January 1991. It is a tax on the sulphur content of coal, peat, and oil. The tax rate, US$3,900 per ton, was based on a calculation of the average marginal cost of abating sulphur emissions. Fuels that are used for purposes other than energy (e.g., petrochemicals) and fuels containing less than one percent sulphur by weight are exempted from the tax. To reward firms that have installed flue gas desulphurization equipment, the tax is refunded when emissions are controlled by scrubbers. To prevent cheating, firms that claim refunds are subjected to continuous emissions monitoring systems (CEMS). The sulphur tax supplements a pre-existing CAC regime.

The impact of the sulphur tax is difficult to evaluate because of parallel CAC regulations, simultaneous tax reforms and structural changes in the Swedish economy. Nevertheless, there are indications that the tax had a significant effect on sulphur emissions.27 Aggregate sulphur emissions fell by 25 percent in the first year the tax was administered. More tellingly, after the imposition of the tax in 1991 but prior to the tightening of CAC emissions standards in 1993, the average sulphur content of heavy fuel oil fell from 0.65 percent to 0.40 percent.28 And, according to the OECD, annual sulphur emissions have fallen by about 6,000 tons per year as a direct result of the tax. Administrative costs are estimated to have been less than one percent of total revenues.29

In the Indian power generation context, one of the most significant distortions relates to the pricing of water. As the work on Rajasthan within the framework of the World Bank’s Environmental Issues in the Power Sector (EIPS) project showed, the consumptive use of water for thermal coal and lignite projects is substantial.30 This water is provided free, even in drought-prone states, yet opportunity cost calculations suggest it should be priced at about Rs. 0.05/kWh. An environmental tax at that rate on the consumption of water would internalize the cost and provide operators with better incentives to manage their use of water.

27 See Blackman and Harrington, 1999, ibid.28 See Lovgren, K. “Instrument for Air Pollution Control in Sweden,” in G. Klassen and F. Forsund, eds. Economic

Instruments for Pollution Control, 199429 OECD: Evaluating Economic Instruments for Pollution Control, 199730 According to the study, the generation of 1kWh evaporates 3.75 litres of water in cooling towers. See

Environmental Issues in the Power Sector: Long-Term Impacts and Policy Options for Rajasthan, World Bank/ESMAP, October 2004

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4.3.3.2.3 Emission fees

Emission fees are fees paid by generators per unit of emissions of a particular pollutant (e.g., CO 2, SO2, NOx etc.).31

Emission fees have similar advantages as environmental taxes over CAC polices:

they raise revenue, which can be earmarked for environmental purposes;

they directly reduce emissions by creating incentives to reduce emissions per se; and

they reduce emissions at lower aggregate costs than a CAC policy would do, since they incentivize those with low abatement costs to emit less than those with high abatement costs.

Annex II describes the experience of three countries – China, Poland and Sweden – in the design and implementation of emissions fees to control SO2 and NOx. This experience of these three countries holds several lessons for India:

fees need to be set high enough to have an impact on emissions. However, sufficiently high fees present a number of difficulties in a developing country like India:

o it may be difficult politically to raise fees to the requisite level: firms are bound to complain that they must pay fees on emissions in addition to paying to abate;

o high fees could result in pervasive non-compliance that might eventually threaten the legitimacy of the regulatory system, though earmarking fee revenue for the use of the generators that pay them, exempting small generators from paying fees, using two-tiered fee structures to reduce regulatory costs for generators that meet emissions standards, and differentiating fees across generators by vintage and geographical location may help;

fees need to be collected, particularly but not only from the worst polluters;

earmarked fee revenue should be disbursed in a manner that preserves the incentive properties of emissions fees;

to the extent possible, barriers to the effectiveness of emissions fees created by pre-existing regulation should be removed or mitigated. An example is tax laws that enable Chinese and Polish firms to count most emissions fees as tax-deductible expenditures.

Emissions fees clearly require some minimum level of credible monitoring and enforcement. Unless the institutional capability and political will exists to provide a minimum level of monitoring and enforcement, emissions fees will not have the desired environmental impact. Unfortunately, the costs of continuous environmental monitoring systems make them an unrealistic choice for most developing countries. Since second-best monitoring methods are the logical alternative, emissions fee systems should probably be restricted to those pollutants (e.g., SO2) for which such methods are effective. But second best methods are not well-suited to monitoring particulate emissions, which the companion paper by Professor Anil Markandya has shown to be particularly harmful to human health.

31 The use of the word ‘fee’ is somewhat arbitrary. In the literature, fees refer only to charges on emissions, whereas the word ‘tax’ usually refers to charges on pollution intensive inputs and outputs.

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The World Bank has suggested that emissions fees could be used for local pollution problems in India, such as ash disposal, particularly for the small and medium enterprise (SME) sector (which is currently excluded from the pollution control regime).32 According to the World Bank, an ash disposal fee would be feasible but would have a limited effect unless it was combined with power sector-reform and the introduction of commercial incentives.

4.3.3.2.4 Tradable emission allowances

Taxes (or fees) and tradable allowance systems are, in principle, very similar policy instruments. Both rely on price signals and on financial incentives for emitters to reduce the external costs they impose on society.

In a first-best world they are equivalent.33 And in a second best world, as Norregaard and Reppelin-Hill show, there is no obvious preference from a theoretical point of view for either taxes (i.e., a price-based economic instrument) or tradable allowances (a quantity-based economic instrument).34 However, from a practical point of view, the majority of countries using economic instruments for environmental policy purposes have hitherto relied more on taxes or fees than on tradable allowances. This may be because taxes are a more familiar tool than tradable allowances and a tool that can be implemented through an existing administrative apparatus; and because a tradable allowance scheme imposes greater administrative costs than using the tax system. This is because, for the scheme to work at all, participants must have confidence in the integrity of the monitoring, measuring and verification/certification systems put in place. These systems are required to ensure that the prices of permits in the market truly reflect the fundamental drivers of the price. Without confidence in those systems, the scheme will not work effectively, if at all.

The literature agrees that efficient and effective monitoring, measuring and certification provisions have been central to the success of the recent US tradable allowance schemes. This has been largely due to the automated measuring and reporting devices used in the US for NOx and SO2. They are, however, expensive to install and operate.

Nonetheless, tradable permits have been used in a number of countries to deal with various environmental or resource problems since the 1970s, notably air pollution, fisheries, water management, waste management and land-use. Most tradable permit schemes link government regulations with markets. Allowances delivered by governments to firms are recognized as a means of complying with a certain regulation. The permits are then simply recognized as tradable.35

32 See UNDP/The World Bank: India: Environmental Issues in the Power Sector ESMAP Report No 205/98, June 1998.

33 See Norregaard, J and Reppelin-Hill, V: Taxes and Tradable Permits as Instruments for Controlling Pollution: Theory and Practice. IMF Working Paper WP/00/13, January 2000.

34 Nordhaus argues, in the context of how best to control global greenhouse gas emissions, that the structure of the costs and damages in climate change gives a strong presumption to price-type approaches, such as a harmonised carbon tax, rather than a global tradable permits scheme. The reason is that the benefits of emissions reductions are related to the stock of greenhouse gases, while the costs are related to the flow of emissions, implying that the marginal costs of emissions reductions are highly sensitive to the level of reductions, while the marginal benefits of emissions reductions are invariant to the current level of emissions reductions. Fees or taxes are likely to be much more efficient than quantitative standards or auctionable quotas when there is considerable uncertainty, as is clearly the case with climate change. See Nordhaus, W: Life After Kyoto: Alternative Approaches to Global Warming Policies, NBER Working Paper No. 11889, December 2005

35 The words allowance and permit are often used interchangeably. The term allowance is used here to refer to the allocations issued to firms to cover total emissions from their plants. The generic term for a unit of trade is a permit.

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There are two broad types of schemes: “cap-and-trade” and “rate-based trading” regimes (see the Table below):

in a cap-and-trade scheme, the total number of allowances are fixed. These allowances are then allocated across firms, usually on the basis of emissions in some previous period;

in a “rate-based scheme” the allowances are determined relative to a standard, e.g., emissions per unit of output.

In either scheme, firms that can cheaply reduce their emissions more than stipulated by the fixed allowance (cap-and-trade) or the relative allowance (rate-based) can sell surplus emission allowances to others that have only costlier options for reducing emissions. As a result, the total cost incurred by firms in achieving the emissions cap set by the regulator is lower than in case of pure CAC environmental regulation.

Annex II describes the features of two of the more important tradable allowance schemes in the US – the Emissions Trading Program and the Sulphur Dioxide Program; the European Union’s Emissions Trading Scheme (the ETS); and the Emission-Offsets Trading Programme introduced in the early 1990s in Santiago, Chile to control total suspended particulate emissions from stationary industrial sources. The inclusion of the ETS as an example is intended to illustrate the workings of a trading scheme, albeit one that operates across all 25 member states of the European Union. It is not included in the Annex because of a perceived need for a trans-State scheme to control CO2 emissions in India.

International experience suggests that tradable allowance schemes will be most successful in controlling emissions where:

the pollutant is readily quantifiable and measurable;

there are a large number of fixed sources of emissions and where the firms involved are sufficiently large and sophisticated to deal with the contractual and commercial requirements of trading permits (e.g., pricing and risk management functions);

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Table 1: Tradable Emissions Allowance Schemes

Cap-and-Trade Rate-Based Trading

Applies to all emissions Applies to emission vis-a-vis some defined standard (e.g., emissions per unit of output)

All emissions can be traded Emissions above or below the standard can be traded

Allowances are allocated by the regulatory authority Credits are generated when a source reduces its emissions below the standards

Trading must be built into the regulatory structure from the beginning

May develop incrementally as a means of introducing flexibility into existing regulatory structure

Participants can buy or sell or both Participants can buy or sell or both

Participation in the programme is mandatory – the overall emission cap still applies even if sources do not trade

Participation in the programme is usually mandatory – sources must meet existing standards

Source: US Environmental Protection Agency, 2003

the market is not dominated by one or a small number of firms who hold the majority of the allowances and are therefore in a position to exercise market power;

there is a pre-existing institutional basis for regulatory control of the pollutant, providing an effective structure that inspires confidence.

Experience also suggests that, in designing a scheme, the following criteria apply:

Simplicity - the simpler the system, the more likely it is to succeed. This implies minimal restrictions on trade and streamlined administration and enforcement procedures.

Allowance allocation - this is the most intractable issue. The allocation rule should be simple, it should be based in part on historic data (grandfathering) and it should be perceived to be fair. Auctions of a portion of the permits may have a useful role in stimulating the market and providing a means of acquiring permits for new entrants. Auctioning also avoids the perception that existing (dirty) sources of the pollutant profit from the allocation of allowances (the permit to pollute problem);

Data - there must be accurate data on the baseline for allowance allocation, together with reliable and accurate systems of emission monitoring and permit accounting.

Certainty - permits must be protected from confiscation or arbitrary modification in value and there must be confidence in the stability of the scheme for a reasonable period of time. Without this, participants will not trade and will not market necessary investments in abatement since they will have little confidence of being compensated in the permit market.

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Banking - flexibility and confidence in the system may be significantly increased by allowing permits to be banked.

Enforcement - there should be strong penalties for evasion together with a high probability of detection.

Compatibility - the scheme must be compatible with existing regulatory requirements and these should not unduly restrict the scope for trade.

Commitment - there should be a strong policy commitment to the system and its objectives. The constituency of political support should include the affected parties, including the sectoral regulators, who will need to sanction the passing through to end-customers increase in end-user prices that will result from the inclusion of permit prices in the wholesale price of electricity.

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Conclusions & Recommendations

5 CONCLUSIONS & RECOMMENDATIONS

A number of conclusions can be reached on the basis of the evidence presented in this paper on whether and how India might best internalize environmental externalities.

First, as previous work UNDP/World Bank work has already established, the environmental consequences of generation and transmission India are best mitigated in current circumstances by pushing ahead with power sector reform.36 Failure to push ahead with reform will, according to the World Bank, limit the environmental benefits that can be gained from:

raising end-user tariffs in real terms;

reducing technical losses in the transmission and distribution systems;

increasing the efficiency of state-owned thermal plants;

reforming the structure of tariffs;

the restoration of financial health to the sector, thereby sensitizing sector participants to penalties for non-compliance with environmental standards;

the removal of the discriminatory customs duty that constrains the use of low ash, low sulphur imported coals; and

eliminating the health impacts of small diesel generators in highly populated urban areas by reducing shortages through adequate grid-based generation, which in turn means financially healthy SEBs (or their successors).37

While all these effects will be significant in environmental terms, the final one is, in this context, perhaps of more direct interest. As Lvovsky et al. show, the adverse environmental effects of self generation are about 35 times as high as grid-based commercial generation. If pushing ahead with electricity sector reforms has the effect of large scale substitution of small diesel sets for grid-based energy, the environmental benefit will be large.38

Second, other initiatives, either at the planning level or in adopting economic instruments, are unlikely to be effective in the absence of reform.

Third, ensuring that fuels are priced at their economic cost, as suggested by the Planning Commission’s Draft Report of the Expert Committee on an Integrated Energy Policy paper, is another step that could be taken to ensuring that the environmental costs of electricity generation and transmission are internalized.

36 See Environmental Issues in the Power Sector: Long-Term Impacts and Policy Options for Karnataka, Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP), October 2004

37 Though the trend is positive, the gap between average realised revenue (in terms of cash collections) and the average cost of supply, which is a measure of the subsidy given by the state government to the sector, remains high in almost all States, with the exception of Goa, West Bengal and Chattisgarh. See Final Report on State Power Sector Performance Ratings, CRISIL/ICRA for the Ministry of Power, June 2006

38 Lvovsky, K. et al: Environmental Costs of Fossil fuels: A Rapid Assessment Method with Application to Six Cities, World Bank Department Paper 78, Washington D.C. 2000


Conclusions and Recommendations

Fourth, using externality adders in power sector planning at either the state or central level to reflect the environmental externalities of generation and transmission is unlikely to be either feasible or effective. Planning is currently done on the basis of financial rather than economic costs. The use of shadow prices is unlikely to have much effect at a practical level, so long as the over-riding policy objective is to build enough new generating and transmission capacity to meet the anticipated growth in demand, including unserved demand. When capacity is as short as it currently is in India, trying to get planners to choose a different (and by definition more costly) mix of plant to meet a persistent shortfall in supply is unlikely to be effective.

Fifth, the most direct way of internalizing environmental externalities would be to tighten Pollution Control Board standards, both for existing plants and for new plants. Using the current command-and control regime would have the advantage of familiarity. And it would maximize the chances of a fair regulatory treatment for the recovery by generators of their compliance costs, since the direct cost of meeting tighter limits would be reflected in the capital and operating costs of generation. But existing particulate matter emission limits are frequently exceeded, as Professor Markandya’s paper shows. It is not obvious that tighter limits would have much effect. The priority must be to ensure compliance with the existing limits, before contemplating tighter ones.

Sixth, of the economic instruments:

1) an environmental tax could be relatively easy to administer, if the existing tax authorities in India are used to administer them. An environmental tax could be targeted, e.g., exemptions could be used to protect those using gas as a feedstock rather than a fuel. But the levying of an environmental tax high enough to have an environmental impact is likely to be difficult for political reasons;

2) emissions fees are a feasible regulatory solution to the problem of how to internalize environmental externalities. But they depend for their effectiveness on the institutional capability and political will to provide a minimum level of monitoring and enforcement and will therefore suffer from the same non-compliance problems in India as the existing command and control regime;

3) emissions trading is unlikely to be feasible in the foreseeable future in India. The success policy makers in the US (and now policy makers in Europe with the successful introduction of the Europe-wide ETS) at developing emissions trading schemes is not likely to be easily replicated in India. A lack of monitoring, enforcement, and administrative capabilities is a critical constraint on emissions allowance trading.

Tradable permit markets will simply not work without these monitoring, enforcement and administrative capabilities, while emissions fees can work effectively, as the China and Poland case studies illustrate. And economic instruments depend for their effectiveness on the enterprises affected by the instrument in question being able and willing to respond to the incentives created. It is not obvious that the institutional/organizational framework for pollution abatement in India currently is sufficiently effective. And state-owned enterprises (which dominate the power sector) are less responsive to market forces than private firms since they generally face “soft” budget constraints.

To the extent that there is an appetite in India for reflecting the relatively high external costs of fossil fuel generation, particularly that of coal, in the direct costs of generation, then a system of emissions fees would appear to be a more realistic and appropriate policy alternative than emissions trading in current circumstances.

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Conclusions and Recommendations

35


International Experience

ANNEX I: TERMS OF REFERENCE

1. BACKGROUND

India plans to add 100,000 MW of new generating capacity within the period 2002-2012. Within the Ministry of Power planning framework, about one-third of this total would be hydro, about half thermal (most of which will be coal-fired), and the balance nuclear and non-hydro renewable. The majority of capacity additions are slated to come from central sector, majority state-owned firms such as NTPC and NHPC. The balance is expected from state-level generators, and from the private sector. In practice, NTPC (the central sector thermal generator) has come closest to meeting its planned capacity addition target, and most of this capacity has been coal-fired.

Technical and costing work is performed by the Central Electricity Authority. Based in part on this work, the Ministry of Power formulates generation expansion plans that feed into the five-year economic planning cycles used by the Government of India. Currently India is more than half-way through the Tenth Plan (2002-2007) and on track to add about 75% of the planned 41,000 MW envisioned. This performance will likely leave India considerably short of the 100,000 MW target for 2012.

A framework for capturing environmental externalities within the power system planning framework is only now emerging, and it is substantially incomplete. Historically, India developed specific approaches to deal with specific problems. The high ash content of Indian coal, for example, has led to regulations requiring coal-fired plants to capture and dispose of all of their ash output (typically, this is given away for free to companies that pick it up at power plants and then used it in brick or road construction). Companies wishing to use forested land had to pay the Ministry of Forests and Environment for aforestation of 2 hectares for every hectare of forest land lost. Resettlement & Rehabilitation (R&R) components associated with, inter alia, hydro and transmission projects, are mandatory items (though no less easy to implement). There is however no comprehensive treatment for environmental externalities accounting for the wide range of impacts – health, livelihoods, local and global habitats, etc. – that are associated with major electricity sector projects.

The issue of accounting for environmental externalities and incorporating those costs in the power planning process has now come to the fore in India, with a Supreme Court ruling (September 26, 2005) on a matter involving forest conservation. The Court was asked

“whether before diversion of forest land for non-forest purposes and consequential loss of benefits accruing from the forests should [the user Agency] be required to compensate for the diversion. If so, should not the user Agency be required to make payment of Net Present Value (NPV) n of such diverted land so as to utilize the amounts so received for getting back in the long run the benefits that are lost by such a diversion? What guidelines should be used for determination of NPV? Should guidelines apply uniformly to all? How to calculate NPV? Should some projects be exempted from payment of NPV?”

In its ruling the Court recognized the serious costs associated with environmental degradation, and further held that:

“the impact cannot be limited to the place of origin . . . the damage to the environment is a damage to the country’s asset as a whole.”

The Court concluded that:



a) except for projects like clinics and schools, all other projects must pay NPV, pending further review;

b) the payments are intended to fund environmental protection including regeneration of forest, and maintenance of ecological balance and eco-systems; and

c) NPV has to be worked on economic principles.

Accordingly, the Court ordered that a committee of three experts be appointed to develop a basis for calculating NPV, taking into account the various types of benefits that forests might provide, and the significant differences in the type of lands that have historically been lumped together as protected forest land in India. The commission, headed by Kanchan Chopra, is also asked to say whether any additional types of projects should be exempted from paying NPV. The commission has started its work and has held public hearings to solicit input.

The results of the Chopra Commission will influence the cost structure for generation and transmission projects going forward. The impact is likely to be particularly severe for reservoir hydro projects, which are very likely to be sited in protected areas and which could cause a large loss of forested land due to inundation. Certain transmission projects, particularly those that would link hydro projects with market areas, could also see their cost structures change depending on the methodology for calculating the NPV of forests.

This could result in unintended consequences, such as less hydro being developed and, as a consequence, an even greater reliance on coal-fired power plants to meet demand. Some, but not all, of such a rush to coal might be mitigated by increased regulation of SOx/NOx, water-pricing schemes, increased vigilance of state Pollution Control Boards with regard to suspended particulate matter (SPM) emissions, and, further down the road, regulations that affect CO2 emissions. But at the present moment, it appears that India could introduce a court-mandated system of compensation for lost forest land that might at least temporarily skew the market for development of new generation and transmission projects.

The exercise of developing a methodology for and calculating the NPV of forests has generated an additional series of questions of interest to power planners and others in India. If, for example, one should calculate the loss of forest benefits, should not one also count the externality benefits of hydro projects as well (e.g. flood control, storage for irrigation)? What about the benefits to local populations of better roads and services that might be associated with building dams in previously remote places? And if externalities are incorporated with the hydro development process, what about thermal power projects, and transmission lines? And, even if one is able to value externality costs and benefits, should all of these be internalized in the projects costs? If not, how should they be treated? And are there opportunities to create efficient markets for any of the individual components, as has been done in Europe for CO2 (note: there is already discussion of creating a carbon market in India)?

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2. SCOPE OF WORK

With this background in mind, the World Bank now wishes to commission two interrelated papers.

Paper #1 – Energy Cycle Externality Costs and Benefits: Theory and Practice in the Indian Context

This paper will be researched and written by Professor Anil Markandya. It will examine international best theory and practice for identifying and measuring energy cycle externality costs and benefits. The paper will analyze current practice in India, including the issues covered by the Chopra Commission. Cost/benefit identification and methodology should be discussed for the following technology components:

• Major hydroelectricity facilities (both run-of-river, and reservoir)

• Coal-fired power plants

• Natural gas-fired power plants

• Electricity transmission lines

• Natural gas transmission lines

The paper will not specifically focus at this time on issues raised by nuclear and non-hydro renewables. It will be of critical importance that this paper assess cost-benefit valuation issues in the context of Indian political, economic, and financial conditions, and incorporate this context within the valuation methodology developed (in other words, the paper should recognize that preservation and other values that have been developed in far richer countries cannot simply be adopted by India without considerable analysis).

The paper should cover the range of health, livelihood, local habitat and global habitat impacts that arise in the course of developing these kinds of projects. It should give equal weight to positive and negative impacts, i.e. it should not focus only on costs but should recognize and provide valuation guidance for benefits as well. The paper should also identify additional analytic work that would be needed for full application of a valuation methodology (this could include survey work, adapting existing models to serve India’s needs, etc.).

Paper #2 – Incorporating Energy Cycle Externality Costs and Benefits in India’s Power System Planning Mechanisms: Options and Recommendations

The second paper will focus specifically on India’s power generation planning process and how it should adapt in light of increased attention to externality costs and benefits. The key question to be considered is whether and how to incorporate identified cost and benefit streams within individual energy projects (implying that revenues to the project are sufficient to cover these costs, and that revenue streams from benefits are also established); which costs and benefits to recognize outside the project structure (and if so, who absorbs the costs or gains the benefits); and which costs and benefits to leave aside until some future date. The paper should examine the institutional framework within which planning now occurs and identify ways in which this framework should be adapted (this assessment to include advice on potential for creating markets for specific externalities).

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The second paper should take as a point of departure the main findings, conclusions, and recommendations of the first paper. As such, the papers are intended to be sequential and complementary; however, it is hoped that through interaction and joint participation on the field trip to India, there will be enough collaboration and consultation between the authors to enable work to be done to some degree in parallel.

It should also be recognized that some specific areas of inquiry will be of current interest to the Chopra Commission, and the consultants are encouraged to meet with the experts on this committee to the extent possible, and to be responsive to input, or requests, from them. To the extent that such interaction might necessitate changes to this TOR, this should be discussed with the Bank’s task leader.

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ANNEX II: INTERNATIONAL EXPERIENCE

1 INTRODUCTION

This Annex describes the experience of other countries/regions in the design and implementation of emission fees and tradable allowance schemes.

2 EMISSIONS FEES

Blackman and Harrington (1999) compare three countries that have implemented an emission fee programme: China (twenty different air pollutants), Poland (sixty two specific air pollutants) and Sweden (nitrogen oxides).39

China

China's first comprehensive Environmental Protection Law, passed in 1979, established a mixed regulatory system based on both emissions fees and emissions standards. The original objective of the fee system was to enforce compliance with emissions standards. Thus, polluters are required to pay a fee only on those emissions that exceed emissions standards.

To encourage compliance with emissions standards, firms that violate standards for three consecutive years are assessed a fee increase of 5 percent per year. To create incentives for newly built plants to install pollution control equipment, all fees for plants built after 1979 (the year the fee system was initiated) are doubled, and fee increases for non-compliant plants increase by 100 percent per year (instead of 5 percent per year).

Fees are set by the central government but provincial and local governments may raise them. As a result, there is substantial variation in fees across the country. Fees tend to be higher in more developed provinces and, within provinces, for old and state-owned sources.

Fees are charged on twenty different air pollutants. However, when more than one pollutant is above the permissible level, firms are required to pay fees only for the "worst case pollutant," i.e., the one pollutant that involves the largest fee payment. The national floor on fee rates in the late 1990s was roughly US$280 to $700 per tonne for particulate matter (depending on the source) and roughly US$280 per tonne for most other common airborne pollutants including SOx, NOx and CO.

The monitoring needed to assess fees is based on self-reporting, periodic auditing, and a crude monitoring technology. Each firm is required to monitor emissions concentrations daily and to report monitoring data to the local Environmental Protection Bureau (EPB). To check the accuracy of firms' reports, EPBs compare them with past reports and with reports for similar firms. They also make unannounced spot checks. Fines may be imposed for false reporting, and for interfering with inspections. However, both the probability of getting caught for underreporting and the penalty for doing so are low. In most cases, firms caught underreporting are simply required to provide an explanation.

39 See Blackman and Harrington, 1999 ibid.



Approximately $3 billion in fee revenue was collected in total between 1979 and 1995, of which 30 percent – around US$50 million a year—was paid by air polluters. Fee revenue is earmarked for investments in pollution control equipment.40

There is some disagreement about the impact of the fee system on the level of emissions. Most commentators have argued that is it unlikely that emissions fees by themselves have been responsible for improved environmental performance. They point out that fees are below marginal abatement costs for most firms, and therefore provide limited incentives to abate.41 Others have found that emissions fees are so low by comparison with marginal abatement costs that in many cases firms with abatement equipment already installed prefer to pay fees rather than incur the costs of operating their abatement equipment.42

Blackman and Harrington cite several problems with China’s fee system as it existed in the late 1990s:

the structure of the fees blunted incentives to abate. Because firms paid fees only on the "worst case pollutant" they had no incentives to abate emissions of other pollutants;

firms could recoup most of the fees they paid, ostensibly to pay for pollution control equipment. But local EPBs simply did not at the time have the resources to monitor how enterprises used those funds.

These criticisms related to the situation in the late 1990s. Recent experience in China is more encouraging. It is acknowledged that there were problems in the past with the S02 emissions tax system, reflecting:

a failure to collect fees from the worst polluters, which are combined heat and power plants located in the major cities, burning high sulphur coal;

the haphazard central allocation of coal across users, which does not provide price incentives for the use of low sulphur in the cities.

However, enforcement is now being tightened. In Shandong Province, which has significant S0 2 control problems and where the World Bank is currently developing an flue gas desulphurization (FGD) project for seven plants, there are now strong incentives for companies to retrofit FGD, since the benefits include not only the avoidance of the emissions fee (Y633/tonne S02), but projects with FGD are now allowed to levy an Y0.0125/kWh on power delivered to the grid. This is equivalent to about 5% of the typical generation price of Y0.25 – 0.35/kWh. As a result, the financial internal rate of return on FGD projects are in the range of 20 – 90%.43

40 The Law says 80 percent of fee revenue is to be used to subsidize pollution control investments by the enterprises that pay the fees and the remaining 20 percent (along with all fines) be used to fund the operations of the EPBs.

41 See Florig K., W. Spofford, M. Xioying and M. Zhong. "China Strives to Make the Polluter Pay: Are China's Market-based Incentives for Improved Environmental Compliance Working?" Environmental Science and Technology, 1995, vol. 29, no. 6, pp. 268-273; and Yang, J., D. Cao, and D. Wang. "The Air Pollution Charge System in China: Practice and Reform," in OECD 1997, Applying Market-Based Instruments to Environmental Policies in China and OECD Countries.

42 See Yun, P. "The Pollution Charge System in China: An Economic Incentive?" Working Paper, 1997. Renmin University, Beijing.

43 The author is indebted to Peter Meier for this information.

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Poland

Poland has a hybrid fee/standard instrument:

a "normal fee" is paid on all emissions below an emissions standard; and

a "penalty fee" - up to ten times higher than the normal fee - is paid on all emissions above the standard.

Emissions standards are source-specific and are set by a permitting process. Allowance applicants are required to submit an extensive environmental impact analysis and to have their applications reviewed by an independent government-approved expert.44

Fee rates are determined by Poland's national environmental ministry for sixty two specific air pollutants and seven different types of evaporative air emissions. The relative levels of the fees are based on their presumed potential to cause environmental damage. Fee rates are revised annually. In 1995, the "normal" fees were US$83 per tonne for SO2 and NOx and US$44 per tonne for particulate matter.45

Monitoring of emissions relies on self-reporting and emissions factors. Local regulators are supposed to verify self-reports. Firms are allowed to defer penalty fee payments for three to five years. Deferred payments can be waived if the firm is in compliance by the end of the deferral period.

In 1994, regulators levied US$250 million in airborne emissions fees (both "normal" and "penalty" fees), of which 90 percent (US$220 million) was actually collected. Fee revenue is distributed to a national environmental fund (36 percent), forty-nine regional environmental funds (54 percent), and 2,400 local environmental funds (10 percent). The environmental funds disburse the revenue to polluters (in the form of subsidized credit and grants) and to regulators. Revenue is also used for public-sector pollution control infrastructure such as coal washing facilities.

The impact of fees on emissions is ambiguous, in part because the imposition of fees has coincided with the tightening of CAC standards and with drastic economic restructuring. There is a consensus that "normal" fees have been set too low to have had much impact on abatement. However, according to Anderson and Fiedor, "penalty" fees do provide significant incentives to abate.

Aside from the level of the fees, there are a number of important barriers to the effectiveness of Poland's fee system, all of which are similar to problems with China's system:

monitoring and enforcement is weak;

notwithstanding extensive privatization, many large enterprises are state-owned and still operate under soft budget constraints;

the use of fee revenue to subsidize regulatory activity and pollution control investment creates perverse incentives to maintain the flow of fee revenue.

Sweden

44 Anderson, G. and B. Fiedor. 1995. "Environmental Charges in Poland," in R. Bluffstone and B. Larson, eds., Controlling Pollution in Transition Economies, 1995.

45 Anderson and Fiedor, ibid.

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In 1992, Sweden imposed a fee on emissions of NOx from electricity and heat generating plants. The fee, at US$5,200 per tonne, together with a tightening of CAC regulations, was designed to reduce emissions by 30 percent over three years.

A continuous emissions monitoring system (CEMS) is used to measure emissions for most plants. CEMS was deemed necessary because emissions of NOx depend on plant-specific operating conditions and, as a result, second-best monitoring methods can be inaccurate. The annual cost of operating and maintaining CEMS equipment has been estimated at US $39,000 per plant or US $520 per tonne of NOx abated.46

Given the magnitude of these costs, small sources were exempted from paying the fee. To avoid giving small plants a competitive advantage, the revenue from the fee is refunded to the payees. To avoid dampening the incentive effect of the fee, revenue is refunded in proportion to the amount of energy produced. As a result, plants with high emissions per unit output are net payers of fees, - while plants with low emissions per unit output are net recipients of fees.

The NOx fee has had a strong impact on emissions. Total emissions from monitored plants fell by 40 percent in the first two years of the programme. For most plants, there were no changes in CAC regulations during this time, so most of the reduction can be attributed to the emission fee.47 The fee programme generates about $80 million a year which is refunded to payees. The annual cost of administering the program has been estimated at about 0.2 to 0.3 percent of the annual revenues.48

3 ALLOWANCE TRADING SCHEMES

This section describes the experience of two of the most important allowance trading programs in the USA, the Emissions Trading Program and the Sulphur Dioxide Program; on the European Union’s Emissions Trading Scheme (EU ETS); and on the Emission-Offsets Trading Programme introduced in March 1992 to control total suspended particulate emissions from stationary industrial sources in Santiago, Chile.

The Emissions Trading Program

The Emissions Trading Program (ETP), the oldest US air allowance scheme, was grafted onto a complex CAC regime for industrial air pollution control. The ETP grew out of frustration with existing CAC regulation that, if interpreted strictly, would have prohibited the building of new sources not complying with ambient air quality standards. To accommodate economic growth under the CAC regime, the US Environmental Protection Agency (EPA) established a programme of “offsets” whereby new sources are allowed to locate in non-compliant zones if they are able to secure sufficient “emissions reductions credits’ from existing firms.

Emissions reductions credits evolved into a tradable allowance market. By 1986, the EPA had formalized rules to allow three other kinds of transactions: “netting,” “bubbles,” and “banking.” Netting allows old sources wanting to build new facilities to avoid strict new source regulations by, among other things, applying emissions reductions credits earned in old facilities to new facilities. Banking, instituted in 1979, allows firms to store emissions reductions credits for subsequent use. Bubbles, also instituted in 1979, allow two or more sources to be treated as one emissions source.

46 See Lovgren, ibid47 See Lovgren, ibid48 See Sterner, T and Hoglund, L. “Refunded Emission Payments: A Hybrid Instrument with Some Attractive

Properties,” 1998. Working Paper, Resources for the Future, Washington D.C.

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The number of trades has been far smaller than expected. By 1986 there had been about 150 bubble transactions, 2,000 offset transactions, 5,000-12,000 netting transactions, and only about 100 banking transactions.49 Moreover, most of the bubble trades were internal, that is, between firms owned by the same parent corporation.

The ETP has, according to analysts, not performed as well as expected for the following reasons:

existing CAC regulations have restricted trading. For example, the rules require that no individual trade can result in increased emissions from a participating firm. This restriction rules out multilateral trades that increase emissions of some firms but reduce overall emissions. As a result, cost savings are lower than expected;

ETP rules severely restrict new firms’ ability to trade even though they have the greatest incentives to do so, since they are subject to the strictest standards;

transactions costs for firms involved in permit trading are high, due in part to the regulatory administrative requirements. Transactions costs frequently exceed the market value of the emissions reductions credits.50

firms have limited information about the market for permits; and

firms are often reluctant to participate in the permit market because of uncertainty about future regulation.

The Sulphur Dioxide Program

While the ETP is the oldest US allowance trading programme, the Sulphur Dioxide Program (SDP) has arguably been the most successful. A centerpiece of the 1990 Clean Air Act Amendments, the Sulphur Dioxide Program was designed to reduce SO2 emissions from electricity generating plants to half their 1980 levels.

The program was implemented in phases:

during Phase I, lasting from 1995 through 1999, the 263 electricity generating units emitting the largest volume of SO2 were subject to an interim cap that required projected average emissions from these units to be no greater than approximately 2.5 pounds of SO 2 per million Btu of heat input.

In Phase II, beginning in 2000 and continuing indefinitely, the programme was expanded to include virtually all fossil-fuelled electricity generating facilities and to limit emissions from these facilities to a cap of approximately nine million tons—which implies an average emission rate of less than 1.2 pounds of SO2 per million Btu.

the final Phase II cap will eventually reduce total SO2 emission from electricity generating units to about half of what they had been in the early 1980s.

49 See Hahn, R. and G. Hester "Marketable Permits: Lessons for Theory and Practice," 1989 Ecology Law Quarterly, vol. 16, no. 2, pp. 361-406

50 See Foster, V. and R. Hahn. “Designing More Efficient Markets: Lessons from Los Angeles Smog Control,” Journal of Law and Economics, 1995, vol. 38, no. 1, pp. 19-48 (1995)

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To enforce the aggregate emissions caps in each phase, utilities are allocated a certain number of allowances, each of which entitles them to emit one ton of sulphur. These allowances are allocated to owners of affected units free of charge, generally in proportion to each unit’s average annual heat input during the three-year baseline period, 1985–87. Utilities are audited at the end of each year to ensure that their emissions have not exceeded their allowances. Breaches of allowance caps are severely sanctioned.

To reduce the cost of meeting the emission caps, utilities are permitted to trade permits with any party anywhere in the continental United States or to “bank” them, i.e., carry them forward into the next year for future use or sale. Unlike the ETP, there are no restrictions on trading on the basis of environmental or economic benefits. A small percentage (2.8 percent) of the allowances allocated to affected units are withheld for distribution through an annual auction conducted by the EPA to encourage trading and to ensure the availability of allowances for new generating units. The revenues from this auction are returned on a pro rata basis to the owners of the existing units from whose allocations the allowances are withheld.

The most remarkable feature of the SDP was the striking reduction of SO2 emissions in the first year of the program. SO2 emissions had been falling steadily throughout the 1980s and they continued to fall at about the same rate during the first half of the 1990s. But the reduction from 1994 to 1995 was far greater than anything that had been seen before. By all accounts, there can be no doubt that it was caused by the SDP.

The reason for the remarkable reduction in emissions in 1995, when the allowable emissions for that year required only a small reduction in emissions, was the availability of “inter-temporal trading” in the form of banking. The prospect of higher marginal abatement costs after 2000 made abating more than required in Phase I an appealing option for smoothing the transition to the more demanding Phase II cap. As a result, the reduction in emissions experienced in Phase I was about twice what would have been required to bring emissions below the level allowed in these years.

Inter-source or “spatial” trading also has been an important feature of the SDP. Compliance data for each year shows that about one-third of the affected units in Phase I obtained allowances from other units, either by intra-firm transfers or through purchase in the permit market, to cover emissions in excess of the allowances allocated to those units. Spatial trading has allowed sources with high abatement costs to reduce emissions less—and those with low abatement costs to reduce emissions more than under a CAC mechanism requiring uniform emissions rates, and thus has reduced the overall cost of the mandated emissions reduction.

The purchase and sale of permits by the owners of affected units has created an active and efficient market for SO2 permits, as evidenced by:

a single price for permits at any one point in time, regardless of the source of the price quote;

the high volume of inter-firm trades, as reflected in the allowance registry maintained by the EPA;

the low transactions costs associated with trading; and

the development of an active and diverse contract and futures market.

The EPA auction has also provided a transparent mechanism to reveal prices, which was very important in the early years when few private transactions were being reported.

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The cost savings due to emissions trading in the SDP clearly are substantial. On average, spatial trading during Phase I reduced annual compliance costs by $358 million a year, a reduction of about 33 percent from the estimated cost of $1,093 million a year under a non-trading regime in which each affected unit limits emissions to the number of allowances received without any trading. During the first eight years of Phase II, the combination of spatial trading and banking is estimated to reduce annual compliance costs by about $2.3 billion per year, a reduction of over 60 percent from a total of about $3.7 billion per year. Over the first 13 years of the program, the ability to trade permits nationwide across affected units and through time is estimated to reduce compliance costs by a total of $20 billion, a cost reduction of about 57 percent from the assumed CAC alternative.51

According to Ellerman, Joskow and Harrison, there are several reasons why the SDP has been successful compared with the ETP scheme:

the absence of any requirement for regulatory pre-approval of individual trades, which has limited the effectiveness of the ETP scheme;

the reduced importance of location and timing of emissions facilitated the simpler procedures that made emissions trading successful - the reduction in aggregate, cumulative emissions was more important than the precise pattern of reductions at individual sources;

the baseline for the scheme was clearly defined as an aggregate level of emissions, whereas in the ETP it was defined as emissions reduction above and beyond complex existing legal requirements;

in contrast to the ETP which has been overlaid on existing regulation, the SDP was designed to substitute for existing regulation;

the requirement to verify actual SO2 emissions using a continuous emissions monitoring system (CEMS) played an important role in gaining support for the trading scheme and in building market confidence.

Notwithstanding its success, several aspects of the SDP raise concerns about the appropriateness of permit trading programs for a country like India.

The success of the SDP depends critically on a high level of monitoring, enforcement, and administration. The SDP market in the US is viable and robust because participants know that they will receive full credit for emissions reductions and that emissions limits implied by allowances will be strictly enforced. The effective monitoring and enforcement that underpins the program is due to investments and institutions that would be difficult to replicate India.

All plants that participate in the program are required to install CEMS, flow monitors and opacity monitors. Among the reasons for this provision were fears that if an emissions factor approach was used, utilities would receive credit for installing scrubbers but might not operate them, and also a recognition that the viability of the permit market would depend on the credibility of enforcement.52 The average

51 See Ellerman, D, Joskow P. L, and Harrison D. Jr. “Emissions Trading in the U.S. Experience, Lessons, and Considerations for Greenhouse Gases”, Discussion Paper, Pew Center on Global Climate Change, May 2003

52 An emissions factor approach calculates emissions using a common factor (e.g., tonnes of CO2 per tonne of coal) times the tonnes of coal used times the oxidation factor of the coal used.

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annual cost of continuous emissions monitoring (including operating and annualized capital costs) is approximately $124,000 per generating unit).53:

The enforcement of allowances, which is largely taken for granted in the US, depends on effective regulatory institutions; and programme administration is carried out by firms and by specially-created regulatory organizations costing several millions of dollars a year.

Finally, incremental administrative costs associated with the programme (i.e., administrative costs incurred by both regulators and firms above and beyond costs incurred in conventional CAC system) are significant. They include the costs of keeping track of all trades via the Permit Tracking System; holding yearly auctions; buying permits; and trading permits.

European Union’s Emissions Trading Scheme (ETS)54

The EU’s CO2 installation-based cap and trade tradable allowance scheme began operating in January 2005. All 25 Member States of the European Union take part in the scheme, with over 11,000 installations representing about 40% of the EU’s emissions of CO2 covered. Five separate sectors are covered: electricity and heat generation; petroleum refining; the ferrous metals industry; the cement, glass and brick industry; and the pulp, paper and board industry.

Phase I of the ETS, which lasts for the three year period from 2005 to 2007, was designed to be a “pilot” phase, with CO2 as the only greenhouse gas (GHG) included in the market. “Credits” derived from Clean Development Mechanism (CDM) projects are eligible, with the exclusion of nuclear, large hydro and LULUCF (land use, land use change, and forestry) projects. Emission targets in Phase I, were based on the national allocation plans of individual member states. Allocations of allowances were based on actual emissions over a recent period in the past. Allocations were generally set at a relatively high proportion of historical emissions. The European Commission mandated that at least 95% of allowances were to be allocated free of charge, rather than, for example, auctioned off.

Phase II, to run for the five-year period beginning 1 January 2008, may expand the scheme to include all six GHGs; and the covered sectors may be expanded to include aviation, chemicals, aluminum, and transport. Member States will be required to allocate at least 90% of the allowances free of charge in Phase II.

The scheme works by requiring each participating installation to surrender sufficient EU emission allowances (EUAs) at the end of each annual compliance period to cover the installation’s CO2 emissions. “Banking” of emissions allowances is effectively allowed between years in Phase I.55 Penalties in Phase I for non-compliance amount to €40/tonne of “excess” CO2 and €100/tonne in Phase II. Installations must not only pay the penalty for exceeding their allowances. They must also surrender extra allowances the following year. The penalty for non-compliance is therefore onerous.

EUAs have been traded since 2004 through brokers (in an over-the-counter market (OTC)) and on various exchanges across Europe. Thus far, the OTC market has been more important: more than 60% were 53 Schmalensee R., Joskow P., Ellerman A.D., Montero J.P., and Bailey E. : “An Interim Evaluation of Sulfur Dioxide

Emissions Trading,” Journal of Economic Perspectives, 1998, vol. 12, no. 3, pp. 53-68.54 This section is based on the analysis in Harrison, David Jr.: European Carbon Markets and Implications for a US

Carbon Constrained Future, June 2006 (available at http://www.nera.com/Event.asp?e_ID=2857)55 1 EUA = 1 tonne of CO2 emissions.

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traded over the counter in 2005. Allowances are traded both spot and forward. Derivatives – options, spreads – are also traded. More than 1 million tonnes of CO2 are now traded each day, at a value well in excess of what was traded on the US SO2 market in its early years. But it is fair to say that the market is still maturing. Significantly, uncertainties over future caps and allocations are inhibiting investment decisions in abatement.

As the chart below shows, the price of allowances has been quite volatile since trading of significant volumes began in early 2005. The high allowance prices which emerged in 2005 were a surprise to some analysts, given the relatively relaxed caps imposed and the expected prices before the scheme began of around €10/tonne. A peak price of more than €30/tonne CO2 was reached in May 2006, just before the price collapsed to €12/tonne when it became apparent that actual emissions in 2005 in a number of countries, particularly Germany, were well below allocations.

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Chart 1: ETS Allowance Prices

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Announcementof German NAP

Announcements by France and other countries of low emisssions in 2005

Source: Harrison D. Jr. op. cit.

The EU’s ETS shares many common elements with the US cap-and-trade programs described earlier. It represents a shift from a legal-engineering to economic approach; it has the basic architecture of a cap-and-trade programme and, while the allocation mechanism is contentious – in the sense that allocations are based on a ‘business-as-usual’ basis and are made free of charge, it does work. But there are differences between the EU and US schemes: allocations are based upon recent emissions, rather than benchmarked, which means that allocations are heterogeneous rather than standardized; the new entrant reserves and closure provisions are different between the two schemes; and there are more long-term uncertainties in the ETS, particularly about what will happen after 2012, than in the US schemes.

While there are a number of key issues surrounding the ETS that still need to be addressed (including the nature of future caps and their allocation and how to address the problem of windfall gains made as a result of the free allocation of credits), Harrison concludes that the ETS has been a major accomplishment for the European Commission and Member States; that it is now promoting cost-effective CO2 reductions; and that it shows that a multi-country continent-wide emissions trading regime can be set up successfully.

Santiago, Chile56

The city of Santiago in Chile suffers critical air pollution problems. The concentration of particulates constantly exceeds the established ambient standards, even though overall emissions are not especially

56 This section is based on Montero J.P., Sanchez J.M., and Katz R., “A Market-Based Environmental Policy Experiment in Chile,” mimeo, July 2000.

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high. Efforts have been made to reduce emissions over the last fifteen years, based on the use of emission standards for industrial, domestic and mobile sources. Additionally, for stationary point sources, an emission offsets trading scheme was introduced in 1992.

Under this system current sources that have a daily emission capacity below their individual cap can sell the difference to other sources, existing or new, who want to reduce emissions by less than required by their specific cap. Trading is carried out on a one-to-one basis. New point sources are required to offset all their emissions. A staggered reduction requirement beginning with 25% in 1993 and reaching 100% in 1997 was established, i.e., by the end of 1997 new sources should have offset all their emissions.

At the end of 1992, there were 1,334 point sources, emitting a total of 9.1 tonnes per day of particulates. The main processes were industrial combustion and thermal processes. Local heat production using solid, liquid and gaseous fuels in boilers was also a relevant source of emissions. There was also one large coal powered electric utility that alone accounted for approximately 14% of total emissions. By 1998, when the offset system was supposed to be fully operative, there had been a significant reduction in emissions from fixed point sources by comparison with 1992. By then there were 1,167 fixed point sources emitting a total of 4.3 tons per day.

These numbers might suggest that the offsets trading scheme has been successful. Unfortunately, according to Montero et al., the reduction in actual emissions was largely the result of emission standards that were easy to comply with, both for new and old sources. Existing sources switched from coal and wood to cleaner liquid fuels. And from 1997 natural gas became available in the city. It was convenient and economic for most of the boilers and some other processes to switch to gas.

Furthermore, analysis indicates that the market created under the programme has performed poorly owing to:

regulatory uncertainty. The first problem faced by the environmental authorities when the scheme was introduced in March 1992 was the urgent need to develop a database of existing sources and historical emissions. Emission rights were allocated to all existing sources, implicitly recognizing the existence of historical rights. However, when such an initial allocation of emission rights is made, the number of existing sources and their size must be known precisely. This was not the case with the offsets trading scheme. A significant number of new sources appeared, creating great uncertainty around the scheme and the possibility of trading. This uncertainty led the authorities to concentrate on the quantification of sources and emissions; consequently, no offsets were authorized during the first three years of the scheme.

high transaction costs. Transaction costs are high because the procedures under which the system operates are far from simple; and because no formal market exists for the emission rights.

poor enforcement. Because of limited resources, enforcement of the scheme has been weak. During the early years, enforcement problems occurred with regard to both the concentration standard and the accounting of emission rights that each source must hold to cover its emissions. Reconciling rights and emissions remains a challenge.

thin market. The market in rights has been thin, partly because potential sellers are unwilling to sell because of uncertainties that they will be able to buy back capacity rights later, if needed; and partly because, without the ability to monitor total suspended particulates (TSP) emissions on a

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daily basis, the environmental currency has become a “permanent right” instead of a “daily right,” significantly reducing the liquidity of the market.

limited programme scope. Industrial processes, which account for more than 50 percent of particulates originating from stationary sources, are not within the scope of the scheme. This exclusion creates market uncertainty because these sources may be included at some point in the future and enter the market as net buyers or net sellers, affecting expectations about future market prices. Also their exclusion reduces the liquidity of the market.

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