Greenhouse Gas Mitigation in the Power Sector: Case Studies From India ESM237 4= S F! 1i i xS s '' .. X . 9 ,'S C f _ e ie:; - , Energy Sector Management Assistance Programme Clk A in Report 237/01 February 2001 JOINT UNDP t WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) PURPOSE The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) is a special global technical assistance program run as part of the World Bank's Energy, Mining and Telecommunications Department. ESMAP provides advice to governments on sustainable energy development. Established with the support of UNDP and bilateral official donors in 1983, it focuses on the role of energy in the development process with the objective of contributing to poverty alleviation, improving living conditions and preserving the environment in developing countries and transition economies. ESMAP centers its interventions on three priority areas: sector reform and restructuring; access to modern energy for the poorest; and promotion of sustainable energy practices. GOVERNANCE AND OPERATIONS ESMAP is governed by a Consultative Group (ESMAP CG) composed of representatives of the UNDP and World Bank, other donors, and development experts from regions benefiting from ESMAP's assistance. The ESMAP CG is chaired by a World Bank Vice President, and advised by a Technical Advisory Group (TAG) of four independent energy experts that reviews the Programme's strategic agenda, its work plan, and its achievements. ESMAP relies on a cadre of engineers, energy.planners, and economists from the World Bank to conduct its activities under the guidance of the Manager of ESMAP, responsible for administering the Programme. FUNDING ESMAP is a cooperative effort supported over the years by the World Bank, the UNDP and other United Nations agencies, the European Union, the Organization of American States (OAS), the Latin American Energy Organization (OLADE), and public and private donors from countries including Australia, Belgium, Canada, Denmark, Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden, Switzerland, the United Kingdom, and the United States of America. FURTHER INFORMATION An up-to-date listing of completed ESMAP projects is appended to this report. For further information, a copy of the ESMAP Annual Report, or copies of project reports, contact: ESMAP c/o Energy and Water The World Bank 1818 H Street, NW Washington, DC 20433 U.S.A. Greenhouse Gas Mitigation in the Power Sector: Case Studies From India February 2001 Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) Copyright C 1999 The International Bank for Reconstruction and Development/THE WORLD BANK 1818 H Street, N.W. Washington, D.C. 20433, U.S.A. All rights reserved Manufactured in the United States of America First printing February 2001 ESMAP Reports are published to conmunicate the results of the ESMAP's work to the development community with the least possible delay. The typescript of the paper therefore has not been prepared in accordance with the procedures appropriate to formal documents. Some sources cited in this paper may be informal documents that are not readily available. 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ESMAP encourages dissemination of its work and will normally give permission promptly and, when the reproduction is for noncommnercial purposes, without asking a fee. Contents Contents .............. iii Units of Measurement ..................v A. Introduction ................1 Genesis of the Work ..............1 Basic Information on the Case Study States . .................................................................2 (i) Bihar ..................................................................2 (ii) Andhra Pradesh ..................................................................2 B. The Concept and Scope of a Global Overlay ......................................................................2 Concept .................................................................2 Scope .................................................................3 C. Methodology .....................................................................3 Overview .................................................................3 Load Forecasts ..................................................................4 (i) Bihar ..................................................................4 (ii) Andhra Pradesh ..................................................................5 (i) Business as Usual (BA U) Scenario .................................7................................7 (ii) Reform Scenario ..................................................................7 a. Bihar ..................................................................8 b. Andhra Pradesh ..................................................................9 (iii) Greenhouse Gas (GHG) Mitigation Scenario .............................................................9 a. Bihar ................................................................. 10 b. Andhra Pradesh ................................................................. 12 Modeling the Power Systems ................................................................. 14 (i) The Load Module ................................................................. 15 (ii) The Production Cost Module ................................................................. 15 (iii) The Report Module ................................................................. 17 D. Results ..................................................................... 17 GHG Emissions Under Bau and Reform ................................................................. 17 Incremental Impact of Individual GHG Reduction Options: GHG Mitigation Option Supply Curves ............................................................... 18 Incremental Impact of Combinations of GHG Reduction Options: GHG Mitigation Scenarios .................................................................................................................................................. .21 E. Conclusions ..................................................................... 24 Annexes Annex 1: Load Forecasts ..................................................................... 29 Annex 2: Supply-Side Options ..................................................................... 31 Annex 3: Demand-Side Options ...................................................................... 37 Annex 4: Local Emissions ..................................................................... 39 iii Tables Table 1: Price and Income Elasticities by Sector in Bihar under BAU and Reform .....................4 Table 2: BAU and Reform: Forecasts of Energy (GWh) and Maximum Demand (MW) for Bihar, 1997-2015 ................................................................5 Table 3: BAU and Reform: Price and Income Elasticities for AP by Sector .............. .................6 Table 4: BAU and Reform: Forecasts of Energy (GWh) and Maximum Demand (MW) for AP, 1998-2018 ...............................................................6 Table 5: Estimated Characteristics and Outcome of DSM Program in Bihar under Reform, 2000-2015 ................. ...............................................9 Table 6: Salient Characteristics and Outcome of DSM Program for High-Efficiency Refrigerators in Bihar under GHG Mitigation Scenario, 1997-2015 ............................................................... 11 Table 7: Salient Characteristics and Outcome of DSM Program for Urban Lighting in Bihar under GHG Mitigation Scenario, 1997-2015 ................... ...................... 12 Table 8: Main Features of DSM Lighting Program in AP under GHG Mitigation Scenario, 1999-2015 ............................................................... 13 Table 9: Main Features of Integrated Agricultural DSM Project for AP under GHG Mitigation Scenario, 1999-2015 ............................................................... 14 Table 10: Carbon Emissions Factors for Liquid Fuels ......................................................... 16 Table 11: Methane Emissions from Coal Mining Activities ............................................... 16 Table 12: GHG Emissions and LOLP under BAU and Reform: AP and Bihar .............. 18 Table 13: GHG Mitigation Scenarios for Bihar ............................................................... 20 Figures Figure 1: Bihar - GHG Mitigation Option Supply Curve - Individual Options (Group A) ............................................................... 18 Figure 2: Bihar - GHG Mitigation Option Supply Curve - Individual Options (Group B) ............................................................... 19 Figure 3: Andhra Pradesh - GHG Mitigation Option Supply Curve - Individual Options ............................................................... 21 Figure 4: Bihar - GHG Mitigation Option Supply Curve - Combination Scenarios Group A ............................................................... 22 Figure 5: Bihar - GHG Mitigation Option Supply Curve - Combination Scenarios Group B ............................................................... 23 Figure 6: AP - GHG Mitigation Option Supply Curve - Combination Scenarios ................. 24 iv Units of Measurement At the time the work was conducted, the exchange rate between the US$ and Indian Rupees (Rs.) was: US$1=Rs. 43 In India, it is common to express numbers in terms of crores and lakhs, where: 1 crore = IO million (107) 1 lakh= 100,000 (105) v Greenhouse Gas Mitigation In The Power Sector: Case Studies From India A. Introduction Genesis of the Work Case studies were completed for two states in India in 1998, as part of an activity on India: Environmental Issues in The Power Sector (EIPS). The activity was undertaken by the World Bank, on behalf of the Government of India (Gol), through the Ministry of Power (MoP). Liaison with MoP on day-to-day matters was facilitated by MoP's Energy Management Centre (EMC). The activity was supported by funding from the UK Department for Intemational Development (DFID), through the Joint World Bank/UNDP Energy Management Assistance Programme (ESMAP), and by the World Bank's South Asia Region. A final report was issued as ESMAP Report No. 205/98 in June 1998. The Administrative Staff College of India (ASCI) and the Sone Command Area Development Agency (SCADA), with the assistance of Metallurgical & Engineering Consultants (India) Ltd. (MECON), carried out the case studies in Andhra Pradesh (AP) and Bihar, respectively. The case studies identified the enviromnental impacts of alternative options for the development of the power sector in those states. In particular, they estimated the atmospheric emissions of particulate matter (PM) and oxides of sulphur and nitrogen (SO2 and NO,, respectively), as well as the production of ash and the preemption of land. But the case studies gave only limited attention to greenhouse gas (GHG) emissions and global warming issues, by tracking CO2 and including some preliminary analysis of the possible effects of a carbon tax. A detailed discussion of the methodology used in the case studies, including a description of the set of analytical tools and the decisionmaking process that were developed for the case studies under EIPS, was published in India: Environmental Issues in The Power Sector, Manual for Environmental Decision Making, ESMAP Report No. 2 13/99 in June 1999. The present study extends the previous work through applying a global overlay, i.e., by (i) including GHG emission impacts; (ii) including GHG mitigation analysis; and (iii) estimating the incremental costs of GHG reduction. The global overlay was conducted in accordance with the World Bank's Guidelines for Climate Change Global Overlays (Environment Department Paper No. 047, Climate Change Series, February 1997). It was funded by the World Bank's Global Overlay Programme, with help from Denmark, Norway, ESMAP, and the World Bank's South Asia Region. The AP case study was again conducted by ASCI, while MECON had the responsibility for Bihar. The two consulting teams worked under common terns of reference that were provided by the World Bank. However, the teams were given discretion in developing their methodology for the case studies, wherever the differences in approach did not compromise the I 2 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India comparability of the results. The task managers were Robin Bates (EIFEG) and Mudassar Imran (SASEG), who also prepared this synthesis report. Basic Information on the Case Study States AP and Bihar were chosen as case studies for EIPS because they offered a good cross- section of the issues and options related to the environmental impacts of power generation in India. (i) Bihar Bihar is one of the poorest states in India, and the Bihar State Electricity Board (BSEB) is in a particularly precarious financial and technical condition. It experiences heavy financial losses and requires burdensome state subsidies; its thermal plants are old and poorly maintained; and transmission and distribution (T&D) losses, estimated at nearly 40%, are high. About 50% of electricity sales are to heavy industry; 21% to agriculture; and 11% to domestic consumers. The power sector depends heavily on coal, with more than 90% of power generation coming from that fuel. The state is also comparatively remote from alternative domestic sources of energy, although it is reasonably well placed to import energy from Bangladesh and Nepal in the longer term and it has significant biomass potential. (ii) Andhra Pradesh In contrast to Bihar, AP has a wider range of supply options for its power sector: apart from coal (54%), they include hydropower (43%) and small amounts of nuclear (from the central sector), wind, and solar energy. Furthermore, its long coastline and good ports offer better possibilities for importing fuels, including LNG and coal. Agriculture accounts for some 45% of electricity sales; industry 36%; and domestic consumers 15%. The financial, technical, and operational performance of the AP State Electricity Board (APSEB) has been better than that of BSEB, although (as in Bihar) T&D losses (estimated at 32%) are still high. B. The Concept and Scope of a Global Overlay Concept The World Bank routinely carries out energy sector work in its client countries, often in association with restructuring efforts. Such sector work analyzes the implications of pursuing existing policies under a business-as-usual (BAU) scenario as well as changes that are associated with energy sector reform and restructuring. These analyses will cover economic, financial, and technical issues, but not necessarily environmental impacts. The objective of a global overlay is to add to these analyses-or "overlay" them with-a systematic process for assessing the GHG implications of BAU and reform; and to design Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 3 and cost a new scenario, known as the GHG Mitigation Scenario, to reduce GHG emissions. Scope Usually a global overlay covers the energy sector for an entire country. It calculates GHG emissions for the production, transmission, distribution, and consumption of both imported and indigenous fuels, i.e., the related emissions are calculated wherever they occur in the world; and its scope is limited to carbon dioxide (CO2), methane (CH4), and nitrous oxide (N20). In this work, only two states within India were covered, although it should be noted that the population in each state is greater than that of many entire countries: the population of Bihar is about 100 million, and that of AP about 70 million. The work also limited its scope to the power sector in AP and Bihar, although it traced back down the entire fuel chain to calculate GHG emissions caused by the production, transmission, and distribution of all fuels used by the power sector, both in India and overseas. However, it did estimate the contribution of the power sector to total GHG emissions in each state. In Bihar, it was found that the power sector contributed 4.9 million metric tons (Mt) of carbon equivalent in 1995-96 out of a total of 16.6 Mt, i.e., 30%. Most of the carbon emitted from the power sector (4.7 Mt) came from coal burning. In AP, for the base year 1996-97, the total emissions of carbon equivalent were estimated at 18.4 Mt, to which the power sector contributed 9.2 Mt or 50% of the total. C. Methodology Overview The implementation of the global overlays required load forecasts and power development plans (investment program and operating regime) for both the BAU and the Reform scenarios. The GHG emissions associated with those load forecasts and power development plans were then estimated. Next, a set of GHG mitigation options was identified and appropriate GHG mitigation scenarios formulated. The difference between GHG emissions and total power system costs under the BAU, Reform, and GHG Mitigation scenarios were compared; and the end result was an estimate of the incremental cost of GHG reduction. In general, that result is important for the World Bank's clients, because it could form the basis for (i) financing from the World Bank and the Global Environment Facility (GEF); (ii) the creation of opportunities under joint implementation or carbon trading arrangements; and (iii) the clearer identification of the "win-win" opportunities presented by energy pricing and energy sector reform. It is emphasized that no attempt was made to link the Reform scenario with any particular institutional or managerial model in either AP or Bihar, nor to patterns of ownership. Rather, the global overlays proceeded on the basis of reasonable assumptions and judgements about the likely economic and technical consequences of reform, in terms of the growth rate of the economy, electricity tariffs, and the efficiency of the power system. 4 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Load Forecasts The two case studies projected the unconstrained energy (GWh) and power (MW) demand over a 20-year planning horizon for the BAU and Reform scenarios, broken down by the main consumer categories, viz.: * Domestic * Commercial * Low tension (LT) and high tension (HT) industry and * Agriculture. Econometric modeling, combined with judgements based on experience in other countries, was used to estimate the income and price elasticities for each consumer category. Given specific assumptions and projections about income growth and likely tariff changes for each consumer category, it was possible to forecast sales of energy and maximum demand. (i) Bihar In the case of Bihar, BAU load forecasts were made for both low-growth and high-growth assumptions about Gross State Domestic Product (GSDP), maintaining the existing sectoral shares constant over the planning period. The projected GSDP growth rates are in Annex I.1. As far as electricity prices are concerned, it was anticipated that tariff increases would be modest and confined to the residential and agricultural sectors, where tariffs are currently set well below costs. The assumptions are in Annex I.2. The sectoral income and price elasticities are those derived for EIPS (India: Environmental Issues in The Power Sector, ESMAP Report No. 205/98, June 1998, Table 2:14), Teproduced in Table 1. Table 1: Price and Income Elasticities by Sector in Bihar under BAU and Reform1 Sector Income Elasticity Price Elasticity Residential 1.75 -0.30 Commercial 1.27 -0.26 Industrial 1.5 -0.20 Agriculture 1.5 -O.202 1. Econometric techniques were used to estimate the price and income elasticities. Time- series data for 1985-86 through 1993-94 were pooled over 19 states in India for each consumer sector. The study considered two types of linear models, one with a lagged effect of electricity price on the explanatory variable and another without the lagged effect. Since the available data covered nine years, a lag model of only one year could be considered to estimate the long-run price elasticities for each sector. However, the estimates for income and short-run price elasticities were made using an unlagged functional form. Source: "Elasticities of Electricity Demand in India," TERI, New Delhi, March 1997. 2. The Agriculture price elasticity is (-0.10) under Reforms. Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 5 For the purposes of the global overlay, in approaching the Reform scenario, it was assumed that power sector reform would start in Bihar in the year 2000 and be completed over a seven-year period. It can be expected that reform would induce faster growth rates for GSDP, under both low-growth and high-growth assumptions, as depicted in Annex I.3. Furthermore, under reform, it should be possible to increase the tariff level, to allow the utility to eam an acceptable return on equity (taken as 16%). However, bearing in mind the experience so far in reforming states such as AP and Haryana, it was assumed that there would be constraints on adjusting the tariff structure. In particular, agricultural tariff increases are limited, going from the existing level of Rs. 0.15/kWh to Rs. 1.50/kWh from 2003 to 2006 and reaching only about 50% of the supply cost by 2007. Accordingly, the tariffs of other sectors were adjusted so as to achieve a 16% return on equity, as shown in Annex I.4. Finally, the sectoral income and price elasticities are kept the same under Reform as in the BAU scenario, except for agriculture, which is reduced to reflect the expectation that an integrated agricultural demand-side management (DSM) program would already have been implemented as part of the reform package (see Table 1). This program would include the metering of agricultural pumpsets and a variety of technical measures-see the discussion of Power Development Plans, Section (ii)a below. The combined results of these different assumptions underlying the load forecasts for Bihar are summarized in Table 2. Table 2: BAU and Reform: Forecasts of Energy (GWh) and Maximum Demand (MW) for Bihar, 1997-2015 Scenario 1997 2015 Growth Rate (% p.a.) BAU Low Growth MW 2,374 5,751 5.0 GWh 12,205 27,473 4.6 BAU EHigh Growth MW 2,374 6,937 6.1 GWh 12,205 32,900 5.7 Reform Low Growth MW 2,374 4,471 3.6 GWh 12,205 25,635 4.2 Reform High Growth MW 2,374 5,988 5.3 GWh 12,205 34,500 5.9 (ii) Andhra Pradesh In the case of AP, load forecasts were based on a single projection for the growth rate of GSDP, maintaining the shares of each consumer category constant over time. The GSDP 6 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India growth rate assumptions for BAU and Reform are in Annex I.5. As far as electricity tariffs are concemed, it was anticipated that there would be no real price increases under BAU, with the tariff being merely adjusted for inflation. The specific assumptions for tariff increases made for the Reform scenario were as follows: for the industrial sector, the nominal tariff was capped by the assumed nominal cost of self-generation (about Rs. 4.4/kWh at 1998 prices). The LT industrial tariff was assumed to decline from the present Rs. 3.3/kWh to about Rs. 3.0 /kWh by 2007 and remain constant thereafter. The agricultural tariff was assumed to increase to 50 percent of supply cost by 2008 (about Rs. 1.5 /kWh at 1998 price levels). The domestic tariff was increased to Rs. 2.25 /kWh (1998 price levels) by 2007 and kept constant in real terms thereafter. The commercial tariff was increased to Rs. 4.3/kWh by 2001, and then allowed to decline to Rs. 3.8 /kWh by 2007 and kept constant thereafter. The sectoral income and price elasticities, sunmmarized in Table 3, were taken from the analytical work carried out for the World Bank's ongoing First AP Power Sector Restructuring Project and EIPS. In the AP global overlay, no explicit program of DSM was envisaged under Reform, beyond the energy conservation induced by tariff increases. The combined results of these different assumptions underlying the load forecasts for AP are summarized in Table 4. Table 3: BAU and Reform: Price and Income Elasticities for AP by Sector Sector Price Elasticity Income Elasticity Domestic -0.4 0.33 Commercial -0.4 1.01 Agriculture -0.2 1.58 LT Industry -0.3 0.49 HT Industry -0.3 1.06 Table 4: BAU and Reform: Forecasts of Energy (GWh) and Maximum Demand (MW) for AP, 1998-2018 Scenario 1998 2018 Growth Rate (% p;a.) BAU MW 5,581 13,840 4.7 GWh 37,060 91,900 4.7 Reform MW 5,581 25,546 7.9 GWh 37,060 169,630 7.9 Power Development Plans In principle, the supply-side candidate options available for the power development plans covered the following fuels in Bihar and AP: coal, gas, petroleum products, nuclear, and renewables. For Bihar, the information on supply-side options is summarized in Annexes Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 7 11.1 and 11.2; and for AP in Annexes 11.3 and 11.4. All the costs shown are the estimated economic costs of the supply options, using the results of the earlier work published in EIPS. Also, energy efficiency options are available to reduce the generation requirements at the busbars, i.e., DSM (energy conservation) and T&D loss reduction programs. In practice, all these options had to be carefully adapted to the conditions in each state, under the BAU, Reform, and GHG Mitigation scenarios. (i) Business as Usual (BAU) Scenario The power development plans for Bihar and AP under the BAU scenario are based on actual plans, known projects, and judgments about the investments that are likely to take place in the sector in the absence of reform. The supply options are selected, therefore, from a highly restricted menu. The resulting power development plans do not reflect least-cost solutions to meet the anticipated demands, but rather evaluations of what is feasible, given the financial situation of the sector. Inevitably, due to the poor financial situation in both the case study states, new capacity under BAU is insufficient to meet growth in potential demand. In Bihar, the power development plan under the BAU scenario includes only the emergency rehabilitation of existing coal plants (Patratu, Barauni, and Muzaffarpur) and some extensions (2x2lOMW) at the Tenughat coal-fired plant run by the National Thermal Power Corporation (NTPC) in 2003 and 2005. Otherwise, the purchases of power from the central sector (NTPC) remain constant at the current level. Given the inevitable supply shortages, the capacity of captive power plants is assumed to increase to 50% of the incremental HT industrial and commercial loads. In AP, a similar approach was used by allowing the power development plan to include only certain committed coal-fired plants, known to be under implementation through the year 2005. Captive generation is assumed to increase to meet 60% of the shortfall in energy. No investment in T&D loss reduction occurs under BAU in either AP or Bihar. (ii) Reform Scenario The power development plans for the Reform scenario, in contrast to BAU, are offered more supply options, because the financial situation of the sector is assumed to improve. Consequently, power shortfalls are gradually eliminated and all power requirements eventually met. In that sense, the power development plan can be constructed based on a least-cost solution, although the range of supply options made available is limited to known plans (if any) and the options that are judged to be feasible (on economic, financial, and political grounds) in a newly reforming system. Hence, some options are still constrained in amount or excluded entirely from the Reform scenario, as discussed below. 8 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India a. Bihar In Bihar, starting in the year 2000, the target under Reform is to eliminate curtailments over a seven-year period. At present, BSEB draws only half of its entitlements (in energy terms) from NTPC as a consequence of its financial distress (about 3,700 GWh in 1996). Under the reform scenario, tariff increases would help to restore the sector's financial strength, and power supplies could progressively increase from NTPC plants, until the sector reaches its full entitlement of 6,500 GWh by 2004. Rehabilitation of BSEB's thermal plants (Patratu, Barauni, and Muzzafarpur) could commence immediately, targeted at remedying the most serious environmental and operational problems: plant availability could increase from the present levels of 18-25% to 50%. However, the old 50 MW units are assumed to be retired gradually by 2004. In line with current practice in reforming states in India, and to offset the uncertainty related to hydro plants, open-cycle combustion turbines (OCCT), fuelled by naphtha, are forced into the expansion plan for peaking purposes: the first is commissioned in 2005. Bihar has substantial quantities of coal to supply extensions to the existing thermal plants (at Patratu, Tenughat, and Muzzafarpur) and new base-load power stations (e.g., Katihar, Chandil, and Nabinagar). For convenience, a generic coal plant, based on the characteristics of Nabinagar, was used to represent new candidate coal-fired stations (Annex 11.1). Preliminary screening analysis demonstrated that neither nuclear power nor clean-coal technologies, such as IGCC or PFBC, would compete with Nabinagar: they were therefore not candidate options under Reform, but were considered as GHG mitigation candidates. Similarly, Bangladesh gas and coal washing were not made available, because the former hinges on decisions outside the power sector and the latter would require a much broader set of reforms across the energy sector: they were analyzed only as GHG reduction candidates. As far as renewables are concerned, there is considerable uncertainty over Bihar's remaining major hydro projects (Annex II.2). The largest of these is the 710-MW Koel- Karo project, which has recently been given to the National Hydro Power Corporation (NBPC) for implementation. This project involves the resettlement of some 50,000 people in a tribal area, as a result of which little progress has been made over the past 20 years. The project is therefore omitted from the Reform case and considered for GHG mitigation. The most attractive of the other large hydro options is Kadwan, a 450-MW project that could be built at the Kadwan irrigation scheme. Power generation would be incidental to irrigation, and it is considered as a candidate powerhouse-only project for Reform. A large number of potential mini-hydro schemes exist in Bihar and were considered as candidate options for Reform. However, the import of electric power from hydro plants in Nepal, like Bangladesh gas, will depend on decisions outside the power sector; solar photovoltaics (PVs) are still uneconomic for grid supply; and the use of bagasse appears unlikely to be taken up under Reform: these supply options were therefore retained only for GHG mitigation. The energy efficiency measures introduced under Reform cover DSM and T&D loss reduction. Specifically, the rehabilitation of the T&D network is expected to reduce Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 9 technical losses from the existing level of 28% to 18% by 2004, while nontechnical losses fall from 9% to 4% by 2004. The DSM program in the Bihar Reform scenario is based on the Integrated Agricultural DSM Project proposed for the state of AP. It combines improvement of the power distribution system, by converting low voltage (LV) feeders to high voltage (HV) feeders; the introduction of automated load control, to facilitate the supply of nonagricultural customers; and the installation of high-efficiency pumpsets and associated pipes and valves. Due to the substantial investment requirements, the program is implemented in a phased manner: 15% of total customers are covered in 2000, and an additional 30%, 45%, 60%, 75%, and 100% of customers are covered in 2001, 2002, 2003, 2004, and 2005, respectively. Starting in 2005, all customers are assumed to be covered under this scheme for the total study period. At the same time, the number of customers grows by 1% p.a. The main characteristics and outcome of the DSM program are in Table 5. Table 5: Estimated Characteristics and Outcome of DSM Program in Bihar under Reform, 2000-2015 Parameters 2000 2002 2007 2012 2015 Total number of Customers ('000s) 276 282 295 311 321 DSM Coverage (%) 15 45 100 100 100 Energy savings (GWh) 181 553 1290 1356 1397 Cost of energy savings (Rs./kWh) 0.85 Note: The cost of energy savings is defined as the ratio of the present value (PV) of the cost of energy saved to the PV of energy saved. b. Andhra Pradesh In AP, all plants currently scheduled for construction or under consideration were allowed under the Reform scenario. These plants consume either naphtha or coal, as shown in Annex 11.5. Additionally, the candidate options in Annex 11.3 cover the Jurala hydroelectric plant; generic conventional coal plants, located at the pit-head or near load centers and using domestic coal (from Singareni or Talcher) or imported coal; clean-coal technology (PFBC); LNG, naphtha and nuclear plants; and plants using various forms of renewable energy, such as wind, bagasse, solar, and mini-hydro-. The possibility of generating power using refinery residues was also explored. In terms of the energy efficiency measures introduced under Reform in AP, T&D losses were assumed to drop from the current level of about 32% to 15%, although no explicit program was implemented for DSM. (iii) Greenhouse Gas (GHG) Mitigation Scenario The power development plans for the GHG Mitigation scenario in Bihar and AP essentially force in the options that were constrained or excluded under Reform, or even rejected under Reform as not part of the least-cost solution. These options are forced in so that their effectiveness as GHG mitigation options can be explicitly examined. In most cases, it is expected that special policies or initiatives would normally be required to 10 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India overcome the obstacles to their implementation. Initially, each option is forced into the Reform development plan individually, to assess its cost per metric ton of GHG emissions mitigated. This cost is defined as the change in total power system costs, relative to the Reform scenario, divided by the reduction in GHG emissions, relative to the Reform scenario. In a second stage, combinations of individual options are formed, to evaluate the cost per metric ton of alternative mitigation scenarios. The GHG mitigation options considered in Bihar are shown in Annex II.6 and those for AP in Annex 11.7. a. Bihar As already discussed under the options provided for the Reform scenario in Bihar, nuclear power, Bangladesh gas, and coal washing were not included as candidates for the Bihar Reform scenario, but instead were considered as GHG mitigation options. Nuclear power is considered a candidate because of the absence of GHG emissions, despite other obvious environmental problems and considerable uncertainty surrounding the costs. For Bangladesh gas, it is assumed that the gas would be imported by pipeline and burned in combined cycle gas plants at Calcutta. An allowance has been made for the additional cost of transmission lines and for transmission losses from Calcutta to Jamshedpur. Two alternatives were considered in estimating the sensitivity of the cost of GHG reduction with respect to the cost of gas imports. For the coal washing option, the costs were taken from the EIPS (ESMAP Report No. 213/99, p. 103). In terms of renewables, as explained above, solar PVs, bagasse, the large Koel-Karo hydroelectric project, mini-hydro, and imports of hydroelectric power from Nepal were retained as supply options only for GHG mitigation. Although solar PVs are still uneconomic for grid supply, they have obvious environmental benefits, especially from a GHG reduction viewpoint. On the expectation that further substantial technical progress can be anticipated to reduce their capital costs, their low operating costs may bring total costs per kWh down to a competitive level in the future. The global overlay for Bihar therefore took two alternatives, with the capital costs of solar PVs at about US$5/Wp in one case (in line with current technology), and the capital costs reduced by 50% in the other. The abundant supply of sugarcane in the Ganga plains of North Bihar and in eastem Uttar Pradesh make bagasse available in large quantities. However, the economic use of this solid residue from sugarcane crushing will be limited by its value in alternative uses, like paper manufacture, and the cost of transportation, given its low calorific value. In face of the uncertainties about supply and costs for power generation, the total likely available capacity was restricted to two units of 210 MW (a net capacity addition of 380 MW), which were analyzed under two alternative assumptions using differing costs. To assess the impact of the Koel-Karo project as a GHG reduction measure, it was forced into the plan in 2010, after the Kadwan project. For the purposes of the global overlay, two tranches of mini-hydro projects were considered, based upon projections made by the Bihar Hydroelectric Power Corporation (BHPC). Only the first was offered in the Reform scenario, as the cost figures projected for the second tranche were regarded as much more uncertain. The second tranche was Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 11 therefore forced into the development plan as a GHG mitigation option, with a higher capital cost than the first tranche. For Nepal hydro, the global overlay collected information on projects that had been identified by the Government of Nepal for future development and that might be suitable for export to India. The results are in Annex 11.8. Out of the identified projects, Kaligandaki-A and Kaligandaki-Il were identified as the most likely sources of power imports from Nepal to reduce GHG emissions. The total capacity imported was restricted to a maximum of 500 MW until 2015. The additional transmission line costs were included in the total project costs and allowance was also made for additional transmission losses. The option was considered under two alternatives, to reflect different possible timings for Kaligandaki-II. PFBC and IGCC were selected as the possible clean-coal technologies for GHG emission reduction. While the thermal efficiencies and environmental benefits of both of the processes are comparable, the capital costs of PFBC are lower at present. However, both alternatives were examined under the GHG mitigation scenario, by forcing all new Bihar coal-based units to incorporate either IGCC technology from 2004 onward, with the costs shown in Annex 11.1, or PFBC technology, from the same date, but with the capital cost per kW being 20% lower than for IGCC. Finally, more aggressive energy efficiency measures were introduced under the GHG Mitigation scenario than under Reform, both for DSM and T&D loss reduction. Further rehabilitation of the T&D network was envisaged to bring technical losses down to 13% by 2010; while nontechnical losses fall from the existing 9% to 4% by 2004. After reviewing the work done under EIPS, taking into account administrative and financial constraints, an additional DSM program was designed for the Bihar GHG Mitigation scenario, adding energy-efficient refrigerators and urban lighting by compact fluorescent lamps (CFL) with electronic ballast. The salient features of the program are in Tables 6 and 7. Table 6: Salient Characteristics and Outcome of DSM Program for High- Efficiency Refrigerators in Bihar under GHG Mitigation Scenario, 1997-2015 Parameter 1997 2002 2007 2012 2015 Participants ('000s) 7.1 104.5 542.4 1068.1 1340.2 Energy Savings (GWh) 1.3 19.1 99.3 195.5 245.3 Benefitto Consumers (Rs. (-) 2.12 8.08 226.67 481.95 612.19 Million) Benefit to Utility (Rs. Million) 0.90 22.49 27.45 64.74 83.47 Cost of Energy Saved (Rs./kWh) 0.40 Note: The cost of energy savings is defined as the ratio of the present value(PV) of the cost of energy saved to the PV of energy saved. 12 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Table 7: Salient Characteristics and Outcome of DSM Program for Urban Lighting in Bihar under GHG Mitigation Scenario, 1997-2015 Parameter 1997 2002 2007 2012 2015 Participants ('OOOs) 11.51 32.14 88.67 209.31 274.38 Energy Savings (GWh) 2.3 6.3 17.5 41.2 54.1 Benefit to Consumers (Rs. Million) 2.25 8.01 44.55 108.06 140.95 Benefit to Utility (Rs. Million) Cost of Energy Saved (Rs./kWh) 0.59 Note: The cost of energy savings is defined as the ratio of the pTesent value (PV) of the cost of energy saved to the PV of energy saved. b. Andhra Pradesh The broad range of candidate plants considered in AP for the GHG Mitigation scenario was similar to that in Bihar, although some differences are worth mentioning. These arise partly from differences in the particulars of the situation, the quality of available information, and the methodology used. As in Bihar, nuclear power, clean-coal technologies (IGCC and PFBC), and renewable energy options such as wind and solar PVs were found to be too expensive to form part of the least-cost solution for Reform. Again as in Bihar, coal washing could not reasonably be included in the Reform development plan, because it would require a much broader set of reforms, outside the power sector. These options were therefore forced into the development plan for the GHG Mitigation scenario in AP. Plant rehabilitation, the Jurala hydroelectric scheme, and bagasse generation were considered under the GHG Mitigation scenario because it was judged unlikely that they would be taken up without special initiatives. The performance of power plants in AP is for the most part better than in Bihar, so that a general program of rehabilitation is unnecessary. However, the particular case of Kothagudam A was selected for detailed study to represent the possible GHG reduction benefits of plant rehabilitation. The Jurala hydroelectric scheme served as a proxy for other medium-sized hydroelectric power stations. Cogeneration from bagasse may not be large in AP, and in any case has not been developed, because the sugar industry has preferred to supply such, wastes to the paper manufacture industry. In contrast to Bihar, available evidence for AP on mini-hydro was not encouraging and for reasons of cost these schemes were regarded as interesting for GHG reduction rather than as candidates for construction under Reform. Several mini- hydro projects are under consideration and even under construction, and generation is available from mini-hydro schemes, especially during periods of peak agricultural demand. However, one of the most formidable obstacles faced by irrigation canal drop schemes is the need for coordination with the state irrigation departments. LNG was considered under Reform but it was judged more realistic to set limits on the total capacity that might be installed, given the need for associated infrastructure at the LNG terminals and likely political concerns over extending too far India's dependence on a relatively new source of imports. The constraint was removed only to investigate the impact of increased LNG usage on GHG emissions. Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 13 The option of using refinery residues for power generation was not considered in the Bihar global overlay. As mentioned under Reform, it was given consideration in AP, due to strong interest in establishing a plant at Visakhapatnam. According to the detailed work carried out under the AP case study for EIPS, this option would use refinery residual fuel oil having a gross calorific value of 7400 kcal/kg. Power could be generated using conventional steam generators, Fluidized Bed Combustion Technology (FBC), or the Integrated Gasification and Combined Cycle System (IGCC). The main benefits would come from reducing local pollution, but GHG emissions would also be reduced. From an efficiency and environmental perspective, IGCC, with a plant efficiency of about 43%, scores over the other technologies. The costs for power generation would be sensitive to the location and it is difficult to arrive at generic generation costs. With the costs shown in Annex 11.3, which incorporate the data available to ASCI from its special study of refinery residues, the option would not be picked up under the Reform scenario. Hence, it was forced into the development plan for the GHG Mitigation Scenario, with residual fuel oil being used for power generation with the IGCC process. Although the AP global overlay had no explicit DSM program under Reform, two ambitious sets of measures were provided for GHG mitigation. Detailed information for both was drawn from earlier work identified by the Integrated Resource Planming (IRP) study of APSEB, conducted by consultants in 1996 and funded by USAID. The first set of measures relates to lighting, including lighting for urban, municipal, commercial, and rural situations. The main features are summarized in Table 8 and the details are shown in Annex III.1. The second set is based on the Integrated Agricultural DSM Project for AP, which also informed the Bihar Reform Scenario, as described above. The main features are summarized in Table 9 and the details are shown in Annex 11.2. To complement these energy efficiency measures, the AP GHG Mitigation scenario postulated a more far- reaching T&D loss reduction program than under Reform, to bring down losses further, from 15% to 10% by 2010. Table 8: Main Features of DSM Lighting Program in AP under GHG Mitigation Scenario, 1999-2015 1999 2002 2005 2010 2015 Urban Lighting 4.3 48.1 125.3 160.9 43.9 Municipal Lighting (Sodium 0.2 3.7 12.6 21.6 9.8 Vapor) Municipal Lighting 0.5 8.0 26.8 46.1 20.9 (Fluorescent) Commercial Light (Electronic 2.7 50.1 233.4 484.4 259.6 Ballast) Commercial Lighting (CFL) 1.5 26.0 100.5 52.0 52.0 Fluorescent Lamp Standards 49.7 366.0 774.3 1292.0 2080.7 Rural Lighting 6.1 97.0 269.0 475.0 456.1 Total Savings (GWh) 65 598.9 1541.9 2532.0 2923.0 14 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Modeling the Power Systems In order to examine the implications of these power development plans for GHG emissions, a computational tool is needed to: * Simulate the operating regime of the BAU scenario; * Construct and simulate the least-cost solution to meet the unconstrained demand of the Reform scenario, albeit limiting the least-cost solution to a subset of the full range of potential options represented by any known plans and the options that are judged to be feasible; * Calculate emissions of GHG for both BAU and Reform; * Simulate the incremental impact of individual GHG reduction options; and * Simulate the incremental impact of selected GHG mitigation scenarios (i.e., using combinations of options to achieve target reductions in GHG emissions). Both of the case studies relied heavily on a least-cost power system expansion planning software called A/SPLAN (designed by Analytical Solutions - A/S - of Bayport, New York). A/SPLAN is based on the WASP model (the Wien Automatic Simulation Package, produced by the International Atomic Energy Agency) and employs a dynamic programming algorithm. Table 9: Main Features of Integrated Agricultural DSM Project for AP under GHG Mitigation Scenario, 1999-2015 1999 2002 2005 2010 2015 Number of Pumpsets (Millions) 1.791 1.901 2.017 2.227 2.459 Energy Savings (GWh) 0 132 955 4,304 4,788 Capital Costs (Rs. Million) 0 1,860 5,579 5,114 0 Operating Costs (Rs. Million) 0 28 201 908 1,010 Misc. Benefits' (Rs. Million) 0 -62 -446 -2,009 -2,235 Total costs (Rs. Million) 0 1,826 5,334 4,013 -1,225 NPV2 (Rs. Million) 16947 Notes: 1. Miscellaneous benefits include: reduced motor rewinding costs, deferred purchase of pumps, and reduced transformer and Power Factor correction costs. 2. A 12% discount rate was used to calculate the net present value (NPV). AISPLAN has three primary modules, viz.: * A load module * A production cost module, and * A report module. Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 15 (i) The Load Module The basic inputs for the load module are the hourly time series data for energy, according to the season (rainy, dry, winter) and consumer category (residential, commercial, industrial, and agricultural). A/SPLAN then constructs stylized annual, seasonal, and daily load duration curves (LDCs), which feed directly into the production cost module. (ii) The Production Cost Module The production cost module carries out a probabilistic simulation to minimize the total discounted system costs of the power system over a given time horizon, using a 12% discount factor. It combines the scheduled and forced plant outage rates with the LDCs to calculate the Loss of Load Probability (LOLP) and the Energy Not Served (ENS). LOLP is a measure of power system reliability and is defined as the probability that load shedding will occur in any given year. It takes a value between zero and one. It is possible to specify LOLP and A/SPLAN will optimize the power system to achieve that particular level of reliability. For example, in Bihar, LOLP was set at 0.05 (5%), meaning that load shedding would occur on average in 438 hours per year, compared with an LOLP that currently exceeds 40%, or 3504 hours per year. Alternatively, as in AP, the analyst can specify a cost per unit of ENS and the model will select a value for LOLP to optimize the power system, i.e., by balancing the cost of increasing the reserve margin against the savings in cost of a consequent reduction in the amount of ENS. In AP, LOLP also now exceeds 40%, and the cost of ENS was fixed at ten times the average tariff for the purposes of the global overlay. It is interesting to note that this assumption led to the same result as in Bihar, i.e., an LOLP of 5%. The key results of the system simulation are estimates of system production costs (for operation, maintenance, and investment); the consumption of different fuels (based on inputs for the heat rates and unit costs of the fuels); and undiscounted emissions of GHG for the simulated power sector. A/SPLAN can be run using either financial or economic costs. In these two global overlays, economic costs were used for all investments and fuels, i.e., they exclude taxes and add back subsidies. Furthermore, they include estimates of the costs necessary to meet environmental standards in the electric power and coal mining sectors and to that extent internalize the costs of local environmental impacts. The emissions of GHG for the simulated power sector are calculated directly from the consumption of different fuels, as estimated by A/SPLAN, using emissions factors. The CO2, CH4, and N20 emissions factors used in the two case studies are based on the IPCC default values, as reported in the World Bank's Guidelines for Climate Change Global Overlays (Environment Department Paper No. 047, Climate Change Series, February 1997), Exhibits 4-6 and 4-9, except for the burning and mining of coal, where the coefficients were adapted to fit the particular conditions in India. The emissions factors used for CO2 attributable to coal burning in the power sector, the single most important source of GHG emissions in the power sectors in Bihar and AP, were 25.9 metric tons of 16 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India carbon per TJ in Bihar and 26.3 metric tons of carbon per TJ in AP. The IPCC default emissions factors for C02 from other fuels are in Table 10. Generation of electricity from captive power generation and the corresponding emissions, which increase under BAU and decrease under Reform, respectively, were calculated outside AISPLAN, by estimating the amount of captive generation, in KWh, and applying the same emissions factors. Methane emissions associated with the mining of coal as well as emissions during postproduction stages also had to be calculated outside A/SPLAN, for both domestic and imported coals. A/SPLAN estimates the amount of coal-based power generation, in GWh, from imported and domestic coal separately. From these, it is possible to derive estimates of the quantity of imported and domestic coal required by the power sector. Methane emission factors for domestic coal mining in India are summarized in Table 11, according to the type of mining employed. Most of the coal used in Bihar and AP is produced from open-cast or Degree I underground mines. It is anticipated that this will remain true in the future, and further assumed that the same factors can be applied to imported coal. The case studies ignored the emissions of methane associated with the production of liquid fuels because of their low contributions to the overall methane generated. Table 10: Carbon Emissions Factors for Liquid Fuels Product Carbon fraction (metric tons/TJ) Natural Gas 15.3 Diesel Oil 20.2 Residual Fuel Oil 21.1 Naphtha 20.0 Source: IPCC Guidelines for National GHG Inventories, Vol. 3: GHG Inventory Reference Manual, cited in the World Bank's Guidelines foT Climate Change Global Overlays (Enviromnent Department Paper No. 047, Climate Change Series, February 1997). Table 11: Methane Emissions from Coal Mining Activities Mining Category Methane Emissions (m3/metric ton) During Mining Post Mining Open Cast 1.00 1.09 Underground Degree I 1.00 0.09 Degree II 10.00 1.07 Degree HI 23.03 3.50 Note: "Degree" is a measure of "gassiness" in the mine, with higher degrees representing higher concentrations and emissions of inflammable gas. Source: The Climate Change Agenda-An Indian Perspective, TERI, 1993. Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 17 Further adjustments were required outside A/SPLAN to combine the three different types of GHG emissions and express them as CO2 or carbon equivalent (using weights reflecting their relative global warming potential). For the purposes of the analysis, the GHG potential of N20 was considered to be 320 times that of CO2, while the GHG potential of CH4 was taken to be 24.5 times when compared to C02, using the 100-year time-frame recommended by the IPCC (see the World Bank's Guidelines for Climate Change Global Overlays, Environment Department Paper No. 047, Climate Change Series, February 1997, Exhibit 3-2). The AP results were expressed in terms of C02, but this is easily converted to carbon, using the molecular ratio of CO2 to carbon, i.e., 44/12. (iii) The Report Module The report module prepares and prints out the detailed results for every year in the planning horizon. Most importantly, it includes for each plant in the system, and for the system as a whole, the generation (in kWh); emissions (SO2, C02, N20, PM and CG14); consumption of each fuel; and operating and investment costs. It also reports, for the overall system, the reserve margin and LOLP. D. Results GHG Emissions Under Bau and Reform Table 12 summarizes the results of the GHG emissions analysis for BAU and Reform in AP and Bihar, and the LOLP that results for the given demand projections and permissible supply options. The main conclusion from Table 12 is that BAU cannot be applied as a meaningful baseline scenario for GHG mitigation analysis in these two case studies. While GHG emissions are lower under BAU than under Reform in AP and in Bihar (under the high-growth demand projection), the expected energy served is also substantially less. LOLP increases dramatically under BAU in both states: from 42% in 1998 to nearly 100% in 2015 in AP; and from 41% in 1996 to 73% and 86% in 2015 under the low-growth and high-growth scenarios, respectively, in Bihar. Under Refonn, LOLP improves to a reasonable value of less than 5%. The massive expected failures in supplying electric power that would take place under BAU conditions could not be regarded as an acceptable GHG control policy in India or elsewhere. Hence, only the Reform scenario was selected as a baseline reference point for all GHG reduction analysis, especially when calculating the incremental costs. 18 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Table 12: GHG Emissions and LOLP under BAU and Reform: AP and Bihar Scenario Equivalent Carbon LOLP in 2015 (Mt) (%) AP BAU 323.5 99.6 Reform 520.1 4.2 Bihar BAU (LG) 100.7 73.4 BAU (HG) 101.7 86.4 Reform (LG) 91.1 4.5 Reform (HG) 105.9 3.9 Incremental Impact of Individual GHG Reduction Options: GHG Mitigation Option Supply Curves In light of the above conclusion, the individual GHG reduction options are initially evaluated against the Reform scenario by inserting them, one at a time, into the optimal power development program for Reform and assessing the impact on undiscounted GHG emissions and the present value of total system costs, using a 12% discount rate. For any specific option, the ratio of the change in undiscounted GHG emissions to the change in the present value of total system costs provides a preliminary screening value for the cost- effectiveness of that option, expressed as a cost per metric ton of carbon or per metric ton of CO2. The results of the individual options considered for Bihar are in Figures 1 and 2; and those for AP are in Figure 3. Figure 1: Bihar - GHG Mitigation Option Supply Curve - Individual Options (Group A) 3000 1z 2000. o Nepal Hydro o o 'F*,0. Mini Hydro 5000 0000 15000 20000 25000 30000 r&D -2000 Kt of Catbon Reduced Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 19 In the case of Bihar, the set of possible options was divided into two groups: Group A included the options that were judged more likely to be achieved; and Group B considered some alternative assumptions, that were mutually exclusive, and regarded as less likely to be achieved. The Groups are identified in Table 13. The GHG mitigation option supply curve for Group A is in Figure 1; and that for Group B in Figure 2. These supply curves rank the options, from the lowest to the highest cost, by the cost per US$ per metric ton of carbon equivalent reduced. The high-growth assumptions for the growth of GSDP were used throughout the analysis of GHG mitigation options in Bihar. Figure 2: Bihar - GHG Mitigation Option Supply Curve - Individual Options (Group B) 4000 Coal 3000 Wash W) 2000 t_ l D3 P. Voltaic LU 1000- 2 Nepal Hydro KoelKao O 500 s 0 15000 20000 25000 30000 35000 40 00 Bagass Mini Hy -1000 _ T&D -2000 Kt of Carbon Reduced The ranking of options in Figure 1 shows that the following have a negative cost and would therefore be classified as "win-win": T&D rehabilitation beyond the degree assumed under Reform; mini-hydro; the additional DSM measures beyond Reform; and bagasse. The remaining options reduce GHG emissions at a cost: imported Nepal hydro; clean coal (PFBC); imported Bangladesh gas; coal washing; and solar PVs. The change in the ranking of options in Figure 2 corresponds to (i) the introduction of more optimistic assumptions about the costs of PFBC compared with IGCC, which bring the costs of clean coal below Nepal hydro, and of solar PVs, which move ahead of coal washing; and (ii) forcing in nuclear capacity, along with the Koel Karo hydroelectric plant, which appear in the upper-middle portion of the supply curve. The positions of bagasse and Bangladesh gas do not change in the ranking, despite the lower costs taken in Figure 2. In the case of AP, the options are ranked in Figure 3 from the lowest to the highest cost, expressed in US$ per metric ton of CO2 reduced, rather than carbon (as in the Bihar results), as follows: rehabilitation of the existing coal-fired plant at Kothagudam; DSM 20 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India measures to increase the efficiency of lighting; T&D rehabilitation (representing a further reduction from the level of losses assumed under Reform); bagasse; DSM in the agriculture sector; Jurala hydro; LNG (with additional quantities made available, compared with Reform); the use of refinery residues; a program of mini-hydro plants; nuclear capacity; wind; PFBC; solar PVs; and, finally, coal washing. Those options with a negative cost in Figure 3 are again classified as "win-win," because they permit a simultaneous reduction in GHG emissions and a savings in total system costs. The other options, with a greater cost than Jurala in the ranking, reduce GHG emissions but at a cost, and therefore had to be forced into the plant program. Table 13: GHG Mitigation Scenarios for Bihar Group - A Group - B Mini Hydro Mini Hydro (second tranche forced in 2002 with 30% (same as Group A) capital cost increase) Koel Karo - not included Koel Karo (forced in 2010) Nepal Hydro Nepal Hydro (force in Kaligandaki A in 2000 and (force in Kaligandaki A in 2000 Kaligandaki - Kaligandaki - II in 2007) II in 2003) Clean-Coal Technology Clean-Coal Technology (all plants have IGCC from 2004) (all plants have PFBC from 2004 but capital cost falls by 20%) Bangladesh Gas Bangladesh Gas (gas price US$4.50/MBTU) (gas price USS4.00/MBTU) DSM DSM (efficient lighting & refrigerators) (efficient lighting & refrigerators) Coal washing Coal washing (washed coal from 2001 onward) (washed coal from 2001 onward) Bagasse Bagasse (first tranche 2004, second tranche 2007 with (full amount in 2004 with no cost penalty) 20% increase in fuel cost) Nuclear - not included Nuclear (capital cost US $ 2,000/kW) Photo-voltaic Photo-voltaic (force in 200 MW in 2004 with capital cost of (capital cost of Rs. 100,000/kW: force in 200 Rs. 200,000/kW) MW in 2004; 2d tranche of 200 MW in 2012) T & D Rehabilitation T & D Rehabilitation (losses fall to 13% by 2010) (losses fall to 13% by 2010) Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 21 Figure 3: Andhra Pradesh - GHG Mitigation Option Supply Curve- Individual Options GHG Mltigation Option Supply Curve Coal Washing Photovoltaic 0 Q 15- PFBC 1! ~~~~~~~~~~~~~~~~~Mini Hydel Win DSM-Agriculture Ref Rsd .. Fr . . . . . . ..... .... t , ............ .......... ..... % Jurala Hydro -5 - Lighting T&D Rehab Kothagud im Rehab -25- O 100 200 300 400 500 600 700 800 Million Tons of C02 Reduced Incremental Impact of Combinations of GHG Reduction Options: GHG Mitigation Scenarios Based on the preceding screening analysis, combinations of options were put together in the case studies to form GHG mitigation scenarios. The combinations were selected according to the cost-effectiveness ranking of the options, as measured by cost per metric ton of carbon reduced. In forming the combinations, the goal was to achieve reductions of roughly 10%, 15%, and 20% in GHG emissions. The results could not be exact, due to discontinuities between the combinations (i.e., "lumpiness" was encountered), so that sometimes the goal was overachieved and sometimes underachieved. The results for Bihar are in Figures 4 and 5 and those for in AP are in Figure 6. Before discussing these results, it is convenient to convert the cost data into consistent units, so that comparisons between the two case studies can be drawn more easily. The following presentation is therefore expressed in US$ per metric ton of carbon reduced, converting CO2 to carbon, using the molecular ratio of CO2 to carbon, i.e., 44/12. It is useful to note that the GEF guidelines for evaluating projects suggest that cost-effective projects (options) would typically mitigate GHG emissions for approximately US$10/metric ton of carbon or less (see the World Bank's Guidelines for Climate Change Global Overlays, Environment Department Paper No. 047, Climate Change Series, February 1997, Exhibit 1-1). 22 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India In the case of Bihar, relative to the reform scenario, it is possible to achieve a 10% reduction in GHG emissions and reduce total system costs at the same time. The Group A options would include: DSM, T&D, mini-hydro, and bagasse (Figure 4). Logically, that combination should become part of the reform scenario itself, once proper incentives for its implementation have been put in place. In the second step, the movement from a 10% to a 17% reduction in GHG emission occurs at an incremental cost of US$6.4 per metric ton of carbon, using the option of Nepal hydro. Finally, in the third step, GHG emissions can be cut by 20% at an incremental cost of US$10.4 per metric ton of carbon, using clean-coal technologies (PFBC) and the opportunity to import Bangladesh gas. Figure 4: Bihar - GHG Mitigation Option Supply Curve - Combination Scenarios Group A 1000 800 600 2D0/ Roduction 17% Reduction + Clean Coal B.Gas i 200 -Nel - 0 S=I 15000 100 15000 20000 25 0 0 *Z; -200- 0 0 -400- -6D0 1 0% Reduction -800 T&D + Mni Hydro + OSM + Bapase Cumulative C Reduction(Ktonnes) The Group B options in the first step (giving a reduction of 10% in GHG emissions) are the same as in Group A (Figure 5). However, the much more favorable assumptions made about the likely technical progress of clean-coal technology bring in clean coal along with hydro from Nepal at a cost of US$8.1 per metric ton of carbon in the second step. Both options are in relatively abundant supply when selected, so there is a discontinuity in the supply curve, which jumps from 10% to 20%. At the third step, the cost-effectiveness of GHG mitigation becomes marginal: as GHG emissions are cut from 20% to 25%, incremental cost rises to US$1 1.8/metric ton of carbon, and is realized with a large hydro plant (Koel Karo) and nuclear power. Although not shown in Figure 5, Bangladesh gas could have been used in place of Koel Karo at much the same cost. Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 23 Figure 5: Bihar - GHG Mitigation Option Supply Curve- Combination Scenarios Group B 600 25% Reducfion 400 ~~~~~~~~~20% Reduction tNudear + Koel Karo 400- + CDean Coal + Nepal Hydro 200 - 5 0 5000 100 )O 15000 20000 25000 30 00 -200 -400 l -600 10% Reducton -800 T&D + Mini Hydro + DSM . Bagasse Cumulatve C Reduction (Kt) In the case of AP, relative to the Reform scenario, it is again possible to achieve a 10% reduction in GHG emissions and reduce total system costs at the same time, i.e., it is a "win-win" option (Figure 6) .Again, the combination relies on priority DSM measures and more far-reaching T&D rehabilitation. The rehabilitation of existing coal-fired plant is also one of the first-tranche measures in AP. Although it is not clear from the curve, bagasse could be part of the first tranche measures, if the goal is to go beyond a 10% reduction in GHG emissions. For convenience, bagasse was clubbed with the second step in the supply curve, which moves from a 10% to a 15% reduction in GHG emissions, and includes the use of further DSM, along with renewables and cleaner fuels (LNG). The incremental costs increase, although modestly, and are still less than US$5 per metric ton of carbon. If the goal is to achieve GHG emissions reductions beyond 15%, the cost increases are more significant. Incremental costs rise to more than US$25 per metric ton of carbon, to get a 20% reduction in GHG emissions (adding refmery residues and mini- hydro to the combination) and US$150 per metric ton of carbon to go beyond 20% (as it becomes necessary to bring in nuclear, wind, and clean-coal technologies). These costs are well beyond the benchmark figure of US$10 per metric ton of carbon used by the GEF. 24 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Figure 6: AP - GHG Mitigation Option Supply Curve- Combination Scenarios 45.0 350~ Key jGMSI Reforms+ Koth. Rehab +DSM Lighting + TD Rehab' 22.8 % Re In. 35.0 |GMS 2 GMS 1 + Agri-DSM+Bagasse+Jurala+LNG IGMS 3 GMS 2 + Refinery Residue+MiniHydel GMS 4 GMS 3 + Nuclear + Wind + PFBC 25.0 0 1:t5.0 O o0 19.6 % Redn. a - ~~~~~~~~~~~~~~~GMS-3 c., 5.0 G GMS-2 15.3 % Redn 10 200 250 300 350 400 40 -5.0O GMS1 t10.3 % Redn. C02 Reduced (Million Tons) E. Conclusions Methodology The construction of GHG mitigation option supply curves for individual GHG mitigation options was an important first step in applying the methodology of the global overlays in Bihar and AP (Figures 1, 2, and 3). These curves permitted the initial screening of the individual options and assisted the analysts in developing GHG mitigation scenarios. However, the costs per metric ton of carbon reduced for the individual options in Figures 1, 2, and 3 will typically underestimate the cost of GHG mitigation, because they do not allow for the system effects when options are added cumulatively. System effects cause the overall impact of a combination of options on GHG reduction to differ from the arithmetical sum of the impacts of the individual options considered separately. The interactions arise when the options are taken cumulatively because the background generation mix changes as further options are added and the dispatch of all plants in the system may be altered. In the case of Bihar, a good example of the system effects of a power plant is the Koel Karo hydroelectric scheme. Koel Karo was added to the system (along with nuclear power) rather than Bangladesh gas in the final step of Scenario B (Figure 5) because it was shown to be more cost-effective than Bangladesh gas as an individual option (see the ranking in Figure 2). However, the benefits of Koel Karo are vitiated because some of the energy is dispatched ahead of energy generated from the clean-coal-based power plants Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 25 that were installed earlier in the sequence. As a consequence, it was found that essentially the same results could have been achieved by adding Bangladesh gas in place of Koel Karo, even though the cost of the former was 80% higher when taken as an individual option. There is a further important conclusion related to the issue of system effects. A cumulative addition of options may be appropriate to achieve successive increments in GHG reduction over time, e.g., from 10% to 20% to 25%. However, a different investment program may be appropriate if it is decided at the outset that the goal is to achieve a large reduction, say 25%, rather than a succession of incremental reductions in GHG emissions. There may be no point in installing a succession of thermal plants based on clean-coal technologies if it will be necessary subsequently to install a large hydro scheme to meet the required (significant) target. The clean-coal plants might become redundant. In the case of AP, system effects are also apparent in the final step of Figure 6. The cost of GHG mitigation per metric ton of CC2 is substantially higher for the addition of nuclear power, wind, and clean coal than the cost of each option individually (see Figure 3). First, by adding these options cumulatively, total C02 equivalent is reduced by only 61 million metric tons compared with the arithmetic sum of 77 million metric tons for the three options taken individually. The reason is that a substantial impact has already been made on the CO2 equivalent of the system by the previous introduction of measures such as DSM, T&D rehabilitation, hydro, and bagasse. Second, the reserve margin of the system must be increased to maintain the required value of LOLP, given the variable nature of wind energy, so that the capital costs of the combination are multiplied. Results According to the results of these two global overlays, the options identified could reduce GHG emissions by 20% in Bihar and AP (i.e., by about 1 million and 19 million metric tons annually, respectively) at an incremental cost of roughly US$8 to US$10 per metric ton of carbon equivalent in Bihar; and about US$26/metric ton of carbon equivalent in AP. The costs of the individual measures vary widely: * Even if power sector reforms are implemented, there are likely to be unexploited opportunities to reduce GHG emissions and total system costs in tandem. The analysis shows that more aggressive DSM measures, additional T&D loss reduction, and a focus on renewables such as bagasse are highly cost-effective or even "win-win." Ideally, these opportunities would be taken up under Reforms as a matter of good business practice, once the incentive system has been rationalized, but realistically, special policy measures may be required in the short- and even medium-term if GHG emissions are to be brought down as a matter of priority. * Mini-hydro is "win-win" in Bihar and offers the low GHG mitigation cost of US$4/metric ton of carbon equivalent in AP and should therefore be examined closely as a GHG reduction strategy. However, it is case-specific and its potential 26 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India in practice is probably small relative to the size of the goals for GHG reduction that are likely to face most countries. * Large and medium hydro schemes may also be effective, with costs of US$13.4/metric ton of carbon for Koel Karo in Bihar and minus US$8.4/metric ton of carbon for Jurala in AP. But their feasibility depends very much on specific circumstances and the social and environmental costs they create may be much more significant than recognized here. * For Bihar, imported energy supplies from Nepal and Bangladesh promise to yield significant environmental benefits. Obviously prices would have to be negotiated that would make them sufficiently attractive, from an economic and financial viewpoint, to be adopted in a reformed power system. The Bihar case study suggests that Nepal hydro imports would be the higher priority, based on existing information. For AP, imported LNG needs special mention. Although total system costs increased when LNG was added to the Reform scenario, the effect was marginal. The results are very sensitive to the assumptions made about capital and operating costs. The sensitivity analysis indicates that, for relatively small reductions in these costs, the LNG option would displace imported coal in the Reform scenario, reducing total system costs and thereby joining the list of "win- win" options. The cost of LNG as a fuel choice for carbon reduction was estimated at less than US$ 1/metric ton of carbon equivalent. * Clean-coal technologies, such as PFBC and IGCC, seem to be among the more costly options at present for GHG emission reduction, especially in AP (nearly US$33/metric ton of carbon equivalent). But the more favorable assumptions for PFBC used for the Group B options in Bihar show that clean-coal technologies may well have a significant future role to play in seeking larger reductions of GHG emissions because they could offer a way to use the substantial availability of domestic coal more efficiently. * Solar PVs, wind, and coal washing seem to be the most expensive carbon reduction options, with costs exceeding US$100/metric ton of carbon equivalent for solar PVs (in both AP and Bihar), US$22/metric ton of carbon equivalent for wind (in AP), US$85/metric ton of carbon equivalent for coal washing in Bihar, and nearly US$170/metric ton of carbon equivalent for coal washing in AP. While these options are not cost-effective for reducing GHG emissions, they certainly have other advantages, such as offering a decentralized power supply and a reduction of local pollution, such as ash. * The work done in the course of the AP case study for EIPS and the AP global overlay strongly suggests that the use of refinery residues for power generation is worth exploring further. Preliminary analysis indicated that it might be economical at most refinery locations in India, and a number of existing and proposed refineries have prepared feasibility reports and identified joint venture Greenhouse Gas Mitigation in the Power Sector: Case Studies from India 27 partners. At the time of the case study, there were proposals to set up almost 3,500 MW of capacity, using residual fuel oil in India. It was expected that some percentage of this would be located in AP. While the associated environmental problems are not well documented, sulphur dioxide and NO2 emissions could be a problem. In terms of GHG emissions, the AP global overlay placed refinery residues very high in the cost-effectiveness ranking, at US$3.3/metric ton of carbon equivalent. * Nuclear power appears to be a relatively unattractive carbon reduction option on cost grounds. Although the specific cost of carbon reduction for nuclear power as a single option, in both Bihar and AP, was about US$10/metric ton, it appeared in the mitigation scenarios only when very substantial target reductions were envisaged. Furthermore, both global overlays clearly recognized that the economic and environmental case for nuclear power would be further undermined if further allowance is made for the costs of handling nuclear fuel and disposing of nuclear waste fuel and the risks of nuclear accidents. Finally, both case studies found a close correlation between the local and global benefits of the options. The emissions of local pollutants (NO,, SO,,, and PM) decline almost unifonnly in step with GHG emissions, as seen in Annex IV. 1 for Bihar and Annex IV.2 for AP. The decline reflects the steady drop in coal consumption in both power sectors as carbon reduction proceeds (Annex IV.3). The only exception, which is very minor, occurs in Bihar's Group A combination: when GHG emissions are reduced from 17% to 20%, NO, emissions go up by 0.2%. Although at first sight the result seems counter-intuitive, it is another of the system effects mentioned in the previous section, combined with the choice of time horizon and discounting. The reason is that the GHG mitigation options displaced new low-NO, thermal units and, in some instances, more energy will be dispatched from existing higher-NO, thermal units in the short term. If the time horizon for discounting local pollutants were extended beyond 20 years, these short-term dispatching effects could be expected to disappear. Annex 1: Load Forecasts Annex 1. BA U: GSDP Growth Rates 1996-2015 by Sector for Bihar (% per annum) 1996-2002 2003-2007 2008-2015 BAUHigh Growth GSDP 3.5 3.75 4.5 GSDP (Agriculture) 2.0 2.3 2.5 GSDP (Industries) 3.5 4.0 4.5 GSDP (Services) 4.3 5.0 5.5 BAULow Growth GSDP 3.5 3.25 3.0 GSDP (Agriculture) 2.0 1.25 1.0 GSDP (Industries) 3.5 3.5 3.25 GSDP (Services) 4.3 4.75 4.5 Annex L2 BA U: Electricity Price Increases 1996-2015 by Sector for Bihar (% per annum) 1996-1997 1998-2003 2004-2015 Residential 0 2.5 0 Commercial 0 0 0 Industrial 0 0 0 Agriculture 0 10.0 0 Annex L3 Reform: GSDP Growth Rates 1996-2015 by Sectorfor Bihar (% per annum) 1 996-2002 2003-2007 2008-2015 Reform Hieh Growth GSDP 3.5 4.75 6.0 GSDP (Agriculture) 1.5 2.75 4.0 GSDP (Industries) 4.0 5.25 6.5 GSDP (Services) 5.0 6.0 7.0 Reform Low Growth GSDP 3.5 3.75 4.5 GSDP (Agriculture) 2.0 2.3 2.5 GSDP (Industries) 3.5 4.0 4.5 GSDP (Services) 4.3 5.0 5.5 29 30 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Annex I.4 Reform: Electricity Price Increases 1996-2015 by Sector in Bihar (% per annum) 1996-2002 2003-2007 2008-2015 Residential 0 20 0 Commercial 0 14 0 Industrial 0 6 0 Agriculture 0 56 0 AnnexLI.5 BAU and Reform: GSDP Growth Rates for AP, 1998-2018 (% per annum) Year BAU Reform 1998 4.1 5.0 1999 4.0 5.4 2000 3.9 5.4 2001 3.7 5.6 2002 3.5 5.8 2003-2018 3.5 6.0 Annex 2: Supply-Side Options Annex 11.1: Supply-Side Candidate Options for Bihar (Thermal) Capacdiy Heat rate Capital cost Fuel cost O & M cost Maint Life Min Max BTU/MWh RsIkW Rs./MBTU Variable Fixed days' (years) Project MW MW Rs./MWh Rs./KW/ year ______________ _____ __________ ~M onth _ _ _ _ Patratu - 78 195 10352 26,000 86.1 8.9 70.7 45 25 Extension Muzaffarpur - 78 195 10352 26,000 95.5 8.9 70.7 45 25 Extension Tenughat- 78 195 10352 26,000 85.4 14.8 94.6 45 25 Extension Bihar Coal- 78 195 10160 31,800 77.9 10.9 86.5 55 25 based generic plant Naphtha based 78 195 10860 16,000 164.0 6.0 229.0 45 15 generic plant (open cycle) Bangladesh 78 195 7799 21,200 193.5/172 5.6 54.8 45 15 Gas based plant (closed cycle) Bagasse-based 10 190 12342 25,000 28.6/34.3 11.1 87.8 45 25 co-generation plant Bihar Coal- 78 195 8407 54,960 77.9 10.9 86.5 55 25 based generic plant with IGCC Bihar Coal- 78 195 8407 43,970 77.9 10.9 86.5 55 25 based generic plant with PFBC Nuclear 85 212 13271 86,000 15.1 11.2 66.3 47 25 Photovoltaic 10 200 - 200,000/ - 91.3 157.5 90 25 _____ _____ _________ 100,000 I I Note: The Bangladesh gas-based combined cycle gas turbine (CCT) also serves as a proxy for generic CCTs using LNG. 31 32 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Annex 112: Supply-Side Candidate Optionsfor Bihar (Hydro) Capacity Annual 0 & M Cost Capital cost Min- Max- Energy Variable Fixed Project imum imum (Gwh/Year) (Rs/MWEh) (Rs./KW/ (Rs./k P) (MW) (MW) Month) Mini-Hydro-I 37 74 48618 3.7 32.7 35,300 Mini-Hydro-II 37 74 486.18 3.7 32.7 45,890 Kadwan 0 450 858.0 4.3 18.3 23,400 Koel-Karo 20 710 1,058.0 9.7 29.1 37,100 Kaligandaki-A 60 144 823.20 3.7 32.7 71,180 (Nepal) Kaligandaki-2 142 352 1,406.0 9.7 29.1 60,160 (Nepal) Annex I1.3: Supply-Side Candidate Optionsfor AP Plant Type Capacity Economic Life Primary Fuel Heat Rate Fuel Cost Variable Fixed O & M Cost O&M MW Rs./kW Yrs. MBTU/kWh Rs./MBTU Rs./MWh Rs./kW/Mth Pit Head 500 32,300 30 Singareni coal 11000 75 106 13 Pit Head 500 46,300 30 Talcher coal 11000 48 115 21 Load Center' 500 32,300 30 Talcher coal 11000 79 115 21 Load Center2 500 49,000 30 Imported coal 9890 93 115 21 LNG-CCT3 400 30,000 20 LNG 7580 193 21 64 LNG-Open Cycle 400 14,000 20 LNG 11370 193 21 64 Naphtha 400 25,000 20 Naphtha 7580 223 15 63 Wind 100 35,000 20 Wind - - 3 63 Mini Hydro 100 35,000 20 Hydro - - - 22 Nuclear 440 57,000 30 Nuclear 11371 58 15 119 Bagasse 210 25,000 25 Bagasse 12342 29 11 88 Photovoltaic 210 200,000 25 Solar - - 91 158 Refinery Residue 250 45,800 20 Refin. Residue 8810 73 15 63 Jurala Hydro 110 29,200 25 Hydro - - - 22 PFBC5 250 45,000 30 Coal 9000 75 135 22 Notes: 1. Capital costs of Pit Head -Talcher plant include cost of evacuating power from Talcher to A.P. 2. Capital costs of imported coal plants include the cost ofpier construction. 3. Costs of Combined Cycle Turbines (CCT) taken from Proceedings of the Joint Power Generation Conference and Exhibition, 1998. 4. Costs ofplants using renewable energy taken from India: Environmental Issues in The Power Sector, ESMAP Report No. 205/98, June 1998 5. Information for Pressurized Fluidized Bed Combustion (PFBC) plants taken from "Clean Coal Technologies For Developing Countries, " World Bank Technical Paper 286, 1995. Supply-Side Options 33 Annex I1.4: Estimated Fuel Availability for AP, 1998-2018 Fuel Type Incremental Availability (MW): Until 2001 2002-2006 2007-2011 2011-2018 Coal. Singareni Coal 800 700 500 - Talcher Coal 800 1500 2000 2000 Imported Coal 750 2250 3750 3750 Hydrocarbons: Indigenous Gas 600 200 - - LNG - 1800 2400 2400 Naphtha 1200 1500 1500 1500 Refinery Residues 500 - 300 Renewables: Wind 100 500 200 - Mini-Hydel 100 200 100 Bagasse 200 200 - |Note: In the table, the availability of the different fuels is expressed in tenns of the capacity of each plant type that can be supported (MWV). Annex 11.5: Plants Currently Scheduledfor Construction or under Consideration in AP Plant Year Capacity Fuel Type Capital Cost ~~~~~~~~(Rs.1k W) Kondapalli 1999 355 Naphtha 25,000 Snehalata 2000 200 Naphtha 25,000 Oakwell Power 2000 200 Naphtha 25,000 Gautami 2000 300 Naphtha 25,000 Ispat 2001 468 Naphtha 25,000 HNPC - I 2002 520 Coal 32,300 Simhadri - I 2002 500 Coal 32,300 NTPC Talcher 11(1) 2002 500 Coal 32,300 HNPC - II 2003 520 Coal 32,300 Simhadri - II 2003 500 Coal 32,300 NTPC TalcherII (2) 2003 500 Coal 32,300 NTPC Talcher 11( 3) 2004 500 Coal 32,300 NTPC Talcher II6(4) 2004 500 Coal 32,300 NTPC - Ramagundam Ext. 2006 500 Coal 32,300 34 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Annex II.6: Options Considered under GHG Mitigation Scenario - Bihar Opiion Description Mini Hydro Force the second tranche of 74 MW in 2002 with increase in capital cost by 30% Koel-Karo Force in 2010 after Kadwan Nepal Hydro (1) Force Kaligandaki-A in 2000 & Kaligandaki-II in 2003 (2) Force Kaligandaki-A in 2000 & Kaligandaki-II in 2007 Clean Coal (1) All units of coal-based plants beyond 2004 have IGCC Technologies (clean coal) (2) All units of coal-based plants beyond 2004 have PFBC but with capital cost reduced by 20% below IGCC Bangladesh Bangladesh gas units available from 2004 (up to a limit of Gas 1000MW): (1) delivered cost of gas US$4.50/MBTU (2) delivered cost of gas US$4. 00/MBTU DSM Efficientfluorescent lamps in urban areas and high- efficiency refrigerators Coal Washing All new coal-based units work with washed coal costing Rs. 125/metric ton from 2001 onward (improved heat rate and increased fuel cost) Bagasse (1) Introduce 2x210 MW in 2004 (2) Introduce lx210 MWin 2004 and a further 1x210 MW in 2007, with a 20% escalation in fuel cost Nuclear Power Two units of25OMW capacity each forced into the plan in 2010 and 2011 with capital cost of US$20001/kW Photovoltaicl (1) Costed atRs.200,000/kWwith 200MWforced in the Renewables year 2004 (2) Costed at Rs. 100,000/kW with 200 MWforced in 2004 and additional 200 MWforced in 2012 T&D T&D loss reduction to bring down technical losses from Rehabilitation 18% under Reform to 13%from 2005 to 2010. Considered costs at Rs. 10 million/GWh reduced Supply-Side Options 35 Annex II. 7: Options Considered under GHG Mitigation Scenario -AP Option Description Enermy Efficiency: T&D Rehabilitation T&D losses assumed to decrease from 15% under Reforms to 10% by year 2010. Capital cost of T&D rehabilitation costs taken at 1/3rd the generation cost. DSM-Lighting DSM measures include commercial lighting, municipal lighting, fluorescent lamp standards, urban lighting (see AnnexIll. l). DSM-Agriculture Option developed on the basis of the ongoing Integrated Agricultural DSM Project (see Annex 111.2). Four technical measures combined in an integrated package. Measures include: conversion of low voltage feeders to high voltage feeders; automated load controlfor loss reduction; provision of customer meters; and improved end-use efficiency. Cost of implementation in all districts of AP estimated at Rs. 170 million. Renewables: Wind Total potential taken at 800 MWfor the duration of the study period. Capacity additions begin 2003 and continue every subsequent year in blocks of 100MW. Mini Hydro Potential taken at 400 MWfor the duration of the study period. Capacity additions in blocks of 100 MW in the years 2001, 2003, 2004, and 2006. Jurala Hydro Jurala taken as a proxyfor similar hydro plants. Plant of 110 MWforced in the year 2008. Bagasse Total potential of 400MW considered. A plant of 200 MW added in 2001 and a further 200 MW in 2002. Photovoltaics - Total capacity added limited to one representative plant in view of the high capital cost, existing technology, and institutional barriers. A typical plant of 210 MW considered in 2006. Others: PFBC PFBC taken as a proxy for new coal technologies such as IGCC. Generic plants using Singareni coal taken as PFBCs. A total of 2000 MW added in steps of 250 MWV Coal Beneficiation Coal washing made mandatory for all candidate plants using Indian coal. Coal washing costs taken at Rs. 125 per metric ton. Ash content assumed to drop by 7% and calorific value to improve from 3300 to 4000 Kcal/Kg LNG Unrestricted supply of LNG assumed, in order to maximize GHG reduction. Imported coal replaced with LNG from 2005 onward. 36 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Annex IL 7 (Continued) Options Considered under GHG Mitigation Scenario - AP Others continued: Refinery Residues Potential taken as 800 MWfor the duration of the study period. Two plants of 250 MWforced in 2001 and a third of 250 MWin 2010. Nuclear A plant of 440 MWforced in. Plant parameters based on existing Kaiga nuclear power plant. Capacity added in 2008. Plant decommissioning and spent fuel disposal costs not included. Hence the costs considered are likely to be understated. Plant Rehabilitation Kothagudam A unit repowered under a plant rehabilitation program. Measures include replacement of boiler valves, high-pressure rotors in steam turbines, change of generatorfeed coils, and modifications in the coal handling equipment. Rehabilitation cost of Rs. 1200 million. Annex I1.8 Possible Nepal Hydroelectric Power Imports Project Capacity Energy (GWh Load (MW) peryear) factor (/) Kaligandaki - A 144 840 67 Seti-III 107 Middle Bhote Koshi 120 UpperMarsyandgdi-3 121 Andi Khola 154 Tila-2 203 Tama Koshi-3 287 1813 50 Upper Trishuli-2 300 Burhi Gandaki 600 A run-III 402 2891 82 Upper Arun 335 2050 70 Lower Arun 308 2275 84 Kaligandaki -II 660 2660 46 Note: The table does not include large hydroelectric projects such as Karnali (10,800MW) and Pancheswar (6000MW). .Annex III. : Demand-Side Management in AP - Lighting (GWh Savings) 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Urban Lighting 4.3 13.3 27.7 48.1 69.8 92.8 125.3 155.2 182.1 205.6 183.9 160.9 124.2 85.3 43.9 43.9 43.9 > Municipal Lighting 0.2 0.8 1.8 3.7 6.6 9.5 12.6 15.7 19 22.4 22.1 21.6 20.6 18.6 15.8 12.9 9.8 (Sodium Vapor) SD Municipal Lighting 0.5 1.6 3.9 8 14 20.3 26.8 33.5 40.5 47.7 47.2 46.1 43.8 39.7 33.7 27.4 20.9 X (Fluorescent) CommercialLighting 2.7 8.6 21.6 50.1 97.3 162.1 233.4 311.8 398.1 493 490.3 484.4 471.4 442.8 395.7 330.9 259.6 (Electronic Ballast) Commercial Lighting 1.5 4.7 11.8 26 48.6 77.1 100.5 117.6 129.4 142.3 99.3 52 52 52 52 52 52 (CFL) (D Fluorescent Lamp 49.7 131.8 240.2 366 504.4 656.6 774.3 876.4 970.7 1067.8 1174.5 1292 1241 1563.3 1719.6 1891.6 2080. a Standards 7 W Rural Lighting 6.1 18.9 46.2 97 150.9 208.2 269 333.6 402.2 475 475 475 475 475 475 469 456.1 Total Savings (GCWh) 65 179.7 353.2 598.9 891.6 1226.6 1541.9 1843.8 2142 2453.8 2492.3 2532 2428 2676.7 2735.7 2827.7 2923 C (D 0 C,) Annex II1212 Cost and GWh Savingsfrom Integrated Agricultural DSM Project in AP Energy Savings/pumpset [kWh /pumpset/yearl 2527 Q Economic Cost/pumpset [Rs/pumpset] 26657 P Misc.Benefit/pumpset/year [Rs/pumpset/yearJ 1180 Opcost/PS/year [Rs/pumpset/yearl 533 Pumnpsets/scheme [pumipsets] 5813 r;. Annual Growth Rate in Pumpsets [%] 0.02 0 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 _ Number of Pumpsets (Millions) 1.791 1.827 1.864 1.901 1.939 1.978 2.017 2.058 2.099 2.141 2.183 2.227 2.272 2.317 2.363 2.411 2.459 2.508 2.558 2.609 C Pumpsels Added (Millions) 0.036 0.037 0.037 0.038 0.039 0.040 0.040 0.041 0.042 0.043 0.044 0.045 0.045 0.046 0.047 0.048 0.049 0.050 0.051 o Fraction of Growth in New Pumpsets 0.0 0.0 0.1 0.1 0.2 0.5 0.7 0.9 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Old Ptmpsets Added (Millions) 0.036 0.037 0.035 0.034 0.031 0.020 0.012 0.004 0.002 0 0 0 0 0 0 0 0 0 0 Stock of Old Pumpsets Eligiblefor 1.791 1.827 1.864 1.899 1.933 1.964 1.984 1.996 2.000 2.002 2.002 2.002 2.002 2.002 2.002 2.002 2.002 2.002 2.002 2.002 CD Rehabilitation (Millions) o 0 Numiber of Schemes 3 6 12 20 24 36 48 48 48 48 33 Pumpsets Rehabilitated (Millions) 0.017 0.035 0.070 0.116 0.140 0.209 0.279 0.279 0.279 0.279 0.192 0 0 0 0 0 0 0 0 Total Energy Savings (GWh/Year) 11592 0 0 44 132 308 602 955 1484 2189 2894 3599 4304 4788 4788 4788 4788 4788 4788 4788 4788 0 Capital Costs (Rs Million/Year) 0 465 930 1860 3099 3719 5579 7438 7438 7438 7438 5114 0 0 0 0 0 0 0 0 Operating Costs (Rs Million/Year) 0 9 28 65 127 201 313 462 611 759 908 1010 1010 1010 1010 1010 1010 1010 1010 Miscellan. Benefits (Rs Million/Year) 0 -21 -62 -144 -281 -446 -693 -1022 -1351 -1680 -2009 -2235 -2235 -2235 -2235 -2235 -2235 -2235 -2235 Total Costs (Rs Million/Year) 0 465 918 1826 3020 3565 5334 7059 6878 6698 6517 4013 -1225 -1225 -1225 -1225 -1225 -1225 -1225 -1225 0 Discount Rate 0.12 NP V (Rs Million) 16947 Note: Miscellaneous benefits include: reduced motor rewinding costs, deferred purchase of pumps, and reduced transformer and Power Factor correction costs Annex 4: Local Emissions Annex IVI: Bihar: Present Value of Emissions of SO2, NOx, and PM Scenario SO2 NOx PM (metric tons) (metric tons) (metric tons) Reform 876,550 732,619 58,195 GHG Mitigation: Group A 10% Reduction in C02 800,406 689968 52,606 17% Reduction in C02 749,551 655,103 48,909 20% Reduction in C02 738,811 656,672 48,407 Group B 10% Reduction in C02 800,406 689,968 52,606 20% Reduction in C02 718,869 639,368 47,057 25% Reduction in C02 707,976 629,329 46,052 Annex IV.2: AP: Present Value of Emissions of SOx, NOx and PM Scenario NOx SOx PM (metric tons) (metric tons) (metric tons) Reforms 3,006 3,316 380 10.3% Reduction in CO2 2,606 2,627 259 15.3% Reduction in CO2 2,577 2,474 258 19.6% Reduction in C02 2,403 2,384 241 22.8% Reduction in CO2 2,326 2,303 233 Annex IV.3: Coal Consumption in the Power Sector for the 12eform and GHG Mifigation Scenarios -Bihar and AP State/Scenario Coal Consumption (million metric tons) Bihar Reform Scenario 263 GHG Mitigation Scenario: 39 40 Greenhouse Gas Mitigation in the Power Sector: Case Studies from India Group A: 10% Reduction in CO2 228 17% Reduction in C02 221 20% Reduction in C02 199 Group B: 10% Reduction in C02 228 20% Reduction in C02 198 25% Reduction in C02 183 Andhra Pradesh Reforms 977 10.3% Reduction in C02 872 15.3% Reduction in C02 803 19.6% Reduction in C02 753 22.8% Reduction in C02 722 Joint UNDP/World Bank ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) LIST OF REPORTS ON COMPLETED ACTIVITIES Region/Country Activity/Report Title Date Number SUB-SAHARAN AFRICA (AFR) Africa Regional Anglophone Africa Household Energy Workshop (English) 07/88 085/88 Regional Power Seminar on Reducing Electric Power System Losses in Africa (English) 08/88 087/88 Institutional Evaluation of EGL (English) 02/89 098/89 Biomass Mapping Regional Workshops (English) 05/89 - Francophone Household Energy Workshop (French) 08/89 -- Interafrican Electrical Engineering College: Proposals for Short- and Long-Term Development (English) 03/90 112/90 Biomass Assessment and Mapping (English) 03/90 -- Symposium on Power Sector Reform and Efficiency Improvement in Sub-Saharan Africa (English) 06/96 182/96 Commnercialization of Marginal Gas Fields (English) 12/97 201/97 Commercilizing Natural Gas: Lessons from the Seminar in Nairobi for Sub-Saharan Africa and Beyond 01/00 225/00 Angola Energy Assessment (English and Portuguese) 05/89 4708-ANG Power Rehabilitation and Technical Assistance (English) 10/91 142/91 Benin Energy Assessment (English and French) 06/85 5222-BEN Botswana Energy Assessment (English) 09/84 4998-BT Pumnp Electrification Prefeasibility Study (English) 01/86 047/86 Review of Electricity Service Connection Policy (English) 07/87 071/87 Tuli Block Farms Electrification Study (English) 07/87 072/87 Household Energy Issues Study (English) 02/88 -- Urban Household Energy Strategy Study (English) 05/91 132/91 Burkina Faso Energy Assessment (English and French) 01/86 5730-BUR Technical Assistance Program (English) 03/86 052/86 Urban Household Energy Strategy Study (English and French) 06/91 134/91 Burundi Energy Assessment (English) 06/82 3778-BU Petroleum Supply Management (English) 01/84 012/84 Status Report (English and French) 02/84 011/84 Presentation of Energy Projects for the Fourth Five-Year Plan (1983-1987) (English and French) 05/85 036/85 Improved Charcoal Cookstove Strategy (English and French) 09/85 042/85 Peat Utilization Project (English) 11/85 046/85 Energy Assessment (English and French) 01/92 9215-BU Cape Verde Energy Assessment (English and Portuguese) 08/84 5073-CV Household Energy Strategy Study (English) 02/90 110/90 Central African Republic Energy Assessement (French) 08/92 9898-CAR Chad Elements of Strategy for Urban Household Energy The Case of N'djamena (French) 12/93 160/94 Comoros Energy Assessment (English and French) 01/88 7104-COM In Search of Better Ways to Develop Solar Markets: The Case of Comnoros 05/00 230/00 Congo Energy Assessment (English) 01/88 6420-COB Power Development Plan (English and French) 03/90 106/90 C6te d'Ivoire Energy Assessment (English and French) 04/85 5250-IVC Improved Biomass Utilization (English and French) 04/87 069/87 -2 - Region/Country Activity/lReport Title Date Number C6te dlvoire Power System Efficiency Study (English) 12/87 -- Power Sector Efficiency Study (French) 02/92 140/91 Project of Energy Efficiency in Buildings (English) 09/95 175/95 Ethiopia Energy Assessment (English) 07/84 4741-ET Power System Efficiency Study (English) 10/85 045/85 Agricultural Residue Briquetting Pilot Project (English) 12/86 062/86 Bagasse Study (English) 12/86 063/86 Cooking Efficiency Project (English) 12/87 -- Energy Assessment (English) 02/96 179/96 Gabon Energy Assessment (English) 07/88 6915-GA The Garmbia Energy Assessment (English) 11/83 4743-GM Solar Water Heating Retrofit Project (English) 02/85 030/85 Solar Photovoltaic Applications (English) 03/85 032/85 Petroleum Supply Management Assistance (English) 04/85 035/85 Ghana Energy Assessment (English) 11/86 6234-GH Energy Rationalization in the Industrial Sector (English) 06/88 084/88 Sawmill Residues Utilization Study (English) 11/88 074/87 Industrial Energy Efficiency (English) 11/92 148/92 Guinea Energy Assessment (English) 11/86 6137-GUI Household Energy Strategy (English and French) 01/94 163/94 Guinea-Bissau Energy Assessment (English and Portuguese) 08/84 5083-GUB Recommended Technical Assistance Projects (English & Portuguese) 04/85 033/85 Management Options for the Electric Power and Water Supply Subsectors (English) 02/90 100/90 Power and Water Institutional Restructuring (French) 04/91 118/91 Kenya Energy Assessment (English) 05/82 3800-KE Power System Efficiency Study (English) 03/84 014/84 Status Report (English) 05/84 016/84 Coal Conversion Action Plan (English) 02/87 - Solar Water Heating Study (English) 02/87 066/87 Peri-Urban Woodfuel Development (English) 10/87 076/87 Power Master Plan (English) 11/87 -- Power Loss Reduction Study (English) 09/96 186/96 Implementation Manual: Financing Mechanisms for Solar Electric Equipment 07/00 231/00 Lesotho Energy Assessment (English) 01/84 4676-LSO Liberia Energy Assessment (English) 12/84 5279-LBR Recommended Technical Assistance Projects (English) 06/85 038/85 Power System Efficiency Study (English) 12/87 081/87 Madagascar Energy Assessment (English) 01/87 5700-MAG Power System Efficiency Study (English and French) 12/87 075/87 Environmental Impact of Woodfuels (French) 10/95 176/95 Malawi Energy Assessment (English) 08/82 3903-MAL Technical Assistance to hnprove the Efficiency of Fuelwood Use in the Tobacco Industry (English) 11/83 009/83 Status Report (English) 01/84 013/84 Mali Energy Assessment (English and French) 11/91 8423-MLI Household Energy Strategy (English and French) 03/92 147/92 Islamic Republic of Mauritania Energy Assessment (English and French) 04/85 5224-MAU Household Energy Strategy Study (English and French) 07/90 123/90 - 3 - Region/Country Activity/Report Title Date Number Mauritius Energy Assessment (English) 12/81 3510-MAS Status Report (English) 10/83 008/83 Power System Efficiency Audit (English) 05/87 070/87 Bagasse Power Potential (English) 10/87 077/87 Energy Sector Review (English) 12/94 3643-MAS Mozambique Energy Assessment (English) 01/87 6128-MOZ Household Electricity Utilization Study (English) 03/90 113/90 Electricity Tariffs Study (English) 06/96 181/96 Sample Survey of Low Voltage Electricity Customers 06/97 195/97 Narnibia Energy Assessment (English) 03/93 11320-NAM Niger Energy Assessment (French) 05/84 4642-NIR Status Report (English and French) 02186 051/86 Improved Stoves Project (English and French) 12/87 080/87 Household Energy Conservation and Substitution (English and French) 01/88 082/88 Nigeria Energy Assessmnent (English) 08/83 4440-UNI Energy Assessment (English) 07/93 11672-UNI Rwanda Energy Assessment (English) 06/82 3779-RW Status Report (English and French) 05/84 017/84 Improved Charcoal Cookstove Strategy (English and French) 08/86 059/86 Improved Charcoal Production Techniques (English and French) 02/87 065/87 Energy Assessment (English and French) 07/91 8017-RW Commercialization of Improved Charcoal Stoves and Carbonization Techniques Mid-Term Progress Report (English and French) 12/91 141/91 SADC SADC Regional Power Interconnection Study, Vols. I-IV (English) 12/93 - SADCC SADCC Regional Sector: Regional Capacity-Building Program for Energy Surveys and Policy Analysis (English) 11/91 - Sao Tome and Principe Energy Assessment (English) 10/85 5803-STP Senegal Energy Assessment (English) 07/83 4182-SE Status Report (English and French) 10/84 025/84 Industrial Energy Conservation Study (English) 05/85 037/85 Preparatory Assistance for Donor Meeting (English and French) 04/86 056/86 Urban Household Energy Strategy (English) 02/89 096/89 Industrial Energy Conservation Program (English) 05/94 165/94 Seychelles Energy Assessment (English) 01/84 4693-SEY Electric Power System Efficiency Study (English) 08/84 021/84 Sierra Leone Energy Assessment (English) 10/87 6597-SL Somnalia Energy Assessment (English) 12/85 5796-SO South Africa Options for the Structure and Regulation of Natural Republic of Gas Industry (English) 05/95 172/95 Sudan Management Assistance to the Ministry of Energy and Mining 05/83 003/83 Energy Assessment (English) 07/83 4511-SU Power System Efficiency Study (English) 06/84 018/84 Status Report (English) 11/84 026/84 Wood Energy/Forestry Feasibility (English) 07/87 073/87 Swaziland Energy Assessment (English) 02/87 6262-SW Household Energy Strategy Study 10/97 198/97 Tanzania Energy Assessment (English) 11/84 4969-TA Peri-Urban Woodfuels Feasibility Study (English) 08/88 086/88 Tobacco Curing Efficiency Study (English) 05/89 102/89 Remote Sensing and Mapping of Woodlands (English) 06/90 -- -4 - Region/Countiy Activity/Report Title Date Number Tanzania Industrial Energy Efficiency Technical Assistance (English) 08/90 122/90 Power Loss Reduction Volume 1: Transmission and Distribution SystemTechnical Loss Reduction and Network Development (English) 06/98 204A/98 Power Loss Reduction Volume 2: Reduction of Non-Technical Losses (English) 06/98 204B/98 Togo Energy Assessment (English) 06/85 5221-TO Wood Recovery in the Nangbeto Lake (English and French) 04/86 055/86 Power Efficiency Improvement (English and French) 12/87 078/87 Uganda Energy Assessment (English) 07/83 4453-UG Status Report (English) 08/84 020/84 Institutional Review of the Energy Sector (English) 01/85 029/85 Energy Efficiency in Tobacco Curing Industry (English) 02/86 049/86 Fuelwood/Forestry Feasibility Study (English) 03/86 053/86 Power System Efficiency Study (English) 12/88 092/88 Energy Efficiency Improvement in the Brick and Tile Industry (English) 02/89 097/89 Tobacco Curing Pilot Project (English) 03/89 UNDP Tenninal Report Energy Assessment (English) 12/96 193/96 Rural Electrification Strategy Study 09/99 221/99 Zaire Energy Assessment (English) 05/86 5837-ZR Zambia Energy Assessment (English) 01/83 4110-ZA Status Report (English) 08/85 039/85 Energy Sector Institutional Review (English) 11/86 060/86 Power Subsector Efficiency Study (English) 02/89 093/88 Energy Strategy Study (English) 02/89 094/88 Urban Household Energy Strategy Study (English) 08/90 121/90 Zimbabwe Energy Assessment (English) 06/82 3765-ZIM Power System Efficiency Study (English) 06/83 005/83 Status Report (English) 08/84 019/84 Power Sector Management Assistance Project (English) 04/85 034/85 Power Sector Management Institution Building (English) 09/89 -- Petroleum Management Assistance (English) 12/89 109/89 Charcoal Utilization Prefeasibility Study (English) 06/90 119/90 Integrated Energy Strategy Evaluation (English) 01/92 8768-ZIM Energy Efficiency Technical Assistance Project: Strategic Framework for a National Energy Efficiency Improvement Program (English) 04/94 - Capacity Building for the National Energy Efficiency Improvement Progranmne (NEEIP) (English) 12/94 - Rural Electrification Study 03/00 228/00 EAST ASIA AND PACIFIC (EAP) Asia Regional Pacific Household and Rural Energy Seminar (English) 11/90 -- China County-Level Rural Energy Assessments (English) 05/89 101/89 Fuelwood Forestry Preinvestment Study (English) 12/89 105/89 Strategic Options for Power Sector Reform in China (English) 07/93 156/93 Energy Efficiency and Pollution Control in Township and Village Enterprises (TVE) Industry (English) 11/94 168/94 -5 - Region/Country Activity/Report Title Date Number China Energy for Rural Development in China: An Assessment Based on a Joint Chinese/ESMAP Study in Six Counties (English) 06/96 183/96 Improving the Technical Efficiency of Decentralized Power Companies 09/99 222/999 Fiji Energy Assessment (English) 06/83 4462-FIT Indonesia Energy Assessment (English) 11/81 3543-IND Status Report (English) 09/84 022/84 Power Generation Efficiency Study (English) 02/86 050/86 Energy Efficiency in the Brick, Tile and Lime Industries (English) 04/87 067/87 Diesel Generating Plant Efficiency Study (English) 12/88 095/88 Urban Household Energy Strategy Study (English) 02/90 107/90 Biomass Gasifier Preinvestment Study Vols. I & II (English) 12/90 124/90 Prospects for Biomass Power Generation with Ernphasis on Palm Oil, Sugar, Rubberwood and Plywood Residues (English) 11/94 167/94 Lao PDR Urban Electricity Demand Assessment Study (English) 03/93 154/93 Institutional Development for Off-Grid Electrification 06/99 215/99 Malaysia Sabah Power System Efficiency Study (English) 03/87 068/87 Gas Utilization Study (English) 09/91 9645-MA Myanmar Energy Assessment (English) 06/85 5416-BA Papua New Guinea Energy Assessment (English) 06/82 3882-PNG Status Report (English) 07/83 006/83 Energy Strategy Paper (English) - -- Institutional Review in the Energy Sector (English) 10/84 023/84 Power Tariff Study (English) 10/84 024/84 Philippines Commercial Potential for Power Production from Agricultural Residues (English) 12/93 157/93 Energy Conservation Study (English) 08/94 -- Solomon Islands Energy Assessment (English) 06/83 4404-SOL Energy Assessment (English) 01/92 979-SOL South Pacific Petroleumn Transport in the South Pacific (English) 05/86 -- Thailand Energy Assessment (English) 09/85 5793-TH Rural Energy Issues and Options (English) 09/85 044/85 Accelerated Dissemination of Inproved Stoves and Charcoal Kilns (English) 09/87 079/87 Northeast Region Village Forestry and Woodfuels Preinvestment Study (English) 02/88 083/88 Impact of Lower Oil Prices (English) 08/88 - Coal Development and Utilization Study (English) 10/89 - Tonga Energy Assessment (English) 06/85 5498-TON Vanuatu Energy Assessment (English) 06/85 5577-VA Vietnam Rural and Household Energy-Issues and Options (English) 01/94 161/94 Power Sector Reform and Restructuring in Vietnam: Final Report to the Steering Committee (English and Vietnamese) 09/95 174195 Household Energy Technical Assistance: Improved Coal Briquetting and Commercialized Dissemination of Higher Efficiency Biomass and Coal Stoves (English) 01/96 178/96 Petroleum Fiscal Issues and Policies for Fluctuating Oil Prices In Vietnam 02/01 236/01 Western Samoa Energy Assessment (English) 06/85 5497-WSO -6- Region/Country Activity/Report Title Date Number SOUTH ASIA (SAS) Bangladesh Energy Assessment (English) 10/82 3873-BD Priority Investment Program (English) 05/83 002/83 Status Report (English) 04/84 015/84 Power System Efficiency Study (English) 02/85 031/85 Small Scale Uses of Gas Prefeasibility Study (English) 12/88 -- India Opportunities for Comnmercialization of Nonconventional Energy Systems (English) 11/88 091/88 Maharashtra Bagasse Energy Efficiency Project (English) 07/90 120/90 Mini-Hydro Development on Irrigation Dams and Canal Drops Vols. I, II and I1:I (English) 07/91 139/91 WindFarm Pre-Investment Study (English) 12/92 150/92 Power Sector Reform Seminar (English) 04/94 166/94 Environmental Issues in the Power Sector (English) 06/98 205/98 Environmental Issues in the Power Sector: Mariual for Environmental Decision Making (English) 06/99 213/99 Household Energy Strategies for Urban India: The Case of Hyderabad 06/99 214/99 Greenhouse Gas Mitigation In the Power Sector: Case Studies From India 02/01 237/01 Nepal Energy Assessment (English) 08/83 4474-NEP Status Report (English) 01/85 028/84 Energy Efficiency & Fuel Substitution in Industries (English) 06/93 158/93 Pakistan Household Energy Assessment (English) 05/88 -- Assessment of Photovoltaic Programs, Applications, and Markets (English) 10/89 103/89 National Household Energy Survey and Strategy Formulation Study: Project Terminal Report (English) 03/94 -- Managing the Energy Transition (English) 10/94 Lighting Efficiency Improvement Program Phase 1: Commercial Buildings Five Year Plan (English) 10/94 Sri Lanka Energy Assessment (English) 05/82 3792-CE Power System Loss Reduction Study (English) 07/83 007/83 Status Report (English) 01/84 010/84 Industrial Energy Conservation Study (English) 03/86 054/86 EUROPE AND CENTRAL ASIA (ECA) Bulgaria Natural Gas Policies and Issues (English) 10/96 188/96 Central and Eastem Europe Power Sector Reform in Selected Countries 07/97 196/97 Increasing the Efficiency of Heating Systems in Central and Eastem Europe and the Former Soviet Union 08/00 234/00 Eastern Europe The Future of Natural Gas in Eastem Europe (English) 08/92 149/92 Kazakhstan Natural Gas Investment Study, Volumes 1, 2 & 3 12/97 199/97 Kazakhstan & Kyrgyzstan Opportunities for Renewable Energy Development 11/97 16855-KAZ Poland Energy Sector Restructuring Program Vols. I-V (English) 01/93 153/93 Natural Gas Upstream Policy (English and Polish) 08/98 206/98 Region/Country Activity/Report Title Date Number Poland Energy Sector Restructuring Program: Establishing the Energy Regulation Authority 10/98 208/98 Portugal Energy Assessment (English) 04/84 4824-PO Romania Natural Gas Development Strategy (English) 12/96 192/96 Slovenia Workshop on Private Participation in the Power Sector (English) 02/99 211/99 Turkey Energy Assessment (English) 03/83 3877-TU Energy and the Environment: Issues and Options Paper 04/00 229/00 MIDDLE EAST AND NORTH AFRICA (MNA) Arab Republic of Egypt Energy Assessment (English) 10196 189/96 Energy Assessment (English and French) 03/84 4157-MOR Status Report (English and French) 01186 048/86 Morocco Energy Sector Institutional Development Study (English and French) 07/95 173/95 Natural Gas Pricing Study (French) 10/98 209/98 Gas Development Plan Phase II (French) 02/99 210/99 Syria Energy Assessment (English) 05/86 5822-SYR Electric Power Efficiency Study (English) 09/88 089/88 Energy Efficiency Improvement in the Cement Sector (English) 04/89 099/89 Energy Efficiency Improvement in the Fertilizer Sector (English) 06/90 115/90 Tunisia Fuel Substitution (English and French) 03/90 -- Power Efficiency Study (English and French) 02/92 136/91 Energy Management Strategy in the Residential and Tertiary Sectors (English) 04/92 146/92 Renewable Energy Strategy Study, Volume I (French) 11/96 190A/96 Renewable Energy Strategy Study, Volume II (French) 11/96 190B/96 Yemen Energy Assessment (English) 12/84 4892-YAR Energy Investment Priorities (English) 02/87 6376-YAR Household Energy Strategy Study Phase I (English) 03/91 126/91 LATIN AMERICA AND THE CARIBBEAN (LAC) LAC Regional Regional Seminar on Electric Power System Loss Reduction in the Caribbean (English) 07/89 - Elimination of Lead in Gasoline in Latin America and the Caribbean (English and Spanish) 04/97 194/97 Elimination of Lead in Gasoline in Latin America and the Caribbean - Status Report (English and Spanish) 12197 200/97 Harmonization of Fuels Specifications in Latin America and the Caribbean (English and Spanish) 06/98 203/98 Bolivia Energy Assessment (English) 04/83 4213-BO National Energy Plan (English) 12/87 -- La Paz Private Power Technical Assistance (English) 11/90 111/90 Prefeasibility Evaluation Rural Electrification and Demand Assessment (English and Spanish) 04191 129/91 National Energy Plan (Spanish) 08/91 131/91 Private Power Generation and Transmission (English) 01/92 137/91 Natural Gas Distribution: Economics and Regulation (English) 03/92 125/92 - 8- Region/Country Activity/lReport Title Date Number Bolivia Natural Gas Sector Policies and Issues (English and Spanish) 12/93 164/93 Household Rural Energy Strategy (English and Spanish) 01/94 162/94 Preparation of Capitalization of the Hydrocarbon Sector 12/96 191/96 Introducing Competition into the Electricity Supply Industry in Developing Countries: Lessons from Bolivia 08/00 233/00 Final Report on Operational Activities Rural Energy and Energy Efficiency 08/00 235/00 Brazil Energy Efficiency & Conservation: Strategic Partnership for Energy Efficiency in Brazil (English) 01/95 170/95 Hydro and Thermal Power Sector Study 09/97 197/97 Rural Electrification with Renewable Energy Systems in the Northeast: A Preinvestment Study 07/00 232/00 Chile Energy Sector Review (English) 08/88 7129-CH Colombia Energy Strategy Paper (English) 12/86 -- Power Sector Restructuring (English) 11/94 169/94 Energy Efficiency Report for the Commercial and Public Sector (English) 06/96 184/96 Costa Rica Energy Assessment (English and Spanish) 01/84 4655-CR Recomnnended Technical Assistance Projects (English) 11/84 027/84 Forest Residues Utilization Study (English and Spanish) 02/90 108/90 Dominican Republic Energy Assessment (English) 05/91 8234-DO Ecuador Energy Assessment (Spanish) 12/85 5865-EC Energy Strategy Phase I (Spanish) 07/88 -- Energy Strategy (English) 04/91 -- Private Minihydropower Development Study (English) 11/92 -- Energy Pricing Subsidies and Interfuel Substitution (English) 08/94 11798-EC Energy Pricing, Poverty and Social Mitigation (English) 08/94 12831-EC Guatemala Issues and Options in the Energy Sector (English) 09/93 12160-GU Haiti Energy Assessment (English and French) 06/82 3672-HA Status Report (English and French) 08/85 041/85 Household Energy Strategy (English and French) 12/91 143/91 Honduras Energy Assessment (English) 08/87 6476-HO Petroleum Supply Management (English) 03/91 128/91 Jamaica Energy Assessment (English) 04/85 5466-JM Petroleum Procurement, Refining, and Distribution Study (English) 11/86 061/86 Energy Efficiency Building Code Phase I (English) 03/88 -- Energy Efficiency Standards and Labels Phase I (English) 03/88 -- Management Information System Phase I (English) 03/88 -- Charcoal Production Project (English) 09/88 090/88 FIDCO Sawmill Residues Utilization Study (English) 09/88 088/88 Energy Sector Strategy and Investment Planning Study (English) 07/92 135/92 Mexico Inproved Charcoal Production Within Forest Management for the State of Veracruz (English and Spanish) 08/91 138/91 Energy Efficiency Management Technical Assistance to the Comision Nacional para el Ahorro de Energia (CONAE) (English) 04/96 180/96 Panama Power System Efficiency Study (English) 06/83 004/83 Paraguay Energy Assessment (English) 10/84 5145-PA Recommended Technical Assistance Projects (English) 09/85 -- Status Report (English and Spanish) 09/85 043/85 Peru Energy Assessment (English) 01/84 4677-PE -9- Region/Country Activity/Report Title Date Number Peru Status Report (English) 08/85 040/85 Proposal for a Stove Dissemination Program in the Sierra (English and Spanish) 02/87 064/87 Energy Strategy (English and Spanish) 12/90 -- Study of Energy Taxation and Liberalization of the Hydrocarbons Sector (English and Spanish) 120/93 159/93 Reform and Privatization in the Hydrocarbon Sector (English and Spanish) 07/99 216/99 Saint Lucia Energy Assessment (English) 09/84 5111 -SLU St. Vincent and the Grenadines Energy Assessment (English) 09/84 5103-STV Sub Andean Environmental and Social Regulation of Oil and Gas Operations in Sensitive Areas of the Sub-Andean Basin (English and Spanish) 07/99 217/99 Trinidad and Tobago Energy Assessment (English) 12/85 5930-TR GLOBAL Energy End Use Efficiency: Research and Strategy (English) 11/89 - Women and Energy--A Resource Guide The International Network: Policies and Experience (English) 04/90 -- Guidelines for Utility Customer Management and Metering (English and Spanish) 07/91 Assessment of Personal Computer Models for Energy Planning in Developing Countries (English) 10/91 Long-Term Gas Contracts Principles and Applications (English) 02/93 152/93 Comparative Behavior of Firms Under Public and Private Ownership (English) 05/93 155/93 Development of Regional Electric Power Networks (English) 10/94 -- kounatable on Energy Efflciency (English) 02J95 171/95 Assessing Pollution Abatement Policies with a Case Study of Ankara (English) 11/95 177/95 A Synopsis of the Third Annual Roundtable on Independent Power Projects; Rhetoqc and Reality (English) 08/96 187/96 Rural Energy and Development Roundtable (English) 05/98 202/98 A Synopsis of the Second Roundtable on Energy Efficiency: Institutional and Financial Delivery Mechanisms (English) 09/98 207/98 The Effect of a Shadow Price on Carbon Emission in the Energy Portfolio of the World Bank: A Carbon Backcasting Exercise (English) 02/09 212)90 Increasing the Efficiency of Gas Distribution Phase 1: Case Studies and Themnatic Data Sheets 07/99 218/99 Global Energy Sector Reform in Developing Countries: A Scorecard 07/99 219/99 Global Lighting Services for the Poor Phase II: Text Marketing of Smnall "Solar" Batteries for Rural Electrification Purposes 08/99 220/99 A Review of the Renewable Energy Activities of the UTNDP/ World Bank Energy Sector Management Assistance Programme 1993 to 1998 11/99 223/99 - 10- Region/Countiy Activity/Report Title Date Number Global Energy, Transportation and Environment: Policy Options for Environmental Improvement 12/99 224/99 Privatization, Competition and Regulation in the British Electricity Industry, With Implications for Developing Countries 02/00 226/00 Reducing the Cost of Grid Extension for Rural Electrification 02/00 227/00 2/8/01 The World Bank 1818 H Street, NW Washington, DC 20433 USA Tel.: 1.202.458.2321 Fax.: 1.202.522.3018 Internet: www.esmap.org Email: esmap@worldbank.org A )oir~t UNDPJWOrhBan Programme ia A joint UNDPfWortd Bank Programme