Document of The World Bank FOR OFFICIAL USE ONLY L F -3 43 4 -1 MICROFICHE COPY Report No. 8943-IN Report No. 8943-IN Type: (SAR) MEJIA, ALF/ X81467 / E10009/ AS4TE STAFF APPRAISAL REPORT INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT JANUARY 3, 1992 Energy Operations Division Country Department II South Asia Region This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENTS C&77of 4uh!, 1992XF Currency Unit = Rupees (Rs) Rs 1.00 = Palse 100 Rs 1,000,000 = USS38,482 USS1.00 = Rs 28.00 MEASURES AND EQUIVALENTS 1 Kilometer (km) = 1,000 meters (m) = 0.6214 miles (mt) 1 Meter (m) = 39.37 Inches (in) 1 Cubic Moter (i3) = 1.31 cubic yard (cu yd) = 36.36 cu. ft. 1 Ton (t) = 1,000 kilograms (kg) = 2,200 lbs 1 Kilovolt (kV) = 1,000 volts (V) 1 Kilovolt ampere (kVA) = 1,000 volts-amperes (VA) 1 Megawatt (MW) = 1,000 kilowatts (kW) = 1 million watts 1 Kilowatt-hour (kWh) = 1,000 watt-hours 1 Megawatt-hour (MWh) = 1,000 kilowatts-hours 1 Gigawatt-hour (GWh) = 1,0C0,000 kilowatt-hours ABBREVIATIONS AND ACRONYMS ADB Asian Development Bank AEC Ahmedabad Electricity Company AIC Average Incremental Cost BSES Bombay Suburban Electric Supply Ltd. CEA Central Electricity Authority CESC Calcutta Electric Supply Corporation DOP Department of Power DSCR Debt Service Coverage Ratio EAMU Environmental Assessme,.D and Monitoring Unit EHV Extra High Voltage ESP Electrostatic Precipitators Co0 Covernment of India HVDC High Voltage Direct Current ICICI Industrial Credit and Investment Corporation of India IDBI Industrial Development Bank of India LCB Local Competitive Bidding LIB Limited International Bidding LIC Life Insurance Corporation of India LRMC Long Run Marginal Cost MIS Management Information System NHPC National Hydroelectric Power Corporation NPTC Natlonal Power Transmission Corporation NTPC National Thermal Power Corporation OFAP Operational and Financial Action Plan OPS Operational Policy Statement PFC Power Finance Corporation PLF Plant Load Factor RES Regional Electricity Board REC Rural Electrification Corporation SEA Socio-Environmental Assessments SEB State Electricity Board SCF Standard Conversion Factor SGC State Generating Corporation SPAR Sub-project Appraisal Reports TEC Tots Electric Companies The Act Electricity Supply Act of 1948 USAID United States Agency for International Development FISCAL YEAR April 1 - March 31 FOR OFFICIAL USE ONLY INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT STAFF APPRAISAL REPORT Table of Contents Page No. Loan and Project Summary .................................... iv I. SECTORAL CONTEXT ........................................... 1 Overview .............................................. 1 Electricity Demand and Supply ......................... 2 Organization of the Power Sector ...................... 2 GOI Strategy in the Power Sector ...................... 3 Past Bank Group Strategy in the Power Sector .......... 5 Bank Group Support .................................... 7 Results of These Efforts ....................... ........ 7 Towards a New Approach in the Power Sector ............ 9 II. THE BENEFICIARY ........................................... 10 Formation of PFC ... 10 Organization and Staffing of PF .. . . 12 Operational Policy Statement . . . 12 Pre-allocation of PFC's Funds . . . 13 Institutional Strengthening of PFC Borrowers ... 13 Lending Criteria ... 14 PFC's Loan Processing Procedures . . . 15 Collection Procedures . . . 16 Accounting and Auditing . . . 16 Environment Monitoring Unit . . . 16 Monitoring of Projects . . . 17 Management Information System ........................ 17 Financial Planning, Budgeting and Controls ........... 17 This report was prepared by Messrs. Alfonso Mejis (Principal Financial Analyst), Alfonso Sanchez (Principal Engineer), Mark Tomlinson (Senior Economist), and Mrs. Magdalena Manzo (Energy Specialist). The report has been reviewed by Messrs. K. Siraj (Operations Advisor); K. Jechoutek (Senior Economist), and J. Hanson (Lead Senior Economist). The report has been endorsed by Mr. Heinz Vergin, Director (India Department) and Mr. Jean-Francois Bauer, Division Chief (Energy Operations Division, India Department). This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. - ii - Page No. II THE PROJECT ....................... 17 Project Setting ....................... 17 Project Objectives ...................... 19 Project Description .. . 19 Institutional Strengthening of PFC . .20 Pre-investment Fund .............................. 20 Financing Through PFC ........................... . 20 Transmission and Distribution Projects .. 20 Environmental Upgrading of Power Plants .. 21 Engineering Studies for System Renovation ...21 Institutional Strengthening of Utilities .... 21 Billing and Collections .. 21 Status of Project Engineering .............. .......... 21 Project Implementation Arrangements and Schedule ...... 23 Environmental ard Resettlement Aspects ................ 25 Project Costs ......................................... 26 Project Financing ..................................... 27 On-Lending Arrangements ............................... 27 Procurement ........................................... 28 Disbursements ......................................... 29 Project Monitoring .................................... 30 :roject Risks ......................................... 30 IV. FINANCE .................................................... 31 Background ............................................ 31 PFC's Market .......................................... 31 SEB's Future Funding Requirements ...................... 32 PFC's Sources of Financing ............................ 33 Domestic Market Borrowings ....................... 33 Equity Contributions ............................. 34 External Borrowing ............................... 34 PFC's Lending Terms ................................... 34 PFC's Historical Performance .......................... 35 PFC's Financial Policies .............................. 35 General Operations Parameters .................... 35 Solvency ................................... 36 Liquidity ................................... 36 Profitability .................................. 36 Foreign Exchange Risk ............................ 36 Term Transformation .............................. 36 Repayment Guarantees and Exposure Limits ......... 36 Non-Rescheduling of Loans ........................ 38 Adjustability of PFC's Lending Rate .............. 38 PFC's Future Financial Performance .................... 38 Conditionality ........................................ 40 - iii - Page No. V. ECONOMIC ANALYSIS AND PROJECT JUSTIFICATION ................. 40 Least Cost Analysis .................................... 41 Program Analysis .............. 41 Project Analysis ............... 42 Costs ............................................... .42 Benefits ............................................... 43 Results of Program and Project Economic Analyses ....... 44 VI. AGREEMENTS AND RECOMMENDATION ............................... 45 Agreement Reached ...................................... 45 Recommendation ......................................... 47 ANNEXWS 1.1 All India: Electricity Supply and Demand 1.2 Previous Loans and Credits to Indian Power Sector (as of November 30, 1991) 2.1 PFC Organization Chart 2.2 Operational Policy Statement 2.3 Guidelines for Preparation of Action Plans 2.4 PFC's Lending Operations Up to March 31, 1991 2.5 Environmental Assessment and Monitoring Unit - Scope of Work and Procedures 3.1 Detailed Project Description 3.2 Environmental Review of Power Stations - Suggested Terms of Reference 3.3 A. Tentative Scope of Technical Assistance for System Renovation B. Suggested Terms of Reference for Thermal Plant Rehabilitation 3.4 Draft Terms of Reference for Preparation of a Training Program for PFC 3.5 PFC Plan for Implementing the Institutional Development Program 3.6 PFC Preinvestment Fund Concept and Scope of Operations 3.7 Project Cost Summary 3.8 Procurement Arrangements 3.9 Schedule of Estimated Disbursements 4.1 SEB's Financial Peformance 1986-90 4.2 Historical and Projected Income Statements 4.3 Assumptions Followed in Financial Projections 4.4 Sensitivity Analysis - Selected Cases 5.1 Punjab SEB Transmission and Distribution Project - Economic Analysis 6.1 Documents in Project File - iv - INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Loan and Project Summary Borrower: India, acting by its President Benef4ciary: Power Finance Corporation Ltd. (PFC) Amount: US$265 million Terms: Repayment over 20 years, including five years grace, at the Bank's standard variable interest rate. On-lending Term: From the Government of India (GOI) to PFC, with repayment over 15 years, including three years grace, at an interest rate at not less than 11.5Z per annum with GOI assuming the foreign exchange and interest rate risks. PFC will onlend to its clients at an interest rate which is now set at 12.5Z and which will be adjusted to reflect variations in its cost of funds, and repayment terms ranging from 3 to 7 years, according to the types of assets financed. Project Description: The main objectives of the project are to: (a) support GOI efforts to make PFC a viable and effective instrument for improving th, power sector; (b) strengthen the operations of the beneficiary utilities by lending only to those willing to undertake acceptable reform programs; (c) foster better use of existing power facilities by reducing constraints in the transmission and distribution systems; (d) mitigate the adverse environmental impact of thermal plants in operation by providing adequate anti- pollution and monitoring facilities; and (e) improve the preparation of power projects and promote the development of the local consulting industry by funding preinvestment studies and engineering for power projects. The proposed project comprises: (a) a program to strengthen PFC's capabilities to discharge its responsibilities; (b) the creation of a preinvestment fund in PFC; and (c) five components to be financed through PFC: (i) the implementation of a pre-identified segment of the lending program of PFC; (ii) environmental upgrading of power plants; (iii) engineering studies for system renovation: (iv) institutional strengthening of power utilities; (v) improvements in SEBs' billing and collection. v Benefits: The main benefits of the project are: (a) improvements in the operational efficiency of the state utilities; (b) improvements in the finances of the state utilities through reducti n in losses and better billing and collections; (c) improvements in the environmental operating conditions of participating utilities; (d) improved quality of service; and (e) better use of existing plant facilities. Projects eligible for PFC funding are required to have an economic rate of return of at least 12Z; the economic rates of return of projects already approved, and which represent about 50% of all investments envisaged, range from 141 to over lOOZ. Risks: The proposed project does not pose extraordinary technical risks. There are, however, risks related to the institutional, managerial, and financial aspects of the project. There is a risk that the participating utilities will not meet the expected improvements set out in their action plans or that the pace of reform will be slower than planned. This risk will be minimized by establishing realistic targets in the plans, and by providing financial and technical resources to the utilities to facilitate their implementation. To minimize the risk of delays caused by siow procurement decisions and administrative processing, at negotiations GOI provided the Bank with the details of the procedures to be followed to expedite and simplify clearances of procurement actions and releases of foreign exchange for Bank- financed procurement. There are two risks related to PFC's performance. The first is that PFC could face collection problems because of the poor financial performance of its customers. This risk would be kept at an acceptably low level by requiring PFC's clients to establish a set of suitable guarantees. The second risk is that PFC might fail to become an effective promoter of institutional improvements at the utilities level. This could occur if PFC does not have the institutional resolve -- and GOI's support -- to attach adequate conditionality to its lending operations. This also may occur if political pressures prevent PFC from enforcing said conditionality or its Operational Policy Statement (OPS). To manage this eventuality, agreements were reached to ensure that PFC's policies and procedures are consistent with its development objectives. - vi - Estimated Cost: a/ Local Foreign Total b/ --------(US$ Million)------ A. Transmission & Distribution Schemes 214 126 340 B. Environmental Upgrading of Plants 67 24 91 C. Studies for System Renovation 2 4 6 D. Institutional Development of SEBs 3 3 6 E. Institutional Development of PFC 1 0 1 F. Creation of Preinvestment Fund 4 10 14 TOTAL BASELINE COSTS 290 167 457 Physical Contingencies 28 15 43 Price Contingencies 102 39 141 TOTAL PROJECT COST 420 220 640 Interest During Construction World Bank 20 20 40 Others 30 2 32 TOTAL FINANCING REQUIRED 470 242 712 Financing Plan: Source Z IBRD 59 206 265 37 PFC Resources 26) 22 291 41 USAID - 14 14 2 SEBs 142 - 142 20 Total 470 242 712 100 Estimated Bank Disbursement: (US$ Million) Bank Fiscal Year FY92 FY93 FY94 PY95 FY96 FY97 PY98 Annual 15.9 31.8 53.0 74.2 31.8 53.0 5.3 Cumulative 15.9 47.7 100.7 174.9 206.7 259.7 265.0 Rates of Return: In excess of 12Z. a/ Including taxes and duties of about US$84 million equivalent. b/ Total may not add up due to rounding. INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT STAFF APPRAISAL REPORT I. SECTORAL CONTEXT Overview 1.01 Over the past decade, electricity consumption in India increased at an average annual -ate of 9.2%. Despite impressive progress in systems expansion, power shortages continue and are equivalent to about 9% of total energy and 22Z of peak capacity requirement. The supply gap is largely attributable to the relatively inefficient and wasteful utilization of energy in the country due to technical as well as energy price inefficiencies. Reduction in systems losses (currently estimated at 222), setting of power rates closer to the economic cost of supply and improved inter-state and regionr.l power trading could significantly reduce the supply shortfall. The proposed project will address some of these efficiency issues. 1.02 With per capita level of about 270 kWh per annum, electricity consumption in India is among the lowest in the world, and demand is expected to continue to expand at an average growth rate of 8X per annum over the next five years. Even if GOI were to boldly address the inefficiency problems of the sector through adoption of energy conservation measures and correction in price signals, massive investments in additional capacity will still be required. 1.03 In the face of the current and medium-term budgetary constraints, central government funding of the sector's investment program is likely to be insufficient and the state and central government-owned utilities will have to increasingly rely on their own internal resources to finance power systems expansion. However, their ability to contribute internal resources toward capacity investments is hampered by their poor financial conditions. The sector's financial distress primarily stems from the operational and financial inefficiencies of the State-owned utilities -- the State Electricity Boards (SEBs) and the State Generation Companies (SGCs). Their poor performance is adversely affecting the finances of the centrally-owned utilities and is hindering efforts at attracting private investors to the sector. A turn- around in the sector's finances and closing of the power gap would require bold actions on tariff, billing and collection, together with conservation measures such as plant efficiency improvements, reductions of transmission and distribution losses, load management and promotion of greater production and end-use efficiency. 1.04 The Power Finance Corporation (PFC) was established in 1986 by Government of India (GOI) to effect some of the needed financial and operational reforms at the state level. PFC links its financing of the SEBs' priority investments to tangible improvements in their operations. It supports efficiency improvements in existing plant operations, expansion and upgrading of transmission and distribution facilities as well as mitigating measures for controlling plant emissions. While helping finance investments in power supply, PFC, through its !.an conditionalities, attempts to instill financial discipline in the SEBs, thereby strengthening their financial base and their capacity to contribute to the sector's investment requirements. - 2 - 1.05 The following paragraphs describe the salient characteristics of India's power sector, its organizational structure, the Government's strategy for the sector and the main thrust of the Bank's support in the past, a review of the effectiveness of these strategies and the lessons that have been learnt from the Bank's involvement. They also present the Bank's current assistance strategy for the sector. Electricity Supply and Demand 1.06 At present, India's power systems have an installed capacity of over 62,700 MW (Annex 1.1). This makes their size comparable with that of France, the United Kingdom, and all of sub-Saharan Africa excluding the Republic of South Africa. In FY90, India generated 245,000 GWh -- about 702 from coal stations, 25? from hydro stations, and 5? from gas, oil and nuclear stations. Grid supply has expanded quickly: in FY82 installed capacity was only 32,350 MW and generation was 114,000 GWIl. More than half (51Z) of electricity demand is attributable to industrial consumption; 22? to agricultural use; 15? residential; 6? commercial; and the balance largely due to public services. The growth in electricity demand has been accelerated by relatively low powir tariffs which in turn has fostered wasteful end-use of energy. The potentiul impact on demand of adopting economic pricing is significant; a recent estimata projects a reduction in capacity requirements by nearly 900 MW a year over the next ten years. Yet even if the sector were to achieve the full savings potential from a progressive implementation by GOI of pricing reforms and demand management programs, the need for major capacity additio,ns will remain. Organization of the Power Sector 1.07 Public Utilities. Responsibility zor electricity supply is shared constitutionally between GOI and the States. Through the Department of Power (DOP) of the Ministry of Power and Non-Conventional Energy Sources, GOI controls the Central Electricity Authority (CEA), the National Thermal Power Corporation (NTPC), the National Hydroelectric Power Corporation (NIiPC), the Rural Electrification Corporation (REC), and, through CEA, the Regional Electricity Boards (REBs). DOP also controls the Power Finance Corporation (PFC) and the newly-created National Power Transmission Corporation (NPTC). CEA's tasks are to develop a national power policy and coordinate sector development. NTPC and NHPC are bulk supply utilities which sell power to the SEBs. REC plans and finances most investments in rural electrification. The REBs coordinate the dispatch and inter-state power exchanges in each of the country's five regional power svstems. Their function is, however, limited by their lack of statutory authority and by weaknesses in the structure of bulk power tariffs. PFC mobilizes resources for the SEBs. NPTC will coordinate the development and operation of transmission systems. Initially these will be systems associated with NTPC's and NHPC's power stations; since August 1991, NPTC has started to operate and maintain NTPC's transmission facilities under a management contract pending finalization of asset transfer. In November 1991, a similar arrangement was entered into with NHPC. 1.08 Under the same Ministry, the Department of Non-Conventional Energy Sources administers GOI's renewable energy program, which is one of the largest among developing countries. The program seeks to supplement conventional power supply with alternative energy systems, e.g., mini-hydro, biomass, wind and solar energy, as well as meet the decentralized energy needs of the rural sector. The program is implemented through the public utilities as well as through energy development boa':ds and the private sector. 1.09 The states con rol the SEBs and the SGCs, which generate about 75Z of electricity supplies and provide most of the distribution to final consumers. Although they are supposed to be autonomous, in practice the SELs and SGCs must obtain state approval for decisions on investments, taritfs, borrowings, salary and personnel policies. The SEBs are grouped into five regional interconnected systems. The activities coordinated regionally through the REBs include generation schedules, overhaul and maintenance programs and power transfers, 1.10 Private Utilities. At Independence, private utilities and licensed local authorities together provided about &0X of public electricity supply. The Electricity (Supply) Act of 1948 (the Act) creeted the SEBs and entt-usted tlhe' Boards with primary responsibility for public power supply. The Act also made the SEBs responsible for regulating private utilities. The Industrial Policy Resolution of 1956 subsequently defined aspects of generation and distribution which were to be the exclusive responsibility of the states. Most licensees were taken over by the SEBs when their licenses expired, and no new licenses have been granted since 1956. Only five private utilities remain: Bombay Subuirban Electric Supply Limited, Tata Electric Companies, Ahmedabad Electricity Company, Surat Electric Company, and CESC Ltd. (formerly Calcutta Electric Supply Corporation). Together they account for about 5 of public power supplies in India, and are concentrated in the major urban centers. In addition, an estimated 6,250 MW of "captive" generating facilities are operated by industries. GOI Strategy in the Power Sector 1.11 ihe Five-Year Plan eontains the only formal statement of India's energy and power policies. The Eighth Plan, which is expected to cover the period 1993-1997, is still to be finalized. On the basis of preparatory documents, the objectives of GOI's energy policy are to: (a) achieve energy self-reliance; (b) reduce oil import dependence; (c) meet rural energy needs; and (d) improve the efficiency of energy production and use. Specific investment objectives in the power sector under the Eighth Plan are likely to include: (a) accelerating the completion of ongoing projects, particularly hydroelectric investments; (b) encouraging the corstruction of energy efficient and environmentally benign gas-based combined cycle plants; (c) rehabilitating existing plants; (d) improving the quality of ceal supplies through better coal preparation; (e) increasing investments in transmission and distribution relative to investments in generation; and (f) continuing the modest development of nuclear power. 1.12 To achieve the Plan objectives, it is essential that GOI and the state governments tackle the sector's financial and institutional problen-. GOI is constrained in its ability to act unilaterally in the power sector at the State level. There are two main reasons for this: (a) the SEBs and SGCs are owned by the states and are cften operated as extensions of their own administrations; frequently the states use them to pursue socio-political - 4 - objectives; and (b) under India's federal system, allocations of budgetary resources for investments to the states are made following an automatic mechanism -- the Gadgil Formula -- and so it is politically impossible for GOI to condition budgetary assistance to the states. To promote improvements in the sector, GOI can only exercise its leverage through those discretionary funds not subject to the Gadgil formula. These funds essentially include PFC financing and funds from external assistance. 1.13 GOI has recently taken a number of steps to ensure that its discretionary funds are used to effect reforms in the SEBs. The creation of the Power Finance Corporation is one step in this direction. PFC is expected to finance about a quarter of the SEBs' financing requirements for the Eighth Plan period. In line with its operational policies, PFC will lend only to utilities who have undertaken to implement Organizational and Financial Action Plans (OFAPs), endorsed by their respective states, aimed at improving the utilities' resource mobilization and operational efficiency. These OFAPs typically include elements such as: (a) actions, including tariff adjustments, to allow the utilities to reach, in a period of no more than tbree years, the minimum 3% rate of return, after interest, on historically valued assets, as required by the Act; (b) commitment from the states to pay cash subsidies to the utilities whenever tariff revenue is insufficient to meet the minimum 3? rate of return; (c) specific plans to reduce the utilities' receivables; and (d) introduction of clauses in the utilities' tariff to allow them to recover automatically, from their consumers, any increase in the cost of both fuel and purchased power. In addition, GOI has :nformed the Bank that starting in FY92/93 external assistance will be allocated to those projects for which counterpart funds needed to complete the project on time are available. 1.14 Faced with a growing "power gap" and diminishing public resources available for the sector, GO0 has taken bold steps in opening the power sector to the private sector. In the July 1991 modification to the Industrial Policy Resolution, the power sector was removed from the list of activities previously reserved for tie public sector. In September 1991, the Act was amended to lift many of the regulatory disincentives to private investment in the rower sector. In particular, it provides for 100t ownership of power companies by the priv-te sector, an extended pericd of license to 30 years with 20-year renewals and increased financial returns. Provision is made for private generating companies and captive plants to sell power to the SEBs. GOI would also allow foreign companies to have a 100% participation in power projects. A High Powered Board chaired by the Cabinet Secretary was established in October 1991 to promote private investment and accelerate the clearance of projects. So far, a total of 21,558 MW of generating plant projects have been advertised by the various states for private sector investment; of this, private investors have expressed interest in developing schemes involving 5,554 MW. GOI's increased reliance on the private sector will also lead in the medium term to improved financial discipline among the SEBs since private investment would only go to states with an attractive policy environment and a financially sound SEB. 1.15 Th;se measures are to be complemented by: (a) GOI's increased reliance on the central generating companies (NTPC, NHPC) for the expansion of supply in order to improve cost recovery and ensure that priority projects are - 5 - implemented efficiently; (b) the strengthening of NPTC to rationalize the construction and operation of India's bulk transmission system; (c) the establishment of Regional Tariff Advisory Committees to provide advice to state governments, SEBs and central generating utilities on the level and structure of bulk and retail tariffs needed to assure the financial viabiliLy of all agencies in the sector; (d) the adoption of energy conservation measures. Past Bank Group Strategy in the Power Sector 1.16 Over the last decade, IBRD followed a three-pronged strategy in its lending operations in the power sector in India. Firstly, it supported agencies owned by GOI as a means of effecting sector-wide improvements. Secondly, it financed a selected number of SEBs whose managements and state governments appeared to be committed to reforms. Finally, and in close cooperation with IFC, it financed existing private power utiliti-s to improve their financial and economic efficiency and to encourage GOI to lower citry barriers for new investors. The success of this strategy has been uneven. 1.17 Experience with Central Power Agencies. IBRD's support for the central agencies has provided many opportunities for institutional strengthening. IBRD helped NTPC to become India's model utility and, in the process, IBRD also helped to improve operational efficiency nationwide. NTPC provides about 132 of India's total power supplies and the operational efficiency of its plants consistently surpass that of the state utilities. Its investment projects were generally completed on schedule and within budget, reflecting the strong project management capability it has developed. The procedures introduced by NTPC in quality control helped improve the quality standards of power equipment supplied by IndiRn manufacturers. 1.18 However, GOI's and the Bank's efforts to use NTPC to develop the power sector into an efficient and commercially viable part of the economy have fallen considerably short of the objective. This is due to the pervasive nature of the sector's financial problems and the relative autonomy of the states which limits what can be achieved through involvement exclusively w-'th central agencies. The financial health of NTPC has been threatened by the continued accumulation of receivables from the SEBs. At the end of May 1990 they stood at the equivalent of about six months of sales. At that time, in an effort to eliminate the arrears by October 1993, GOI decided to underwrite their payment by "attaching" in NTPC's favor, portions of the states' budgetary allocation. While GOI has kept its end of the bargain, SEBs continue to accumulate arrears. The Bank has informed GOI and NTPC that support for new proiects would no longer be possible unless actions to reduce NTPC's receivables position are taken. The Bank is currently refraining from further commitments to NTPC, including a proposed loan of US$375 million which had been negotiated and wab originally scheduled for Board presentation in FY90. GOI has arranged a "debt-equity" swap with the Uttar Pradesh State Electricity Board (UPSEB) (NTPC's main debtor). It involves NTPC taking over Uttar Pradesh's Unchahar Power Plant in exchange for receivables and increasing the value of UPSEB's letter of credit to the level of expected sales from NTPC. The negotiations are well advanced and the takeover is expected to be completed by early 1992. In the long-term, the problem of NTPC's collections will not be resolved until the financial performance of its clients is substantially improved through tariff adjustments and collection improvements. Since the Center has no direct means to ensure that financial performance of the state utilities improves, the centrally-owned utilities have no option but to enforce financial discipline through meanz such as (a) letters of cre?dit set at the level of its sales to each client, ndlor (b) limiting the supply of power to the level of payments received. GOI is supporting moves in these directions. 2.29 Following the recent approval of Amendments to the Electricity Act, GOI has now the authority to set the tariffs of the central utilities. To rationalize power systems operations, GOI has decided to implement a two- part bulk tariff for NTPC and NHPC. The proposed tariff revision is expected to be finalized by March 1992. Its implementation would provide incentives fcr a more economic dispatching of bulk power supplies within and among regional grids. 1.20 Experience with SEBs. Beginning in the mid-1980s, IBRD emphasized direct involvement with state governments and SEBs, attempting to improve selectively the performances of the Boards. Tariffs and financial performance are key components of IBRD's strategy towards the SEBs. However, these are also the areas in which progress is most difficult to achieve since the state governments historically would rather promise additional financial support to the SEBs, through subsidies, than authorize unpopular tariff increases. However as a general rule, those subsidies are not paid, leaving the SEBs insolvent. IBRD's close lending relationship with the SEBs has been successful in the case of a few of the stronger SEBs, such as the Maharashtra State Electricity Board, which has shown efficiency improvements, relatively better financial performance, and willingness to innovate. Projects with institutionally and financially weaker SEBs carried a correspondingly higher risk. Indeed, the performance of several SEBs did not meet expectations. As a result, the Bank had to apply remedies as follows: (a) in 1989, the loan to Delhi Electric Supply Undertaking (DESU) was canceled; (b) in April 1991, disbursements under the Uttar Pradesh Power Project were suspended; and (c) in June 1991, the SEBs in the States of Karnataka, Himachal Pradesh and Kerala were advised that disbursements would have to be suspended unless actions to meet the financial covenants were taken. Th; Bank's stance has yielded positive responses as the concerned state governments have come to recognize their responsibility for ensuring the financial integrity of their SEBs and the critical role of proper tariff levels in achieving tl-is objective. DESU has recently been authorized to substantially increase its tariff even in a difficult political environment and now serves as a model case regarding tariff level and structure. The Karnataka SEB has been able to comply with its financial covenants in September 1991, when the Government of Karnataka paid the rural electrification subsidy, settled part of its arrears and converted part of the government loans into equity. Similarly, the State of -imachal Pradesh significantly reduced its payables to the SEB and waived interest payments on government loans due from the SEB for FY91. The &overnment of Kerala has exempted the Kerala SEB from paying electricity duties for FY90 and FY91, however, since this is insufficient for the SEB to meet its financial covenants, the Bank has not extended the closing date of the loan (Loan 2582-IN). A 33% tariff increase is to be implemented by Kerala - 7 - as of January 1, 1992. As concerns UPSEB, the state government decided to allow a tariff increase of 281 effective January 1, 1992, which should bring its financial performance for 1992 in line with the Action Plan agreed under the Uttar Pradesh Power Project. As a result of these actions, the Bank held in abeyance the cancellation of the outstanding balance of Loan 2957-IN. A decision to lift the suspension of disbursement will be made upon formal notification of the implementation of the tariff adjustment. At that time, it will also be necessary to reassess the scope for loan cancellation based on the latest cost-estimates which reflect the impact of Rupee devaluation on project costs. 1.21 Experience with Private Utilities. The Bank and IFC's experience with the private utilities has been in general more satisfactory. Unlike the SEBs, the private utilities have beei allowed by their respective state governments to operate autonomously and in a technically and financiall, viable manner. They have not suffered from the institutional and financial problems of the GOI-owned central entities, because the power they generate i largely fed into their own distribution networks which supply urban residential and industrial consumers. Bank Group Support 1.22 IBRD has made 32 IBRD loans (US$6.4 billion) and 18 IDA credits (US$2.3 billion) for power projects in India (Annex 1.2). Twenty-seven projects have been completed: 20 for generation; four for transmission; and three for rural electrification. Ongoing projects include ten for generation (three of which are for hydro power plants); three for transmission; and seve which include a mix of generation, transmission and distribution. Six of the IBRD loans have been extended to private utilities. The physical implementation of most Bank power projects in India has proceeded slowly, but eventually, after significant initial delays, has broadly met expectations. However, loan and credit disbursements continue to show large outstanding balances (US$3,869 million, as of June 30, 1991). These are due primarily tc the very long construction periods for generation projects compounded by frequent delays in procurement and in foreign exchange and import license clearances by the various ministries, and the increasing number of projects under implementation. Undisbursed balances have been pushed up further by frequent cost under-runs on major equipment contracts. The latter are due tc the softening of international markets in the mid-1980s and the rapid real devaluation of the Rupee. The Bank is reviewing the level of potential savings in its power loan portfolio for India with a view towards cancelling those balances which are no longer required for project implementation. 1.23 IFC has made five investments totalling US$203 million to four ol the five private power utilities in India. These investments were made in Al and TEC in FY89, in TEC and CESC in FY90, and in BSES in FY91. All the projects are progressing satisfactorily. Results of these Efforts 1.24 Expansion and Quality of Service. The Bank's support to India's power sector contributed to the rapid expansion of the country's power suppl - 8 - from 32,350 MW installed capacity in FY82 to over 62.700 MW today. However, the quality of electricity supplies remains unsatisfactory. Interruptions and reductions in supply and voltage are common. The poor quality and unreliability of public supplies cause consumers to purchase costly back-up generating capacity which uses scarce liquid fuels. Technical and commercial losses exceed 20? of net generation. 1.25 Operational Efficiency. In parallel with expanding supply, the sector has made some encouraging ef.iciency gains. For example, the plant load factor has increased from 44Z in FY81 to 55? in FY90. This means that every 1 kW of capacity now provides 1,031 kWh (27?) more electricity per year than in FY81. Ir, addition, the rate of coal consumption by power stations has been cut by about 10? since FY81. It now requires 720 tons of coal to generate 1 GWh, compared with 802 tons in FY81. This saves approximately 13 million tons of coal annually (about 82 of the sector's total consumption) and is worth about US$300 million/year. These improvements reflect a strengthlening of plant maintenance and operations and are commendable in view of the deteriorating quality of coal the sector is receiving. A significant institutional gain is the one-third reduction in the ratio of employees to consumers from 29 employees per 1,000 consumers in FY81 to 19 employees at present. Many of the efficiency and institutional improvements are attributable to the rapidly expanding shares of NTPC and the private utilities in India's power system since FY83. 1.26 Financial Performance. Weighted retail tariffs have increased slightly since FY82' in constant price terms although they have remained at about 502 of the long run marginal costs (LRMC). Increases in real costs (particularly for fuel and wages) have largely neutralized the increases in efficiency and real tariffs. In the meantime, tariff differentials among consumer groups have widened. Industrial consumers have taken the brunt of the increases over the last ten years and their tariffs are in nost states now close to, and in some cases even above, LRMC. Agricultural tariffs, on the other hand, actually have fallen in absolute terms and now cover less than 10? of their supply costs. Compounding the problem is the poor collection from agricultural users, high technical and non-technical system losses, leading to an increasingly large financial burden imposed by the sector on the power system. Partly as a result of this subsidization, as shown in Annex 1.1, agriculture's share in total consumption has grown from about 17? in FY82 to 22Z in FY90. A similar situation applies to the case of residential uses of electricity. Accordingly, GOI has put pressure on the SEBs and the central utilities to raise tariffs. Since April 1990, 12 SEBs, out of 18, have increased their tariffs, and both Kerala and Uttar Pradesh are expected to increase their's effective January 1, 1992. In September 1991, the State Power Ministers agreed to have a minimum agricultural tariff, bringing the beginning of a solution to this problem. In addition, the need for SEBs to establish automatic cost recovery surcharges for fuel, freight, etc. was recognized. The implementation of these initiatives are partly reflected in the recently announced tariff reforms for Kerala and Uttar Pradesh. I Using FY82 prices, from 40 Paise/kWh in FY82 to 47 PaiselkWh in FY90. 1.27 The combined financial losses of the SEBs have been steadily increasing. When operating losses, non-payment of subsidies and poor collections are taken into account, the SEBs had a negative internal cash generation equivalent to US$4.1 billion from FY86 to FY90. Deficits of this magnitude materially affect public finances and, because of late payments to suppliers, create major financial problems for NTPC, NHPC, Indian Railways, Coal India, and Bharat Heavy Electricals Limited (BHEL), the largest local manufacturer of electrical equipment. As a consequence, GOI was forced in FY91 to earmark central transfer assistance to these entities, funds which otherwise would have been allocated to the budgets of the delinquent states. 1.28 Conclusion. Notwithstanding tbe efficiency gains secured by the sector in recent years, there is an urgent need for further improvement. Key constraints are the lack of financial autonomy and the poor financial discipline of the publicly owned utilities, as well as the absence of commercial incentives in many markets and subsidized power prices. Physically, these constraints cause India's power systems to provide less power and power of a poorer quality, at higher cost, than they otherwise would be able to provide. The economic costs of shortages and poor quality supply are exacerbated by inefficient end-use of power which is in turn, invited by mispricing and non-collection of dues. 1.29 Performance audits conducted for the Second Power Transmission Project (Credit 242-IN) and the First and Second Rural Electrification projects (Credits 572-IN and 911-IN) highlighted the difficulties of effecting institutional improvements in the absence of clear division of responsibilities between the central entities and the SEBs. Project Completion reports show that the Third and Fourth Transmission projects (Credits 377-IN and 6C4-IN) experienced similar difficulties; despite some progress, in general, SEBs did not respond to GOI's initiatives. The lessons learned from these projects, as well as the experience gained in dealing with the problems of the sector, had an important bearing in the design of the proposed project. Towards a New Approach in the Power Sector 1.30 GOI's strategy towards the power sector evolved to a large extent from the intensive policy dialogue with the Bank over the last year and a half. The Bank supports the major policy reforms recently undertaken, namely the channelling of discretionary funding by the center only to the performing states and the increased role for the private sector. However, much needs to be done to begin solving the structural problems of the sector. 1.31 The evolving lending strategy would continue to support capacity additions through the private sector and efficient public utilities while at the same time giving increased attention to improvements in the utilization of existing operating assets. It would seek and support actions by GOI to address the longer-term issues in the power sector such as problems in the current allocation process (not only in the power sector but also in coal and natural gas), the planning process, the operational efficiency of the power system, the institutional set up of the state utilities and financing needs of the power sector will be explored. In addition, issues affecting energy - 10 - conservation and socio-environmental aspects of power development will be taken up. Bank lending for power would focus on: (a) promoting domestic and foreign private investments, including joint ventures between the private sector and well managed public utilities; (b) projects implemented by either center or state utilities benefiting states whose SEBs either perform in a satisfactory manner or have started implementing credible plans underwritten by their states to improve their performance and finances with emphasis on significant up-front tariff adjustments; (c) investments that promote energy conservation and demand-side management; and (d) innovative, small-scale developments such as mini-hydro, co- generation and non-conventional energy schemes which are environmentally sound and cost-effective. IBRD will also continue to assist the Indian power sector in addressing the environmental and sociological aspects of power development. 1.32 The proposed project fits into this strategy because (a) it is directed to finance investments that will enhance the efficiency of existing assets, such as removing bottlenecks in transmission and distribution systems, engineering studies for systems renovation, environmental upgrading of power plants, and institutional strengthening of selected SEBs; (b) PFC lends only to SEBs/SGCs that either are nerforming or have agreed, with the support from their states, to introduce long lasting improvements in their operations and finances; and (c) PFC financial support to SEBs/SGCs is conditioned upon their compliance with conditionality aimed at ensuring that said improvements are actually implemented. II. THE BENEFICIARY Formation of PFC 2.01 PFC is a wholly owned entity of the Government of India. It was incorporated in July 1986, under the Companies Act of 1956, and began operations in early 1988. The objectives set in its Memorandum of Association allow PFC to undertake an ample array of financial activities aimed at supporting the development of the power sector in India. These activities include the financing, to both public and private power utilities, of: new capacity, renovation and modernization of power plants, system improvement, energy conservation, maintenance and repair of fixed assets, pre-investment activities, research, and consultancy services. 2.02 GOI, through PFC would allow most of the non-budget funding of the utilities, representing 25Z to 30Z of their total financing requirements, to be linked to tangible improvements in the utilities' operations. To implement this objective, PFC would grant loans to SEBs/SGCs conditioned upon the - 11 - implementation of actions which would improve their financial and operational performance. This strategy is reflected in an Operational Policy Statement (OPS) (Annex 2.2) prepared by PFC and found satisfactory by the Bank. 2.03 The developmental function assigned to PFC, in the form it is now conceived, has not been tried before in India. While the role of the typical sectoral financial institution would be to mobilize resources for a particular sector, PFC's main objective is to promote improvements in the power sector operations. The financial function is simply an instrument that provides the necessary leverage to help ensure PFC's effectiveness. It is envisaged that, in the long term, most power utilities should reach a financial performance that allows them access to the financial market on the basis of their own creditworthiness. 2.04 Lending through PFC offers a number of advantages. Firstly, it represents an improvement over the umbrella-type operations, attempted in the past by the Bank using the Rural Electrification Corporation (REC). The effectiveness of these operations was limited by the weak institutional capability of REC, reflected in poor implementation and supervision performance. Secondly, lending through PFC would allow the Bank to expand its impact in the sector by having access to most SEBs/SGCs in the country, as opposed to direct lending by the Bank, which has to be restricted to a limited number of SEBs/SGCs. Thirdly, because PFC will have frequent operations with most SEBs/SGCs, probably on an annual basis, it will enjoy the advantage of a close and regular contact with them, providing a better potential for enforcing lending conditionality. 2.05 However, it is recognized that for PFC to be successful, it has to develop a strong institutional capability of its own and enjoy considerable autonomy. To ensure that the potential benefits to be derived from lending through PFC actually materialize, the Bank established that any lending to PFC should be subject to the following parameters: (a) PFC should have clearly defined, transparent and strict criteria for its lending decisions (paras, 2.09 and 2.16); (b) these criteria should apply not only to Bank funds on-lent through PFC, but to all PFC's resources (para. 2.16); (c) sub-borrowers that do not meet the agreed criteria should not be granted any loan from PFC (para. 2.16); (d) PFC should take remedial action against sub-borrowers which default in their undertakings with PFC (para. 2.14); and (e) the agreements between the Bank and GOI/PFC should provide for monitoring by PFC of compliance with the agreed lending criteria and undertakings by sub-borrowers to PFC, and for suspension of Bank disbursements if PFC does not fulfill its obligations (paras. 4.20 and 4.21). - 12 - Organization and Staffing of PFC 2.06 PFC is run by a Board of Directors which consists of a Chairman and Managing Director, two full-time directors (for finance and technical matters), and four directors representing the Department of Power, the Central Electricity Authority, the Planning Commission, and the Ministry of Finance. This composition of the Board enhances the coordination between PFC and different decision-making centers in the power sector. 2.07 The Corporation is organized along three divisions, or groups -- one for technical matters, one for finance, and one for operations. Each group is headed by a Director. The Technical Group appraises new projects and monitors the portfolio of loans. The Finance Group is responsible for the financial operations of the Corporation and provides support to the Technical Group on the financial aspects of projects. The Operations Group provides critical support to the SEBs in preparing their Operational and Financial Action Plans (OFAPs) and monitors the implementation of these plans. As explained in para. 2.1 , these OFAPs are the framework used by PFC to design the conditionality for each one of its operations. The Operations Group also manages the human resources of the Corporation and provides leadership in the formulation of policies, preparation of procedural guidelines, and study of issues affecting the power sector. PFC is aware of the need to periodically review the effectiveness of its structure and make adjustments as needed. The cu-rent organizational structure of PFC is presented in Annex 2.1. 2.08 PFC's top management is experienced and has done an outstanding job in providing the basis for the future development of the Corporation. PFC has managed to put together a group of about 130 carefully selected professionals. The Corporation is gradually developing a work culture characterized by very demanding standards of quality and a high degree of motivation among staff. In addition, PFC has retained a small nucleus of high-level consultants experienced in different aspects of power sector operations. Although several key positions have been filled with staff on deputation from other government entities, as a way to facilitate recruitment, PFC is confident it will be able to retain those considered best qualified for their respective jobs. PFC is gradually developing a capability for appraising and monitoring the implementationi of projects, and a special training program for its staff will be included in the project (para.3.06). The Technical Assistance component of the project also includes support in the development of policies and procedures to enhance PFC's capability to prepare and monitor projects and to promote the institutional development of its borrowers. Operational Policy Statement 2.09 PFC has prepared an Operational Policy Statement (OPS) which describes the Corporation's rationale, its operating philosophy, objectives, programs, and procedures. A summary is presented in Annex 2.2. The purpose of the OPS is to establish the policies that will guide PFC in its relations with clients and in its own operational and financial activities. The financial policies embodied in the OPS are summarized in para. 4.16. Changes in the OPS are expected to be called for as a clearer picture of PFC's - 13 - activities emerges. The OPS is the instrument that reflects the major agreements between PFC and the Bank on how the Corporation will conduct its operations, and the implementation of the proposed project will be carried out in accordance with the OPS (para. 4.20). 2.10 The Bank and PFC have reached agreement on the contents of the OPS. Because PFC's clientele is confined to a limited number of borrowers, operating in one economic sector, and are in rather poor financial health, steps have been tEken to mininize the financial risks to PFC. These steps include, inter-alia, the design of a set of repayment guarantees, limits on PFC's exposure, and a provision that PFC will not reschedule its loans (para. 4.16). Pre-allocation of PFC's Funds 2.11 To help preserve PFC's autonomy, GOI and PFC have adopted a prudetc policy of not pre-allocating PFC's funds by states. Pre-allocating these funds would undermine PFC's basic developmental objectives and would render totally ineffective the operating policies included in the OPS.2 Given PFC's need for autonomy to promote improvements in the power sector, during negotiations confirmation was obtained that PFC's funds will not be pre-allocated but will be lent following the pre-agreed criteria spelled out in para. 2.16 and included in PFC's OPS (para. 6.03 (b)). Institutional Strengthening of PFC Borrowers 2.12 The core of PFC's effort to promote better standards of operational and financial efficiency in the state power utilities is the preparation and implementation of action plans tailored to each particular utility. PFC's Operational and Financial Action Plans (OFAPs) consist of a set of actions, to be implemented according to an agreed timetable, aimed at correcting the most critical deficiencies of the particular SEB. These OFAPs typically include elements such as: (a) actions, including tariff adjustments, to allow the utilities to reach, in a period of no more than three years, the minimum 3% rate of return, after interest, on historically valued assets, as required by the Act; (b) commitment from the states to pay cash subsidies to the utilities whenever tariff revenue is insufficient t. meet the minimum 32 rate of return; (c) specific plans to reduce the utilities' receivables; and (d) introduction of clauses in the utilities' tariff to allow them to recover automatically, from their consumers, any increase in the cost of both fuel and purchased power. Although the SEBs(SGCs are responsible for preparing the OFAPs, PFC's staff provide initial support in diagnosing major problems, and participate in a manner that ensures that the views of the utilities' management and, eventually, the states' officials are expressed in the formulation of corrective actions. The utilities also would be responsible for retaining consultants to assist in implementing the OFAPs, although PFC could include the cost of financing this consultancy in its loans to the utilities. The general concept of OFAPs, the elements that enhance their 2 However, the need to avoid pre-allocating PFC's funds does not mean that GOI and PFC cannot develop indicative targets for planning purposes. - 14 - effectiveness, and the steps followed in their preparation are presented in Annex 2.3. 2.13 The development of an OFAP for each of the SEBs included in the proposed project was integral to the preparation of the sub-projects presented by PFC for Bank fin3ncing. The OFAPs for the SEBs of Punjab, Andhra Pradesh, Madhya Pradesh and Gujarat Lave been approved by the concerned state governments and accepted by PFC. They contain a comprehensive set of actions addressing the most critical issues of each SEB including among others tariff restructuring, payment by the State of cash subsidy support, billing and collection, system efficiency, materials management, and financial and accounting control. The key elements of these OFAPs are summarized in page 5 of Annex 2.3. The impact of the OFAPs on the SEBs' financial operations have started to be felt. In FY1990 the rates of return of these four SEBs were: - 2.5% for Punjab (PSEB), 0.182 for Andhra Pradesh (APSEB), 3.3% for Madhya Pradesh (MPSEB), and -8.0% for Gujarat (GSEB). All four have since adjusted their tariffs: PSEB by 14% in FY91, APSEB by 20% in FY91, MPSEB by 10% in FY91 and 12Z in FY92, and GSEB by 11% in FY91. MPSEB continues to meet the target 3% rate of return. APSEB is estimated to achieve it in FY1992 and PSEB and GSEB in FY1993. Without the tariff and subsidy payment provisions in the OFAPs, the returns in FY1993 are projected to be significantly lowar at: -6.6% for PSEB, -2.42 for APSEB, -7.0% for MPSEB, and -11.2X for GSEB. Likewise, a number of actions have since been taken by the SEBs with respect to settling of receivables, payment by the state governments of subsidy, improving inventory management, and computerization of billings and collections. 2.14 The practice of agreeing on OFAPs as a criterion for lending should not be limited to sub-borrowers under the proposed Bank loan. PFC concurs with this policy dnd as of June 30, 1991, it no longer considers new requests for loans from SEBs that have not presented a satisfactory OFAP. The need for SEBs to achieve the minimum 3% rate of return has been underscored by PFC in its dialogue with the SEBs and in FY92, PFC has started to require SEBs and State Governments to agree on a time-bound program to achieve this minimum return. The implementation of the OFAPs will be made part of PFC's legal agreements w'th its borrowers. To give force to the OFAP, it is required that both the State government as well as the SEB's management commit themselves, in writing, to implement the OFAP. PFC intends to closely monitor the implementation of the OFAP as part of its regular supervision activities, and to provide the necessary support to the SEBs to facilitate implementation. Lack of compliance with the OFAPs could trigger the application of remedies established by PFC in its guidelines. These guidelines (Annex 2.2) include suspension of disbursements and cancellation of the loan and denial of access to future borrowing. Lending Criteria 2.15 PFC is empowered to lend to anv entity, public or private in the power sector. However, in its initial years it will concentrate on supporting the SEBs and the SGCs, where the developmental needs are considered the most critical. PFC has established priorities to guide its lending operations, which include the following four activities: - 15 - (a) renovation and modernization of generating plants; (b) system improvement; (c) expansion of transmission and distribution systems; and (d) completion of ongoing generation projects. 2.16 PFC reviews both the eligibility of the borrower as well as that of any proposed project. To be eligible for PFC financing, a utility should undertake to implement an OFAP (para. 2.12) agreeable to PFC to improve its operations and finances. In addition, any project proposed must satisfy six criteria, as follows: (a) the project must be economically justified, with an economic rate of return of not less than 12Z; (b) the project must be technically sound; (c) the technical solutions proposed in the project must be the least cost option; (d) the project must be compatible with existing expansion plans; (e) the solutions proposed in the project must meet acceptable environmental and social impact standards; and (f) the schemes must have obtained all the clearances required by state and federal agencies. Schemes for environmental upgrading of power stations must meet acceptable engineering standards, and should be the most cost-effective means of mitigating environmental effects. PFC's Loan Processing Procedures 2.17 Borrowers take the initiative in presenting requests for financing. When a request is received, PFC carries out an appraisal of the project and of the entity. This rnpraisal includes a review of the technical aspects of the project, its economic justification and environmental implications and an assessment of the finances and operations of the implementing agency. PFC staff are organized regionally to expedite the appraisal process and to allow the Corporation greater familiarity with each client's special circumstances. An outcome of this analysis is for the potential borrower to prepare an OFAP, with PFC support. The OFAP then provides the basis for the conditionality in the event PFC decides to finance the project. After the OFAP is approved, it is updated about once a year and the conditionality is adjusted in subsequent operations. PFC's lending terms are discussed in para. 4.14. 2.18 Disbursements of PFC's funds typically are made directly to the supplier when the supplier is a government entity, or through commercial banks - 16 - if otherwise. PFC's overall disbursements procedures have been found acceptable by the Bank. To allow borrowers to make payments in small amounts, a revolving fund of not more than 15Z of the loan amount may be established by PFC. As of March 31, 1991, PFC had gras.ted 352 loans to 21 clients and it had lent a total of Rs 33.6 billion (about U;$1.3 billion). A summary of PFC's lending operations is presented in Annex 2.4. Collection Procedures 2.19 PFC has established satisfactory collection procedures. The Corporation notifies its clients in writing 15 to 20 days before payments are due, and it has developed a system with its bankers to expedite transfers of funds collected. In the event payment is not made on the due date, one week later PFC issues a notice threatening legal action against the borrower and guarantor. If the situation remains unsolved after 60 days, PFC applies the remedies it has established, including suspension of disbursements, cancellation of the undisbursed amounts and making the guarantees effective (Annex 2.2, Attachment). Although these procedures appear sound, PFC's experience is still too limited to allow a final assessment of their effectiveness. PFC's collection performance would be monitored closely during supervision. Accounting and Auditing 2.20 A complete accounting system, in conformity with the Companies Act (1956), was recently installed with the help of consultants and its computerization is advancing. PFC conservatively recognizes income only when actually received and not on an accrual basis. However, an accrual record is maintained to monitor the maturity of arrears. PFC's statut' y auditor is a private firm appointed by GOI on the advice of the Comptroller and Auditor General, who may also elect to carry out his own audit. PFC's audit reports have been produced on time and they were reviewed by the Bank and found satisfactory. During negotiations PFC agreed to submit to the Bank, no later than two months after the end of each fiscal year, unaudited financial statements, and no later than six months after the end of the fiscal year, copies of said financial statements certified by an independent auditor acceptable to the Bank, accompanied by an auditor's report. The financial statements will include: Income Statement, Statements of Cash Flow, and Balance Sheet (para. 6.04 (a)). Environment Monitoring Unit 2.21 PFC is creating a specialized unit to assist its borrowers in preparing the environmental and social dimensions of the projects submitted to the Corporation. This unit also will be responsible for coordinating the preparation of Environmental Impact Assessments and monitoring their implementation. The Bank has provided some preliminary guidance in the make up of this unit and PFC is actively recruiting staff. Annex 2.5 presents the scope of the work of this unit. - 17 - Monitoring of Projects 2.22 PFC has developed an efficient system for monitoring the physical implementation of the projects it finances. This system includes progress reports and period' visits. In the future, as OFAPs with different borrowers are approved, PFC also will need to strengthen its capability for monitoring their implementation. The training and technical assistance programs included in the proposed operation will support the development of PFC in this respect (para. 3.06). Failure by the borrowor to comply with the conditionality agreed, incluaing the implementation of the OFAP, will trigger application of remedies (para. 2.14). Management Information System 2.23 PFC has been gradually developing a management information system (MIS) which provides control at different levels of the corporate structure. The Corporation is aware that the MIS will need to be enhanced as the volume of its operations grows. Along these lines, PFC is conceptualizing a computerized system that will allow different units of the organization to share common data bases, thereby improving efficiency and consistency across the organization. The technical assistance program under the proposed loan would provide support to enhance the Corporation's MIS. Financial Planning, Budgeting and Controls 2.24 PFC has been introducing systems to support its financial management. It has a computerized financial model routinely used in assessing the impact of alternative policies, levels of operations and degrees of performance. Similarly, its budget system and control procedures are adequate for the current level of operation, but will need to be enhanced to handle PFC's future requirements. The institutional development component under the proposed project would support this objective. III. THE PROJECT Project Setting 3.01 While India has made commendable progress in expanding its electricity supply in recent years, shortages still persist which now are equivalent to about 22Z of maximum power demand and 92 of total energy demand. Moreover, the quality of electricity needs improvement, particularly with respect to the continuity of service and regulation of voltages and frequencies. Poor quality supply in turn results in frequent industrial equipment burnouts and higher than necessary production costs. In 1989, the Bank conducted a study to ascertain the causes of major power system inefficiencies in India and possible actions to correct them. The project a India Power Sector Efficiency Review (In two volumes) - November 30, 1989 - Report No. 7878-IN. - 18 - seeks to address several of the inefficiencies detected in the studs in five areas, as follows: (a) Investments in transmission and distribution have not kept pace with investments to expand generating capacity. This imbalance has led to system overloading and, as a consequence, high electricity losses and frequent power interruptions. Moreover, the lack of transmission and distribution capacity prevents full use of generating plants. The project seeks to alleviate these constraints by providing funding for high-priority transmission and distribution investments; (b) SEBs need to address poor maintenance, inadequate controls and operational supervision, poor communication and monitoring systems, lack of trained staff, and unsatisfactory billing and collections. Improvements in these areas, including reductions in non-technical losses, would improve service quality and the cash flow of the SEBs. The project provides funding and technical support for the SEBs to help remedy these deficiencies; (c) The performance of generating plants in India, particularly thermal plants, is below international standards. For instance, thermal plant availability is 10 to 15 percentage points below international norms. Plant renovation and life extension are cost-effective ways to improve availability and reclaim lost capacity. GOI and many of the SEBs already are implementing an important program to partially rehabilitate 164 thermal units. Many thermal units included under the renovation program have been only partially rehabilitated and require further work. In addition many units have become due for renovation since the program was launched in 1984, or were not included in the first phase of the pro-ram. The project includes a component to identify further opportunities for plant modernization and life extension; (d) The environmental operating conditions of many thermal plants in India are substandard. The project includes a substantial component to provide funding for -w .ding the environmental conditions of the SEBs' power s4t.,.on; and (e) The preparation of power projects in India, particularly for hydroelectric plants, is a difficult and slow task which ultimately retards implementation. The quality of project feasibility studies, site investigations, and pre-construction engineering also requires considerable improvement. Inadequate preparation is caused both by an acute shortage of funds in sector institutioiis and by staff limitations in the technical organizations of GOI responsible for this work. Lack of funds also prevents studies from being carried out which would improve the operation and management of the power utilities. The consulting industry for power projects in India is still young; strengthening it would help to supplement the technical resources - 39 - provided by government agencies and establish an avenue for introducing up-to-date engineering practices. The project includes a pre-investment fund to stimulate growth in the local consulting industry. The fund would be used by the power sector agencies wishing to employ consulting fi ms to carry out studies and engineering for power projects. 3.02 PFC is becoming an increasingly important institutional vehicle in promoting efficiency improvements in the SEBs and SGCs. To be effective ir th.is endeavor, PFC needs to: (a) lend a large share of the utilities' financial requirements under terms attractive to them to secure the leverage needed to introduce conditionality; (b) follow financial management practices which ensure its financial viability; (c) have the capability to prepare and supervise a large volume of projects; and (d) provide support to the utilities in designing and implementing their performance improvement plans. The project supports GOI's and PFC's actions in these areas. 3.03 With regard to the first point, the project includes the financing of sub-projects for a selected number of SEBs; this financing would represent an important addition to the funds currently allocated to the SEBs through the Central Plan. Regarding the second point, the project provides assistance to PFC for establishing policies and practices which will reduce its financial risks and ensure its financial viability. With respect to the third and fourth points, the project incorporates a comprehensive institutional development program to enhance PFC's capabilities in project appraisal and supervision. Project Objectives 3.04 The main objectives of the project are to: (a) support GOI efforts to make PFC a viable and effective instrument for effecting improvements in the power sector; (b) strengthen the operations of the beneficiary SEBs by lending only to those willing to undertake acceptable reform programs; (c) foster better use of existing power facilities by reducing constraints in the transmission and distribution systems; (d) mitigate the adverse environmental impact of thermal plants in operation by providing adequate anti-pollution and monitoring facilities; and (e) improve the preparation of power projects and promote the development of the local consulting industry by funding pre- investment studies and engineering for power projects. Project Description 3.05 The project comprises: (a) a program to strengthen PFC's capabilities to discharge its responsibilities; (b) the creation of a pre- investment fund in PFC; and (c) five components to be financed through PFC: (i) the implementation of a pre-identified segment of the lending program of PFC; (ii) environmental upgrading of power plants; (iii) engineering studies for systenm renovation; (iv) institutional strengthening of power utilities; and (v) improvements in SEBs' billing and collection. A detailed descripAion of the project is presented in Annex 3.1. - 20 - 3.06 Institutional Strengthening of PFC. This is a program to strengthen PFC s capabilities to discharge its responsibilities. The program will provide specialized services, equipment, software, and training. The major activities to be covered undcr this program include: (a) enhancing PFC's management information system; (b) developing administrative manuals and procedures to guide internal operations: (c) developing manuals for project appraisal and monitoring; (d) training PFC staff in financial, utility, and project management, power economics, upgrading of power plants, transmission and distribution, and planning and design of distribution systems; and (e) establishing a unit at PFC for sector studies to support the Corporation's operations. 3.07 Pre-investment Fund. The project includes the establishment of a special pre-investment fund at PFC. The fund will be used to finance project preparation and other studies aimed at enhancing the performance of power utilities in the country. 3.08 Financing Through PFC. The project will help PFC finance five types of activities directed to the SEBs/SGCs, as follows: (a) Transmission and Distribution Projects. Includes the financing of a pre-identified segment of the loans for this purpose to be approved by PFC during 1992-94. This segment represents about 8t of PFC's lea.ding program. It includes the financing of the construction of specific sub-projects proposed by eligible SEBs and SGCs. These sub-projects are: (i) sub-transmission and associated distribution works in urban areas; and (ii) transmission lines and substations in the participating SEBs. This being the first Bank operation with PFC, it was considered prudent to limit Bank financing to a set of identified investments in a reduced number of SEBs where the likelihood of a successful reform program is greater, as opposed to providing financing for the entire PFC lending program. Along these lines, the project comprises investments to be made by the SEBs of the states of Andhra Pradesh, Gujarat, Madhya Pradesh, and Punjab. PFC has prepared sub-project appraisal reports (SPARs) for each SEB. Each SPAR includes, among other things, an action plan (OFAP), agreed with the SEB and the State (see section (d) below), and the details of the sub-projects to be financed, their estimated costs, economic and technical justification and an implementation timetable. These four SEBs have already identified about 70? of the transmission and distribution investments under the project. A provision has therefore been made in the project to include investments in one or two additional States where SEBs may become eligible for Bank financing, or to include more sub-projects for - 21 - the four SEBs already identified, as the case may be. PFC will prepare SPARs for the remaining investments as other SEBs become eligible for Bank financing; (b) Environmental Upgrading of Power Plants. The project includes studies, engineering and works to upgrade the environmental operating conditions of power plants; (C) Engineering Studies for System Renovation. This program includes studies for: (i) further improvement and modernization of thermal stations to supplement the rehabilitation investments sponsored by CEA and PFC during the Seventh five-year plan; and (ii) high- priority upgrading of other system components; (d) Institutional Strengthening of Utilities. The project includes a component for the implementation of the institutional development programs for SEBs and SGCs identified in their OFAPs. This assistance will include, among other things, improvements in operation and management, provision of technical and training services, and acquisition of data processing equipment and software; and (e) Billing and Collections. The project covers the promotion of improvements in the billing and collection systems of the SEBs, including studies, equipment, software, and support for establishing the necessary systems and procedures. Status of Project Engineering 3.09 The transmission and distribution sub-projects being proposed for financing are standard works routinely carried out by the SEBs and do not involve complex engineering. Therefore, the SEBs will be responsible for the engineering of these sub-projects. The participating SEBs have staff qualified to plan and design the sub-projects proposed and would have access to technical services by employing consultants under the Pre-investment Fund. Sub-projects under this project component are grouped into three categories: (a) transmission and distribution sub-projects for which engineering at the bidding level is already complete and all necessary approvals by government agencies (CEA, DOP, Planning Commission, etc.) have been granted. This group represents about 60% of the proposed investments in transmission and distribution; (b) transmission sub-projects for which detailed engineering is complete but which are still under review by the concerned government agencies. This group represents 202 of the proposed investments; and (c) transmission and distribution sub-projects for which engineering is still under preparation and government approvalE are pending. This group comprises 20X of the proposed investments. - 22 - 3.10 PFC and SEBs have jointly prepared draft technical specifications and bidding documents for sub-projects under categories (a) and (b). The same documents and specifications will be used, with appropriate changes, for sub- projects under category (). Clearances pending for sub-projects in category (b) are expected to be issued over the first year of project implementation. Final engineering together with the corresponding clearances for sub-projects under category (c) are scheduled to be completed before the end of 1992. At negotiations PFC agreed that only those transmission and distribution sub- projects in categories (b) and (c) that have completed detailed engineering and all the clearances required before December 31, 1992, would be eligible for Bank financing (para. 6.04 (b)). 3.11 Engineering fo, the installation of electrostatic precipitators (ESPs) under the environmental upgrading of plants is currently at the bidding stage for the stations identified at the time of project appraisal. In most cases, however, the proposed environmental actions are limited to the controlling of particulate emissions through the installation of electrostatic precipitators. Additional engineering is needed to determine and design actions in other areas of environmental concern such as water treatment, ash handling, dust control, emissions monitoring equipment, etc. At negotiations PFC agreed that those SEBs participating in this program will conduct, with the assistance of consultants if needed, a full review of the environmental conditions of their stations in order to determine, and subsequently implement, any actions required to meet acceptable environmental standards (para. 6.03 (c)). PFC's environmental unit (para. 2.21) will provide guidance and assistance to the SEBs in identifying consultants when required, and in preparing and conducting the environmental reviews, described in Annex 3.2. 3.12 The studies for system renovation will be conducted by the SEBs with assistance of consultants as needed. The studies will focus on improving efficiency of generating plant, but other system components such as distribution or transmission systems may be included. SEBs wishing financing for system renovation studies will conduct them under terms of reference acceptable to the Bank, prepared for each particular study. Annex 3.3 gives the suggested scope of the system renovation studies and the terms of reference for the thermal plant renovation studies. 3.13 The nature and scope of the training program and of the institutional strengthening of PFC have been identified but further work is needed to refine this program and to formulate a detailed implementation plan. The training program should include identification of training agencies, schedules and duration of training, detailed curricula, priorities, target staff, etc. PFC has prepared terms of reference for the traix, ng program (Annex 3.4), as well as a detailed plan for the first year of its training program. The longer term training program will be prepared by consultants under the United States Agency for International Development (USAID) component of the project. An implementation plan for the institutional strengthening program is presented in Annex 3.5. - 23 - Project Implementation Arrangements and Schedule 3.14 PFC will have overall responsibility for project implementation and for supervising and coordinating implementation of the project components to be carried out by the SEBs. PFC has appraised or will appraise all sub- projects to ensure that they meet the eligibility criteria for financing by PFC (para. 3.15). PFC has furnished the Bank with satisfactory SPARs for four SEBs (in Andhra Pradesh, Punjab, Madhya Pradesh and Gujarat). In addition, at negotiations PFC agreed to submit to the Bank, for prior approval, the remaining items intended to be financed with the proceeds of the Bank loan under each one of the components of the project (para.6.03(d)). PFC will monitor implementation through a well established supervision system already in place. PFC also will prepare periodic progress reports on the project for concerned authorities and the Bank, and will serve as the liaison between the Bank and government agencies involved in the project. PFC will provide assistance to the SEBs in matters related to project implementation directly or through consultants and will help the SEBs identify and select firms to assist them during project execution. PFC will lend funds to the SEBs in accordance with its operational policies for eligible sub-projects and will obtain reimbursement from the Bank in accordance with the loan disbursement arrangements proposed for this project (para. 3.29). 3.15 In order to be eligible for PFC financing under the project, an SEB or SGC must undertake to implement an OFAP agreeable to PFC and the Bank to improve its operations and finances (para. 2.14). PFC has established general eligibility criteria for individual sub-projects (para. 2.16). Bank-financed sub-projects, except for the environmental upgrading of power plants and studies, must meet these criteria. The criteria are as follows: (a) transmission sub-projects over 220 kV must be part of the long term least-cost plan for generation and tran;.mission adopted by CEA; (b) transmission and distribution sub-projects of 132 kV and Lelow must be part of the state transmission plan; (c) the technical solutions proposed must be least cost; (d) sub-projects must be based on a suitable engineering analysis and be technically justified in terms of: (i) operational analysis (i.e., load flow, short circuit, stability analysis, etc.); (ii) improving of service standards (i.e., sub-projects must meet unserved demand, contribute to improvements in voltage and frequency, or increase system reliability); (iii) eliminating system constraints to improved use of existing plant (i.e., deficiencies in transmission capacity); (iii) remedying the overloading of system components; or (iv) directly contributing to reducing losses in the system; (e) the solutions proposed must meet acceptable environmental and social impact standards; - 24 - (f) all sub-projects must have an economic rate of return of at least 12Z; calculated in accordance with the methodology agreed with the Bank (Chapter V); and (g) sub-projects must have all the clearances required by state and federal agencies. 3.16 Sub-projects for environmental upgrading of power stations will have to meet acceptable engineering and environmental standards, and must be the cost-effective means of mitigating environmental effects. In order to encourage utilities to participate in this program, there will not be preconditions for eligibility for Bank financing under this project component. Any power utility requesting funding for these sub-projects is eligible for Bank financing. 3.17 The project comprises a large number of individual sub-projects, each having its own construction schedule. However, the implementation period for the entire project has been estimated at about five and a half years, based on representative transmission and distribution projects financed by the Bank. Implementation would take place between January 1992 and June 1997. Procurement of most of the materials and equipment needed for the project would be carried out between January 1992 and June 1994. The construction of lines and transmission systems and other civil structures related to the project would be completed over the remaining three years. To allow sufficient time to complete the sub-projects before the proposed loan is closed, all contracts financed by the Bank will be awarded before June 30, 1994 (para. 6.04 (c)). The participating SEBs and SGCs will be responsible for implementing individual transmission and distribution sub-projects and for the environmental upgrading of their power plants. The SEBs also will be responsible for implementing their institutional development programs and preparing system renovation studies, with the assistance of consultants. The OFAPs will establish in each case the task for which consultants would be required and the deadline for employing the consultants by the SEBs. The SEBs will prepare the terms of reference for each of the studies required with the assistance of PFC. PFC will implement its own technical assistance and training programs in accordance with the detailed plans agreed with the Bank. The program for improving billing and collections will be conducted under the direction of participating SEBs with the assistance of PFC and consultants. Any SEB is eligible to participate in this program. 3.18 PFC will administer the proposed Pre-investment Fund which will operate as a line of PFC financing with separate accounts. The Fund will provide financing for technical services and for studies and training in areas such as preparation and engineering of power projects, institutional development, system improvements, etc. To be eligible for financing from the Fund, the studies will have to be contracted with independent consulting firms or individual consultants. Studies conducted by government departments or government agencies or by individual consultants employed with such organizations are not eligible for Bank financing. PFC will give the Bank an opportunity to review the objectives, scope, terms of reference and proposed implementation approach of any studies financed by the Bank or being part of the OFAPs, before approving financing for such studies. PFC will establish a - 25 - roster of consultants and consulting firms in different disciplines related to the project. Interested SEBs will be able to obtain information from this roster to prepare short lists for particular assignments. The roster will serve as a data bank and the inclusion of a firm or individual consultant in the roster should not be construed as PFC approval of its qualifications. Annex 3.6 gives details of the objectives, scope of operations and responsibilities of the Fund. Environmental and Resettlement Aspects 3.19 The project does not present any major environmental issues of significance or call for major dislocation of population. It contemplates environmental actions in three aspects: (a) it includes direct investments for about US$100 million to reduce pollution levels and environmental degradation around a large number of power plants; (b) it also includes studies for system renovation comprising studies for upgrading of power stations which include an assessment of their environmental condition. These assessments would be the basis for future implementation of mitigatory actions (Annex 3.3); and (c) the transmission and distribution sub-projects under the project will be subject to environmental assessments when needed and will include the required mitigatory actions to protect the environment. Participating SEBs will be asked, as a condition of obtaining Bank financing for a particular sub- project, to meet acceptable environmental and rehabilitation standards which as a minimum satisfy Bank requirements for this type of projects. At negotiations PFC agreed to include a provision in the on-lending agreements between PFC and its clients that this requirement will be met (para.6.03(e)). 3.20 About 15 to 20 power plants are expected to participate in the program for environmental rehabilitation. In order to ensure that the environmental assessments of the power plants and that the proposed actions meet acceptable standards, at negotiations PFC agreed to give the Bank the opportunity to comment on the first power plant environmental review prepared by each participating SEB prior to PFC funding approval (paras. 3.11 and 6.03 (f)). The Bank would comment selectively on other environmental reviews. Goods, works, and technical services required to implement the actions recommended by the environmental review will be eligible for Bank financing under the project. 3.21 Before being eligible for Bank financing, all transmission lines and distribution sub-projects have to be cleared by the Department of Environment, Forests and Wildlife of the GOI. In accordance with GOI regulations, transmission lines will be routed to avoid encroachment on protected forest and wild life protected zones, or to minimize encroachment on these areas when no alternative routings are possible. In addition, as a condition of obtaining forest clearances, SEBs are required to propose and implement compensatory afforestation programs. GOI regulations require the SEBs to plant ten trees for each tree felled for line construction. Government land or degraded forests are to be used in establishing new plantations in order to minimize acquisition of private lands. Construction specifications for the project will include provisions for contractors to restore construction areas to environmentally acceptable conditions. Construction access tracks in protected areas will be allowed to revert to - 26 - forest and will be rendered unusable to avoid area encroachment. Inspection and routine maintenance of lines in protected areas would be completed on foot. No land will be acquired for the construction of lines because only right-of-way is required. The construction of distribution sub-projects will be confined to urban areas. Most of the proposed sub-projects involve improvements of existing facilities, so no new land will be required. In some instances, small urban plots may need to be acquired for expansions of distribution substations. Any population that may be dislocated by th- substation will be duly resettled and rehabilitated. 3.22 PFC, through its Environmental Unit (para. 2.21), will assist the SEBs in: (a) determining the sub-projects that require an environmental assessment; (b) preparing the assessments; and (c) implementing any actions recommended in the assessments. PFC also will moritor implementation of corrective actions. Project Costs 3.23 The estimated project cost is about US$640 million, including physical and price contirngencies and about US$84 million in taxes and duties. Direct and indirect foreign exchange costs account for US$220 million, or 34Z of the total cost. Interest during construction adds another US$72 million to the financing required. Project costs are based on December 1989 prices for the procurement of goods and works similar to the ones contemplated under the project. The prices have been updated to March 1991. Quantities were derived from detailed designs, where available, and from bidding level or feasibility level designs. The Sub-projects Under Preparation component includes sub- projects for which engineering has been completed but which still require approvals by government agencies and sub-projects for which engineering is still in process (para. 3.09). Consulting and training services for the technical assistance programs for PFC and the SEBs have been estimated at 500 consultants-month, based on the tentative scope of work agreed with PFC and estimates prepared by USAID consultants. Another 500 consultant-months have been estimated for system renovation and environmental upgrading studies. An allowance of 5% has been made for project engineering and administration. Physical contingencies of 102 have been included. Price contingencies, which represent 31Z of the base cost, are based on inflation rates of 7.8% for 1990, 10.1Z for 1991, 11.0% for 1992, 7.0Z for 1993, 6.5 for 1994, 6.0Z for 1995, 5.52 for 1996 and thereafter for local costs; and 3.9Z for foreign costs. Interest during construction was calculated assuming interest rates of 7.73% p.a. for the Bank loan and for the loans from cofinanciers and 12.5X p.a. for PFC's loans to the SEBs up to 1991-92 and 15% afterwards. A summary of project costs is presented in Table 3.1, and further details are provided in Annex 3.7. - 27 - Table 3.1: Project Cost Summary Rupees Million US$ Million Local Foreign Total Local Foreign Total A. Sub-projects Fully Cleared: 1. Transmission 2,812 1,682 4,474 99 68 167 2. Distribution 771 465 1,228 27 16 43 S. Plant Environment Upgrading 171 101 272 8 4 10 Total projects fully cleared 3,754 2,218 5,972 132 78 209 O. Projects under preparation 1. Transmission A Distribution 226 134 380 88 52 140 2. Plant Environment Upgrad;ng 847 SOO 1,347 61 20 81 Total projects under preparation 1,073 834 1,707 149 72 221 Total A+B 4,827 2,852 7,679 281 160 430 C. Technical Assistance 1. Project Support: Studies for Systems Renovation 30 73 103 2 4 6 2. Capacity Building: SEBs Institutional Development 48 SO 98 3 3 8 PFC's Institutional Development 10 10 20 1 0 1 Creation of Preinvestment Fund 76 184 269 4 10 14 TOTAL BASELINE COSTS 4,990 3,169 8,169 290 187 467 P ;sical Contingencies 482 284 787 27 18 43 Price Contingencies 2,318 697 2,916 102 39 141 TOTAL PROJECT COST 7,790 4,060 11,840 421 220 840 Interest During Construction: World Bank 546 683 1,128 19 20 40 Others 907 62 969 30 2 32 TOTAL FINANCING REQUIRED 9,242 4,696 13,937 470 242 712 Note: Totals may not add up due to rounding. Project Financing 3.24 The proposed Bank financing for this project is US$265 million, equivalent to about 37Z of the total financing requirements, or about 42Z net of duties and taxes. USAID is prepared to finance about US$14 million for the technical assistance program envisaged under the project4. PFC would finance about US$291 million, equivalent to 41Z of the total financing requirements, and the SEBs and beneficiary states would finance the remaining US$142 million, equivalent to 202 of financing requirements. The Bank would not finance IDC. The project financing plan is presented in Table 3.2. 4 A grant agreement was signed by PFC with USAID in June 1991, the effectiveness of which is conditional upon the approval by IBRD or the Asian Development Bank (ADB) of a loan to PFC (refer to para. 4.13). - 28 - Table 3.2: Project Financing Plan (US$ Million Equivalent) Local Foreign Total Z IBRD 59 206 265 37 PFC Resources 269 22 291 41 USAID - 14 14 2 SEBs 142 - 142 20 Totals 470 242 712 100 On-Lending Arrangements 3.25 The Bank loan would be made to GOI and GOI has agreed to on-lend the proceeds to PFC, with a repayment period of 15 years, including three years grace and an interest rate of not less than 11.5Z p.a. (para. 6.01). GOI will bear the foreign exchange and interest rate risks. These are the standard on-lending terms used by GOI to transfer borrowed funds to financial intermediaries. PFC would on-lend the proceeds of the Bank loan, together with its own resources, to selected SEBs, at its standard lending terms referred to in paragraph 4.14, which include an interest rate which is revised from time to time to ensure that it reflects PFC's cost of borrowing and allow PFC to earn a return on its equity that is positive in real terms. These on- lending terms reflect four important factors. First, neither PFC nor the SEBs are able to bear the foreign exchange risk at this point. Second, PFC's interest rates should remain competitive with those of other domestic financing sources. Third, the interest rate charged to the SEBs should be in line with the rates agreed under the Bank's direct operations with SEBs. Fourth, it would not be advisable to establish lending terms for the Bank's funds different from those PFC applies to its other operations. The general issue of interest rate structure in India is currently under discussion with GOI. It is expected that any policy changes resulting from these discussions also will be reflected in the power sector. Procurement 3.26 All equipment and materials financed by the Bank costing the equivalent of US$200,000 or more will be procured under ICB procedures. Bank- financed specialized equipment such &s laboratory instruments and equipment, specialized engineering office equipment, computer hardware and software, instruments for monitoring and testing of power system components, up to an aggregate cost of US$5 million, may be procured through international or local shopping procedures acceptable to the Bank. Other materials, equipment, costing US$200,000 or less per contract will be procured under Local Competitive Bidding (LCB) procedures acceptable to the Bank. The nature and size of the civil works, mostly scattered erection of equipment, does not justify International Competitive Bidding (ICB). Civil works will therefore be procured under LCB procedures acceptable to the Bank. Foreign suppliers and contractors will not be precluded from participating in LCB. - 29 - 3.27 The SEBs have their own crews for installing equipment, particularly equipment for distribution systems. Therefore, the SEBs plan to erect part of the equipment by force account, in cases involving small works scattered throughout the States for which public bidding is not practical or Justified. The Bank will not finance force account works. Local manufacturers, competing under ICB, will have a 152 preference margin or the applicable duty, whichever is lower. Local firms are expected to be competitive in equipment supply tenders. Consultants financed by the Bank will be employed in accordance with the Bank's Guidelines for Employment of Consultants. 3.28 All contracts for the supply of goods financed by the Bank with an estimated cost exceeding US$500,000 equivalent will be subjeLt to prior review by the Bank. Other contracts will be subject to ex-post review. About 70 contract packages for goods will be subject to prior Bank review, representing about 802 of total project cost. In order to simplify the Bank's review of documents, the beneficiary SEBs will be requested to agree to use standard bidding documents for all Bank-financed contracts. A summary of procurement arrangements is presented in Table 3.3 and detailed arrangements are presented in Annex 3.8. Table 3.3: Summary of Procurement Arrangements a/ (T5S$ Million) ICB LCB Other N.A. Total L,id 16.2 16.2 Civil Works 72.3 17.4 c/ 89.7 (10.0) (10.0) Materials and Equipment 424.1 47.5 5.6 477.2 (233.0) (5.0) (238.0) Training and Consulting Services 36.2 36.2 (17.0) (17.0) Engineering and Administration 20.7 20.7 Total 424.1 119.8 59.2 36.9 640.0 (233.0) (10.0) (22.0) (265.0) a/ Amounts include taxes and duties (US$84 million), and figures between brackets are the Bank-financed portion. b/ Land acquisition, administration overheads and items not subject to commercial procurement. c/ Works implemented departmentally. Disbursements 3.29 Disbursements of Bank funds will be made against: (a) 100? of foreign expenditures, 1002 ex-factory expenditure and 75? of other locally - 30 - procured equipment and materials for eligible sub-projects for transmission, distribution, system renovation, and environmental upgrading of power plants; (b) 1002 of consulting and training services for the SEBs and PFC; (c) 100% of foreign expenditures, 1002 of local ex-factory expenditures and 751 of other locally procured hardware, software and equipment for institutional development of PFC and the SEBs and pre-investment activities; and (d) 100? of expenditures for consulting and training services under the Pre-investment Fund. Disbursements are to be fully documented. To facilitate disbursements GOI will establish a special account with an authorized allocation of US$14 million. GOI agreed to have this Special Account audited by independent auditors, and to furnish to the Bank, not later than six months after the end of each fiscal year, a report of said auditors (para. 6.02 (a)). Annex 3.9 shows the schedule of estimated disbursements for Bank funds. The schedule follows the one used for typical transmission and distribution projects financed by the Bank. The closing date for the loan would be December 31, 1997. Project Monitoring 3.30 PFC is to furnish the Bank with progress reports on the status of physical works, consulting services, costs, disbursements, and administrative arrangements for the project within 45 days of the end of each quarter. The reports should contain special sections reporting on: (a) the compliance with agreements by all PFC borrowers and on the compliance with OFAPs by the SEBs receiving Bank financing, and (b) on the progress being achieved in the implementation of the environmental components of the project with particular reference to the activities of the PFC Environmental Unit. PFC also is to report on the progress made in implementing its own institutional development program and on any exceptions made to the application of its Operational Policy Statement (para. 2.09). The first progress report should be furnished to the Bank no later than May 15, 1992 and should cover initial project activities up to the quarter ending March 31, 1992. In addition, PFC will furnish the Bank with annual reports on its financial results and on its administrative and managerial situation. Project Risks 3.31 The project does not pose extraordinary technical risks because the type of physical works involved is routinely implemented by utilities in India. There are, however, risks related to the institutional, managerial, and financial aspects of the project. On the institutional side, there is a risk that the participating SEBs will not meet the expected improvements set out in the OFAPs or that thp pace of reform will be slower than planned. This risk will be minimized by establishing realistic actions and targets in the OFAPs, and by providing financial and technical resources to the SEBs to facilitate implementation of the OFAPs. On the managerial side, there is a risk of protracted decision making by the SEBs, particularly in relation to procurement. This, combined with the extensive, detailed reviews of procurement actions typically carried out by GOI agencies for Bank-financed projects, may slow the pace of implementation. Similarly, project delays may occur because of the long time it takes for the implementing agencies to obtain GOI authorizations for payments in foreign currency. To minimize this risk GOI recently streamlined the procedures to be followed to expedite and - 31 - simplify clearances of procurement actions and releases of foreign exchange for Bank-financed procurement. The procedures are expected to ensure that these clearances and permits are granted within a reasonable amount of time. Delays also may occur in obtaining administrative clearances for sub-projects under processing or preparation (para. 3.09). These delays may result in the SEBs not being able to utilize the entire loan before its closing date. To keep this risk at an acceptably low level, the size of the loan has been determined after conservatively assuming that only 50% of the sub-projects under processing would be cleared in time to become eligible for Bank financing. 3.32 There are two risks related to PFC's performance. The first is that PTC could face collection problems because of the poor financial performance of its customers. This risk would be kept at an acceptably low level if PFC requires, as a condition of lending to any SEB or SGC, that it establish a set of suitable guarantees, as described in para. 4.16. The second risk is that PFC might fail to become an effective promoter of institutional improvements at the SEB/SGC level. This could occur if PFC does not have the institutional resolve -- and GOI's support -- to attach adequate conditionality to its lending operations. This also may occur if political pressures prevent PFC from enforcing said conditionality or its OPS. To manage this eventuality, agreements have been reached to ensure that PFC's policies and procedures are consistent with its developmental objectives (paras. 4.16, 4.20 and 4.21). IV. FINANCE Background 4.01 During the short period it has been in operations, and in the context of a strategy to establish its presence in the power sector in India, PFC has managed to implement a relatively large lending program. In the future it plans to continue concentrating its efforts in trying to promote improvements in the operational efficiency and financial performance of state owned power utilities. Most of the SEBs are financially weak and, accordingly, constitute a very risky market. Recognizing this situation, PFC's Operational Policy Statement (OPS) was carefully framed to allow PFC to discharge the responsibility assigned to it, while at the same time preserving its financial integrity. In view of the uncertainties about the size of PFC's lending operations, as well as the blend of financial instruments it will be allowed to use and other variables, the assessment of PFC's future financial performance was made assuming a base case and undertaking a sensitivity analysis of PFC's performance to changes in those variables. The results show that PFC's performance under the different scenarios is adequate, provided it can enforce its collections policy. PFC's Market 4.02 Although PFC is allowed to lend to any power utility in India, including private utilities, in the medium term it will concentrate most of its efforts on the SEBs and SGCs, which are recognized as the weakest segment of the power sector. In the past, despite the fact that investment targets - 32 - are normally set lower than what is required to eliminate the gap between demand and supply of electricity, funds made available to state utilities have consistently fallen short of the requirements of their expansion programs. This shortfall in funding has resulted in delays in commissioning projects and, consequently, in cost ovfrruns. The problem of inadequate funding has several causes. First, the methodology followed in preparing the Five-year Plan underestimates actual funding requirements because Plan estimates: (a) do not take into consideration price escalation during the period of implementation; and (b) include optimistic assumptions of SEBs' expected contribution to investment from internally generated funds, since no provision is made for working capital requirements. Second, Plan funds originally intended for the power sector often are diverted by the states to other sectors. 4.03 As a group, the SEBs have not performed well financially. During the period 1986-90 the SEBs made no contribution to the financing of their investment and had a negative internal cash generation conservatively estimated at about Rs 61 billion (about US$4.1 billion). The utilities earned an average rate of return on historically valued net fixed assets, after interest, of minus 12X, which allowed them to meet only one-third of their annual debt service requirements. Annex 4.1 presents a summary of this performance for the years 1986-90. 4.04 Since the SEBs have no ability to contribute to the financing of their investment programs, following the states' traditional practice of financing their SEBs solely through debt, state-owned utilities had to borrow heavily to cover the cash deficit -sntioned above, as well as to finance their if.vestment. About two-thirds of their borrowing come from the states. The proportionate share of the states in financing the SEBs has been gradually dropping from 70Z in 197'-75 to 65Z at the end of 1986-87. This trend is expected to continue. The state utilit:es are allowed to issue 20-year, 11.5t bonds which are guaranteed by their respective state governments. These bonds are purchased by the financial institutions for the purposes of their statutory reserve requirements, so the market is quite limited. 4.05 In addition to borrowing from the State, SEBs/SGCs obtain loans from the Life Insurance Corporation (LIC), the Rural Electrification Corporation (REC) and the long-term financial intermediaries like the Industrial Credit and Investment Corporation of India (ICICI) and the Industrial Development Bank of India (IDBI). LIC loans carry an interest rate of 13% p.a. and are guaranteed through the mortgage of assets. REC loans carry an interest rate of 7.52 to 13% p.a. and ICICI and IDBI are lending at 14? p.a. All of these loans mature in seven to ten years. SEBs' Future Funding Requirements 4.06 Power investment estimates for the Eighth Five-Year Plan (now 1993-97) are still under discussion. A figure of Rs 500 billion is being indicated. CEA estimates that 60? of the power sector investment during the Eighth Plan could go to the State sector and the rest to the Center. The estimated amount of Rs 300 billion for the State Sector would represent an increase of 30? over the Rs 230 billion under the Seventh Plan. - 33 - 4.07 It appears that GOI expects PFC funding of the states's requirements in the power sector to gradually grow to be able to meet about 25X to 302 by the end of the Eighth Plan. There is consensus within GOI on the need for PFC to reach a volume of operations large enough to provide it with the leverage required to effectively promote improvements in the states' power utilities. On the basis of the figures discussed in para. 4.06, this volume of lending operations translates into between Rs 75 billion and Rs 90 billion, in addition to the budget funds allocated to the states through the Gadgil formula. PFC's Sources of Financing 4.08 PFC has three major sources of financing available to it: (a) domestic market borrowings; (b) equity contributions; and (c) external borrowing. Each of them is discussed briefly below. 4.09 Domestic market borrowings. PFC is expected to rely heavily on borrowings from the domestic market. It is important then to have an idea of the size of the bond market for Government owned enterprises in India. Table 4.1 presents a breakdown of public enterprise borrowings from 1986-87 to 1989- 90. Table 4.1: Market Borrowings by Public Enterprises, 1987-90 (Rs billion) 1986-87 1987-88 1988-89 1989-90 Railways 5.6 4.0 6.0 10.0 NTPC 4.3 4.4 6.5 0.0 NHPC 1.5 2.8 0.0 3.7 Nuclear Power - 1.3 2.0 1.8 PFC - 1.0 6.2 1.2 Telecom 3.8 3.5 3.0 5.0 Neyveli Lignite Corp. 0.6 .9 3.2 4.0 India Petrochemicals 0.9 .6 .2 - Others 3.1 2.9 4.3 13.3 Total 19.8 21.4 31.4 39.0 Source: PFC 4.10 GOI maintains close control over public enterprise borrowings, establishing the allocation for each specific enterprise, the type of instrument to be used, and the timing of the issue. Currently three types of domestic bonds are available to the public sector: (a) 9s tax-free, 10-year bonds; (b) 132 taxable, 7-year bonds; and (c) 11.5? taxable, government guaranteed, 20-year bonds; - 34 - 4.11 Commercial banks and other financial institutions buy most of the issues of 11.5Z bonds to satisfy statutory requirements, and they tend to hold them to maturity. They also buy the issues of 95 bonds, which in turn, after three months, are offered to the general public over the counter. By the end of 1990-91, PFC had successfully floated four issues of ten-year, 9? bonds, two for Rs 1 billion each and two for Rs 6 billion. It has also floated three issues of 20-year, 11.5Z bonds for a total of Rs 600 million. Due to the adverse budgetary impact of the tax free bonds, it is expected that in the future PFC will mostly rely on taxable bonds for its domestic financing. 4.12 Equity Contributions. PFC has an authorized capital of Rs 10 billion, of which Rs 8.5 billion was paid at the end of FY91. Increases in the authorized capital are normally agreed with GOI for the period of the Five-year Plan and payments are made annually. The current level of capitalization is becoming a constraint that may limit PFC's volume of operations. Under the Eighth Plan PFC's capital is expected to be increased. 4.13 External Borrowing. PFC is expected to play a key role in channeling a substantial portion of the loans from multilateral institutions and bilateral sources to the power sector. In FY90 PFC received a FF 304 million (US$60 million) credit from France to finance a Diesel Plant in Karnataka and in FY91 a US$110 million commercial co-financing loan from ADB under its Complementary Financing Scheme, similar to the Bank's B-Loan scheme, was channeled through PFC. In addition, a grant was received from ODA to assist in the development of appraisal of urban distribution systems. Several other operations are in different stages of preparation, including: (a) one from ADB for US$300 million with a scope similar to the proposed project and scheduled for approval in February, 1992; (b) a DM 66 million assistance from KFW; (c) a pound 50 million grant from the United Kingdom for an Energy Efficiency Project; and (d) a grant, NOK 1 million, from Norway for institutional development. In order to supplement the foreign exchange funds mobilised from multilateral and bilateral sources, in a few years, the Corporation may also attempt to access the international capital market. The timing and scope of that attempt will depend primarily on the speed with which India will restore its creditworthiness. The Bank may then be able to play a catalytic role with respect to the Corporation's borrowings from the foreign private sources. PFC's Lending Terms 4.14 PFC's current lending terms are shown in Table 4.2. Although PFC's current lending rate is 12.52, the OPS establishes that the lending rate is adjustable to reflect the cost of funds to the Corporation and to ensure that PFC earns a return on its equity which is positive in real terms (para. 4.16 (d)). PFC is currently reviewing its lending rate and it is expected that it will be increased to about 162 to 17Z p.a. Loan maturities offered by PFC to its clients are prudently matched with the maturities of PFC's own borrowings. Although the present repayment terms may be relatively short given the gestation period of some SEB projects, in the long-run, the average maturity of PFC's liabilities will likely increase as PFC is able to gain access to longer-term borrowings. - 35 - Table 4.2: PFC's Lending Terms Total Grace Interest Category Maturity Period Rate p.a. Renovation & Modernization 7 years 1 year 12.5 Capacitors 3 years none 12.5 Transmission & Distribution 7 years 2 years 12.5 Generation 7 years 2 years 12.5 PFC's Historical Performance 4.15 Although PFC's lending operations began in early 1988, in fact, most of 1987-88 operations took place in the last few weeks of the fiscal year. In order to establish its presence as a source of financing for the power sector, during its first years of operations PFC made loans primarily to facilitate the completion of projects underway. In this process, although the dialogue on ways to improve the efficiency of the SEBs was initiated, no conditionality was attached to the loans. As shown in Annex 2.4, up to March 31, 1991, PFC had approved loans amounting to Rs 33.6 billion. This rather substantial volume of operations for a new organization was financed through GOI's equity contributions and bond issues, mostly of the 9Z, 10-year category. PFC has made a profit every year since operations started, although the return on its net worth was modest. At the end of 1990-91 PFC had a debt:equity ratio of 1.7:1. The debt service coverage has been adequate. Annex 4.2 presents financial statements for PFC for 1987-88 through 1990-91 as well as a projection of its operations. Annex 4.3 gives the assumptions followed in the financial projections. Table 4.3 provides some highlights from these statements. Table 4.3 Highlights of PFC's Historical Performance 1987-88/1990-91 (Rs Million) 1987-88 1988-89 1989-90 1990-91 Equity contribution 1,000 2,000 3,000 2,201 Bonds issued 1,000 6,200 1,200 6,200 Loan disbursement 1,011 4,9;8 6,976 8,968 Operating Income 57 601 1,156 2,306 Net Income 4 148 304 810 Debt service coverage 2.2 .4 1.5 2.3 Return on net worth Z 0.3 4.3 4.5 8.3 Debt/equity ratio 0.8 2.2 1.4 1.7 PFC's Financial Policies 4.16 PFC has incorporated in its OPS (Annex 2.2) a set of parameters designed to ensure a minimum level of financial and operating performance. The following are some of the elements in the OPS which are expected to enhance PFC's financial performance: (a) General Operational Parameters: PFC will endeavor to: (i) operate as a commercial entity; (ii) maintain a healthy portfolio; and - 36 - (iii) build a strong financial base to enable it to borrow on attractive terms. (b) Solvency: to preserve its capital structure, PFC has set a maximum debt:equity ratio of 4sl. As PFC becomes better established, this ratio will be revised. (c) Liquidity: (i) PFC's operations will be managed so as to maintain a debt service coverage ratio not lower than 1.2; and (ii) PFC will ensure the availability of liquid assets equal to not less than the equivalent of the anticipated disbursements for the following three months. (d) Profitability: PFC's lending rates will reflect its borrowing and operational costs, plus a margin to ensure its financial viability, earning an adequate return on its capital (positive in real terms). (e) Foreign Exchange Risk: PFC will not bear the interest rate or foreign exchange risks of its operations. (f) Term Transformation: PFC will determine the average repayment periods for its loans so as to ensure that the average maturity of its assets does not exceed that of its liabilities. (g) Repayment Guarantees and Exposure Limits: In light of the weak financial performance of PFC's clients, as condition of effectiveness of each one of PFC's loans, either a State guarantee or a commercial bank guarantee will be obtained. As indicated below, these guarantees could be enhanced by the SEBs establishing an escrow account in favor of PFC.6 Furthermore, since it is not healthy for PFC to concentrate an excessive portion of its loans in any single client, PFC will not lend or grant any guarantee to any borrower if as a result of such loan or guarantee the combined amount of loans and guarantees outstanding with that borrower exceeds certain limits. Table 4.4 presents a matrix that combines two parameters, creditworthiness of the client and the type of guarantees offered, to determine the credit risk weights to be used in calculating the maximum levels of exposure per client as a percentage of PFC's net worth. These credit risk weights follow the concept of credit conversion factors adopted by the Basle Committee on Banking Regulations, also known as the "Basle Concordat". Table 4.4 includes a sliding scale that in four years would bring PFC's exposure limits tc levels consistent with the standards normally applied to development finance institutions. This sliding scale has been designed to allow PFC enough time to develop an adequate equity base. For the purposes of establishing the credit rating o a client, in the calculation of the debt The Escrow Account system provides PFC a first claim on the cash collections of the utilities. In the event the utility fails to service its debt, those funds are transferred to PFC. - 37 - service coverage the following parameters will be followed: (i) borrowers would be allowed to exclude the servicing of the loans from its State Government, provided the Governmenz commits in writing not to ask the borrower for payment of any interest and principal on its loans while any6 loan or guarantee received from P'C remains outstanding and due; and (ii) rural electrification subsidies not received by the SEBs should be excluded from revenues. In analyzing the credit worthiness of its clients, PFC will give due regard to the client's debt servicing record with other lenders. Table 4.4: Matrix of Risk Exposure and Guarantees On-Balance Sheet Assets and Off-Balance Sheet Items Credit Guarantee Risk Level Rating (a) Offered (b) Weight (c) 1 A STG/BG .5 2 STG+EA .3 3 B STG/BG 1.0 4 STG+EA .5 5 C STG/BG 2.0 6 STG+EA 1.0 7 Backed by GOI 0.0 Definitions: (a) Credit Rating A: Debt Service Coverage in excess of 1.3 Credit Rating B: Debt Service Coverage between 1.0 and 1.3 Credit Rating C: Debt Service Coverage below 1.0. (b) STG: State Government Guarantee BG: Bank Guarantee EA: Escrow Account (c) Risk Weight is the factor by which the loans outstanding that qualify under each level should be multiplied to calculate the exposure.7 6 To this effect, PFC will request each State to confirm the priority claim given by the Electricity Act to PFC's loans over loans granted by the State. 7 For example, a Rs 100 loan ranked as Level 1 will be computed as equivalent to Rs 50 (Rs OO x 0.5) for calculating the risk exposure. - 38 - Maximum Level of Exposure per client, as follows: 1991-92: 352 of PFC's Net Worth 1992-93: 302 of PFC's Net Worth 1993-94: 251 of PFC's Net Worth 1994-95 and thereafter: 20% of PFC's Net Worth (subject to review before the end of 1993-94 to determine its adequacy). (h) Non-rescheduling of Loans: Because of the detrimental impact that re-scheduling could have on the financial discipline that PFC is trying to promote in the sector, PFC has stated that it will not reschedule its loans. It considers that rescheduling could render ineffective its loan guarantee system and ultimately lead to serious financial difficulties. However, under special circumstances, if the Corporation considers it financially prudent, PFC may provide financial restructuring packages to its borrowers, supported by appropriate conditionality. (i) Adjustability of PFC's Lending Rate: Under its current policy, when PFC's cost of borrowing increases, only the interest on the undisbursed portion of loans may be adjusted. This policy should not present difficulties as long as PFC borrows only at fixed rates, as is currently the case. However, as PFC begins borrowing at variable rates, it will include provisions in its lending documents to allow for adjustability of its lending rate on both the disbursed and undisbursed portions of its loans. PFC has retained a consultant to determine the methodology for implementing this policy. A report is expected by December 31, 1991 and a copy of the report will be furnished to the Bank for comments. PrC's Future Financial Performance 4.17 PFC's ability to cover a substantial portion of the outstanding requirements of the state power sector, as discussed in para. 4.07, will depend on several variables, not all of them under PFC's control. On the one hand, PFC's financing capacity will depend on the volume of funds made available to it by GOI, both in the form of equity contributions and by granting PFC access to the domestic market and to external lenders. On the other hand, even though the financial needs of the sector are evident, there is some degree of uncertainty in regard to the attractiveness of PFC's financing package, including the introduction, for the first time in India, of conditionality attached to loans as well as the capability of SEBs and SGCs to meet PFC's eligibility criteria (para. 2.16) and PFC's risk exposure limits. 4.18 Under these circumstances, PFC's future financial performance was evaluated using different assumptions of volume of operations, borrowing and lending maturities, cost of financing, lending terms, and collection performance. The results of this analysis confirm PFC's financial viability under the conditions evaluated, and its ability to meet the financial targets set in the OPS, provided it is able to collect from its borrowers on time. This underscores the need for PFC to adhere to its OPS and particularly to a - 39 - well designed and executed system of guarantees, as discussed above. A summary of some of the alternatives tested is presented in Annex 4.4. 4.19 The base case, which assumes a level of operations of Rs 75.3 billion, was analyzed to determine PFC's performance under existing fiscal constraints. To meet the financing requirements of the base case, during 1991-95 PPC will need to float bonds for Rs 39.6 billion, or 49Z of its total funding requirements. It is assumed that from 1991-92 onwards PFC will rely mostly on 13Z-7 year bonds and that accordingly, following the provision of its OPS, it will adjust its lending rate to 15Z. This volume of bonds seems realistic as the amounts floated each year are assumed to gradually increase from the level attained historically. However, as mentioned above, it is GOT who decides on the amount, type of bond and the timing of issue on a case-by- case basis. This practice makes it almost impossible for PFC to do proper financial planning and adds a degree of uncertainty and risk to PFC's operations. To try to reduce this risk, during negotiations GOI agreed to provide to PFC, every year before March 31, a firm commitment on the amount PFC will be authorized to raise in the domestic bond market in the following financial year, the type of bonds and approximate dates of these issues (para. 6.02 (b)). Under the conditions assumed in the base case, PFC's finances remain satisfactory, as shown in Annex 4.2 and summarized in Table 4.5, with a debt service coverage in excess of 2.3 and a return on net worth approaching 14Z at the end of the five-year period. Table 4.5 Highlights of PFC's Future Performance, 1991-1995 (a) Financing of PFC's Operations 1991-1995 Sources of Funds: (Rs Million) z Equity contribution 10,201 13 Bonds issued 39,650 49 IBRD 3,944 5 Other Foreign borrowing 2,529 3 Internal Funds Gen. 24,351 30 Total Sources 80,675 100 ApPlications: Loans Disbursed 75,338 Increase in liquidity 5,337 Total Funds 80,675 (b) Performance Indicators FY91 FY92 FY93 FY94 FY95 Debt Service Coverage 2.3 2.6 2.5 2.7 3.0 Return on Net Worth 8.3 10.4 9.5 12.7 14.3 Debt/Equity Ratio 1.7 1.8 1.9 1.9 1.9 - 40 - Conditionality 4.20 To ensure that PFC operates according to the standards agreed under the OPS, during negotiations PFC agreed to implement the OPS and not to modify it in a material manner without prior concurrence from the Bank (para. 6.03 (a)). In order to reinforce this covenant, at negotiatins PFC was informed that failure by PFC to adhere to any of the following key elements of the OPS will be construed by the Bank as a serious matter which would affect the institutional capacity and financial viability of PFC: (a) the enforcement of suitable repayment guarantees; (b) observance of the risk exposure limits; (c) enforcement of the non-rescheduling clause; (d) observance of the lending criteria; and (e) adjustment of PFC's lending rate to reflect its borrowing cost. 4.21 7o monitor PFC's performance, during negotiations PPC agreed to present t, the Bank for comments every year, the following reports: (a) by March 31 evidence of GOI authorization to PFC to issue bonds in the following year; C( by January 31, estimated financial performance for the current and next y .rs, comparing them to the parameters set in the OPS; and (c) by June 30, projected financial statements (income statement, sources and applications of funds and balance sheets) for the next following five years, showing how the OPS parameters will be attained (para. 6.04 (d)). V. ECONOMIC ANALYSIS AND PROJECT JUSTIFICATION 5.01 The primary justification for the proposed project is the increased electricity demand to be served by the SEBs through the additional transmission and distribution capacities to be installed. Aside from facilitating the evacuation of power from existing and expanded generating plants, the project will result in reduction of line losses, improved system voltages, and enhanced reliability of the SEBs' service. To assess the economic viability of the various transmission, urban distribution and environmental upgrading schemes proposed by the selected SEBs, the schemes were appraised by PFC as to whether: a) they are part of the least cost power system expansion progrvn at the regional and state levels; and b) they can individually yield adequate net economic benefits. 5.02 The scope of economic analyses involved in the appraisal of the various SEB projects is illustrated in Annex 5.1 in which the economic evaluation of the transmission and distribution projects proposed by the Punjab State Electricity Board is presented in detail. - 41 - Least Cost Analysis 5.03 The SEBs have carried out internal staff studies to arrive at the least cost options of attaining the operational objectives targeted by their proposed projects. These analyses were in terms of detailed load flow studies which identified the weak segments of the network including existing and potential circuit and transformer overloadings. Alternatives satisfying system reliability and voltage design criteria have been examined at various stages of planning to arrive at the best option based on technical and cost considerations. 5.04 PFC has reviewed the alternative options considered by the SEBs. In a number of cases, there were no reasonable alternatives to the proposed schemes, for example, the stringing of a second circuit on transmission towers already erected and lines traversing the shortest direct route between designated loading points. Moreover, the SEBs have generally standardized transmission systems at 220 kV and conductor ratings at 100 MVA per circuit, such that consideration of alternative voltages have largely been limited to cases of upgrading from 132 kV to 220 kV. For sub-transmission systems, the voltages and type of substations depend on various factors, such as load density and network layout. Transformer size and ratings have also been standardized; the most common voltage ratings of the secondary sub- transmission systems are 132/110/66/33 kV, and for primary distribution system, 11, 22 or 6.6 kV. 5.05 The 220 kV works itself have been cleared by CEA in accordance with its transmission planning criteria. These criteria require transmission systems to be planned based on regional self-sufficiency, capable of transmitting the respective state's allocation from the Central sector, and able to withstand specified levels of outages without having to resort to load shedding or rescheduling of plant generation, i.e. outages of two circuits of 220 kV system, or of one circuit of 400 kV or higher voltage system, or of one pole of HVDC bipole, or of an EHV transformer. 5.06 In the case of distribution schemes, whenever possible, low cost alternatives have been considered by the SEBs; for example, outdoor substations over indoor, overhead lines over underground cables, etc. Since the schemes cover mainly critical works for immediate relief to the systems and are to meet the load growth up to the next five years only, consideration of alternative voltages was limited. The procedure adopted by the SEBs has been to select the reinforcement and renovation works in the distribution system which satisfy design criteria mutually agreed with PFC. These criteria cover statutory requirements of supply (e.g., voltage regulation), reliability norms, flexibility for future expansion and other technical considerations. 5.07 With respect to environmental upgrading activities, PFC reviewed and confirmed that the schemes represent the least cost mode of mitigating the pollution effects of power operation. Program Analysis 5.08 Inasmuch as the proposed 220 kV transmission schemes are planned in conjunction with the regional power expansion programs, the economic - 42 - viability of these programs have been evaluated for regions where the selected SEB operations are located. For this purpose, the investments time-slice for the period 1990-2000 has been analyzed for the Northern Region grid in connection with the projects proposed by Punjab SEB, for the Western Region for projects of Gujarat SEB and Madhya Pradesh SEB, for the Southern Region for projects of Andhra Pradesh, and for other regions where proposed SEB projects may be considered for funding by PFC. 5.09 In addition to reviewing the regional system expansion plans, the selected state's respective power investment program were also evaluated to ensure that the proposed distribution schemes are integrated into the SEB's over-all system plan. The economic returns from said plans were calculated for the investment time-slice 1990-1995 corresponding to the construction period of the distribution systems. Project Analysis 5.10 To assess whether each of the many sub-project proposals yield sufficient economic returns and to determine which ones should receive priority funding, the proposals were further analyzed as to their project net benefits and economic returns, and ranked accordingly. For urban distribution improvement proposals, each scheme was appraised as a discrete and independent project. On the other hand, in the case of transmission projects, each of the proposed schemes were reviewed as to its operational objectives in the context of the SEB's grid operations and agreed planning criteria. Schemes affecting the same sub-systems were analyzed together and the load flows for each sub- system affected under varying supply-demand conditions with and without the proposed facilities were assessed to arrive at the value of benefits. To the extent that lack of detailed load flow calculations from the SEBs prevented such sub-system analysis, an approximation of the relative contribution to the over-all grid of specific line components was estimated and an investment yield corresponding to each line was derived. These estimates were based on the projected load flow and loss reduction profile of each circuit as indicated by load flow analyses of the grid for the scheduled year of line commissionings. Costs 5.11 In evaluating the economic costs of the system expansion programs for the regions and states, the capital investments for generation, transmission and distribution facilities were estimated for the period 1990- 2000 and 1990-1995, respectively. The operating and maintenance expense profiles were developed based on the forecast system operation as estimated under CEA's or the SEB's generation planning. All financial costs were converted to economic costs applying the standard conversion factor (SCF) of 0.8 on local costs and by removing effects of taxes, duties and subsidies. In view of its relatively poor quality and low heating value, local coal supply is considered non-tradeable and its economic price is estimated based on cost at pit-head plus transport expenses to thermal plants involved. The economic price of fuel oil used by thermal stations for plant firing is based on the border price plus local handling and delivery costs and is estimated at Rs 2.5 to 2.7 per liter. - 43 - 5.12 Similarly, in analyzing project costs, the capital and operating costs associated with proposed transmission and distribution schemes were considered. In addition, the average incremental cost (AIC) of generation and distribution were included in the evaluation of transmission schemes, and the AIC of generation and transmission were imputed in the assessment of distribution projects, so as to arrive at the full economic cost of electricity supply to final end-users. Benefits 5.13 Given the current situation in India of excess power demand over supply, it is expected that the economic benefits to be derived frou. the system expansion programs at the regional and state levels would consist largely of increases in electricity consumption. Additional benefits representing operational cost savings due to displacement of less efficient thermal generation, reduced system losses, reduced frequency and length of system outages are also projected. 5.14 Similarly, benefits from the specific transmission and distribution improvements proposed by the SEBs are in the form of increased power delivery primarily due to additional line and transformer capacity for evacuating power from existing and forthcoming generating stations. Increased service availability or operational cost savings due to reduced energy and transformation losses are also expected. In addition, the projects will lead to enhanced system reliability due to improvements in voltage levels, metering works, maintenance and fault attendance systems. 5.15 The additional electricity consumption afforded by the regional and state power expansion programs and the proposed transmission and distribution schemes are valued initially at the prevailing tariff 'evels. In general, the expected financial revenues from the programs and the projects are expected to be inadequate in view of the current policy of many SEBs of setting tariffs below the cost of supply, including granting of explicit subsidy to specific consumer groups. In this connection, it is envisioned that with the implementation of the OFAPs which have been mutually agreed to between PFC and the SEBs to help mitigate financial shortfalls in the SEBs' operations, the financial returns on the proposed investments would correspondingly improve. 5.16 Given the scarcity of power supply, however, the value of electricity service in India is deemed to be considerably higher than the current rates at which it is sold. Accordingly, the consumers' willingness to pay has been estimated based on the cost of electricity from sources other than the grid; i.e. from autogeneration from diesel generators for industries and commercial consumers, and from diesel pumps for irrigation requirements of agricultural users. The cost of these alternative sources (estimated at Rs 2.75 per kWh in the residential/commercial sector, Rs 2.07 per kWh in industry, and Rs 3.41 per kWh in agriculture) are considered to be the upper limit of the consumers' willingness to pay for their particular levels of power use from the public supply system, while prevailing tariffs serve as the lower limit. The consumer surplus attributable to incremental consumption is estimated to be equivalent to half of the difference between these limits as the higher cost of autogeneration is seen to reflect the value of energy to - 44 - consumers during the peak and intermediate load periods when there is load shedding, but not necessarily during the rest of the day when energy from the grid is normally available. Results of Program and Project Economic Analyses 5.17 Economic evaluations of project proposals forwarded by the SEBs of Punjab, Andhra Pradesh, Madhya Pradesh and Gujarat have been undertaken by PFC. The transmission schemes have been cleared for implementation by CEA and the distribution schemes have been duly reviewed by PFC as conforming to the agreed technical design criteria. Those that yield sufficient economic returns of at least 12X would be considered for funding under the proposed project. 5.18 The economic returns estimated for various projects submitted by Punjab SEB and Andhra Pradesh SEB as well as for some regional and state programs are summarized in Table 5.1. Relatively high economic rates of return were derived for the transmission and distribution schemes reflecting the critical and urgent need for the proposed activities. A number of the proposed transmission expansion will bring immediate and much-needed relief to the present networks and will result in more efficient dispersal of power from existing generating plants as well as from those already nearing completion. On the other hand, the distribution renovation schemes will help meet load growth in the immediate future as well as effect much needed improvement in existing services. Hence, compared to the relatively low incremental costs of removing system bottlenecks through the project facilities, the benefits to be derived from the enhanced service and higher utilization of system supply capacities are significant. 5.19 Sensitivity analyses based on adverse variations in project benefits, costs and implementation schedule indicate that investment returns remain strong. Moreover, tests using higher AIC values for other investment components associated with power delivery indicate that project returns continue to be well in excess of 122. Table 5.1: Economic Return of Various SEB Projects Base Case a/ Using High AIC Values b/ NPV 121 EIRR NPV 12% EIRE (Rs. MlliI) (X) (Rs. MiiI) (M) Sub-Projects PUNJAB SE a. Transmission Sub-Projects 1. RTP-Ooblndgarh 910 119% 322 S3X 2. RTP-Jsllandar II 881 112% 462 6sx 8. Bhakra-Mahilpur 720 90% 350 64% 4. ONDTP-Mukatesr 420 116% 148 sex S. CNDtP-Mansa-Sunam 365 69% 81 23% 8. RTP-Rajpura-Patiale 343 107% 128 64% 7. Mogo-Mukatsar 273 128X 92 6SX 8. Mukatsar-Jallaobad 150 34x 8 13% b. Distribution Sub-Projects 1. Khanna 309 80X 82 86% 2. Patiala 227 72% 47 29% 8. Jallandhar 129 34X 17 1% 4. Shatinds 73 38% 8 16% S. Phaguara 46 65% 16 29X - 45 - 6. Hoshierpur a8 843 6 18% 1. Faeldkot City 14 21X a 14% c. State Program 12,634 263 A PRADESH Sa a. TransmIssion Sub-Projects 1. Cuddapsh-Renigunta 723 106% 237 693 2. Ramagundam-Nixemabad 682 138% 220 82% S. Rtmagundam-Warangal 827 923 98 41% 4. Sullurpet-Renlgunta 800 483 12? 28% Chitoor b. Distribution Sub-Projects 1. RaJahmundry 381 140% 220 87% 2. Kakinada 320 115X 208 78% 8. Nellore 284 106% 190 7ex 4. Kurnool 259 124X 158 793 S. Warangal 200 98X 9B 64% 6. Nizamabed 190 1303 106 703 7. Chitoor 178 903 98 663 c. State Program 2e,667 32X Northern Region Expansion Projram 51,408 1S% Western Reglon Expansion Program 187,345 26% pj Based on AIC estimates developed at 123 discount rate. To the extent that the State's expansion program yields a return higher than 12X, addittonal return attributable to other investment components Ias partly been credited to the project. k/ Based on higher AIC estimates derived by applying a discount rate as high as the rate of return of the State expansien program. VI. AGREEMENTS AND RECOMMENDATION Agreements Reached 6.01 The conclusion of a Subsidiary Loan Agreement between GOI and PFC, satisfactory to the Bank, will be a condition of effectiveness of the proposed loan (para. 3.25). 6.02 GOI agreed: (a) to submit to the Bank, not later than six months after the end of each fiscal year, an auditor's report on the Special Account (para. 3.29); and (b) to communicate to the PFC, not later than March 31 each year, a firm commitment on the amount PFC is authorized to raise in the domestic bond market in the following year, including the type of bonds 'lo be issued and the estimated dates of such issues (para. 4.19). - 46 - 6.03 PFC agreed: (a) to implement the Operational Po'icy Statement (OPS) (Annex 2.2) and consult with the Bank before any material modification is introduced to it (paras. Z.09 and 4.20); (b) that PFC's funds will not be pre-allocated but will be lent following a pre-agreed criteria satisfactory to the Bank (para. 2.11); (c) that to be eligible for Bank financing of environmental upgrading of plants, candidate SEBs/SGCs will prepare an environmental assessment of the stations and agree to implement actions to meet acceptable environmental standards (para. 3.11); (d) to submit to the Bank for approval the items intended to be financed with the proceeds of the proposed loan, under each component of the project (para. 3.14); (e) to include in its loan agreements a provision to ensure that its clients meet environmental and rehabilitation standards satisfactory to the Bank (para. 3.19); and (f) to give the Bank the opportunity to comment on the first power plant environmental review of each participating SEB (para. 3.20); 6.04 PFC agreed on the following milestones for implementing the project: (a) submit to the Bank, no later than two months after the end of each fiscal year, unaudited financial statements, and no later than six months after the end of the fiscal year, copies of said financial statements certified by an independent auditor acceptable to the Bank (para. 2.20); (b) that only sub-projects having complete deL, led engineering and all clearances by December 31, 1992 will be eligible for Bank financing (para. 3.10); (c) to have all contracts financed under the loan awarded by June 30, 1994 (para. 3.17); and (d) submit each year: (i) before January 31, a report including PFC's current financial performance compared to the parameters set in its OPS; (ii) before June 30, five-year financial projections showing how the OPS parameters will be attained; and - 47 - (iii) before March 31, evidence of GOI's authorization to PFC to issue domestic bonds during the following year, including the amount, the type of bonds and approximate timing of the issues (para. 4.21). Recommendation 6.05 On the basis of the above agreements, the proposed project constitutes a suitable basis for a Bank loan of US$265 million equivalent to India for '0 years, including five years grace, at the Bank's standard variable interest rate. - 48 - Annex 1.1 --. ....... Page 1 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT .............................................. ALL INDIA: ELECTRICITY SUIPPLY AND DEMAND ....... ................................................ Actual a/ Estimated b/ Annual Increase (X) ....... ............ .......................... ...................................... . FY82 FY91 FY92 FY93 FY94 FY95 FY91-95 .......................... ------- ............. ................................................... Instatled Capacity - MU 32347 66066 69805 76355 81755 86597 7.0 Peak Availability - MW 20121 39069 41101 44306 48157 50841 6.8 Peak Load - MU 20121 50184 54481 58920 63611 68435 8.1 Deficit - KW 0 11115 13380 14614 15454 17594 12.2 Deficit (X of Peak Load) 22.1 24.6 24.8 24.3 25.7 Energy AvailabiLity - GUh 113827 258690 271270 288726 314870 337295 6.9 Energy Requirement c/ - GWh 113827 283111 307257 332343 358746 385951 8.1 Deficit d/ - GWh 0 24421 35987 43617 43876 48656 18.8 Deficit (X of Requirement) 8.6 11.7 13.1 12.2 12.6 ................................. ...................................................................................................... NOTES: a/ Constrained by suppty capacity. No estimates availabLe on the extent of suppressed demand. b( Power supply position is based on sanctioned schemes assuming additional capacity during FY 91-95 of only 23307.7 bW. c/ An estimation of demand, based on consumption projections (including consuWtion to be met by non-utilities) plus transmission and distribution Losses. It is to be noted here that with the substantial supply constraints it is not possible to accurately estimate full uvnset demand. This figure merely captures the lowest boundary of demand. d/ The deficit here is underestimated in light of the inability to accurately estimate unmet demand. Source: Fourteenth Electric Power Survey of India, CEA, March 1991 - 49 - Annex 1.1 Page 2 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT ELECTRICITY SUPPLY AND DEMAND ALL INDIA: ENERGY CONSLMPTION BY MAIN CONSUMER CATEGORY Actual (X) Estimated (X) Consumer Category FY82 FY90 a/ FY91 fY95 --------- ---- ...... .... ....................... .. ----- --- 1. Domestic 11.6 14.1 15.2 17.2 2. Industry 57.7 51,5 51.1 49.8 3. Agriculture 16.9 22.1 21.9 21.3 4. Commercial 5.8 6.3 5.7 5.6 5. Traction 2.8 2.2 2.3 2.2 6. PubLic Lighting 0.9 0.8 0.8 0.8 7. Public Water 2.3 2.1 2.1 2.2 S. Others 2.0 0.9 0.9 0.9 100.0 100.0 100.0 100.0 - - . ----. ..... - - a/ Provisional as per Fourteenth Survey estimates Source: Annual Report on the Working of SEBs and EDs, Planning Commission (9/1990) Fourteenth Electric Power Survey of India, CEA, March 1991. - 50 - INDIA ANNEX 1.2 PoIER UTILITIES EFFICIENCY INPROVENENT PROJECT Previous Loans and C;edits to Indian Power Sector (as of November 30, 1991) (Amount in USS million) Approval Closirg Borrower IBRO Loans Nbmber Date Date Amount Disbursed Status -- - - .------.---. .... ............ . ........... - - -- - ......... - - - -- 1 India First DVC - Bokaro - Konar 23 4/50 2/56 18.5 16.7 Complete 2 India Second DVC tMalthon Panchot 72 1/53 f/58 19.5 10.5 Comptete 3 Tata Trombay Power 106 11/54 9/66 16.2 13.9 CompLete 4 Tata Second Trombay 164 5/57 9/66 9.8 9.7 Complete 5 India Third DVC - Durapur 203 7/58 6/65 25.0 22.0 Complete 6 India Kryno Power 223 4/59 4/65 25.0 18.7 Conplete 7 India Power Transmission 416 6/65 12/70 73.0 50.0 Comptete 8 Tata Second Kothagudem Power 417 6/65 12/70 14.0 13.8 Complete 9 Tata Third Tronbay Thermal Power 1549 4/78 12/84 105.0 105.0 Complete 10 India Ramagundam Thermal Pover (0) 1648 1/79 6/87 50.0 45.6 Complete 11 India Farakka Thermal Power (0) 1887 6/80 6/89 25.0 2.5 Complete 12 India Second Ramagundam Thermal Power (M) 2076 12/81 3/92 280.0 /a 270.4 13 India Third Rural Electrificatfon 2165 6/82 6/88 304.5 295.5 Complete 14 India Upper Indravati Hydro 2278 5/83 12/91 156.4 # 0.4 15 India Central Power Trarsmisslon (0) 2283 5/83 3/92 250.7 J 126.7 16 India Indira Sarovar 2416 5/84 6/92 17.4 /b 5.3 17 India Second Farakka Thermal Power (0) 2442 6/84 12/91 300.8 # 184.0 18 Tata Fourth Trombay Thermal 2452 6/84 6/92 135.4 125.2 19 India Chandrapur Thermal Power 2544 5/85 12/92 300.0 # 177.4 20 India Rihand Power Transmission (M 2555 5/85 12/91 250.0 # 191.5 21 Inr4ia Kerala State Power 2582 6/85 9/91 176.0 38.2 22 India Combined Cycle (0) 2674 4/86 12/91 485.0 448.4 23 india Karnataka Power 2827 6/87 12/95 330.0 # 45.5 24 India National Capital Power Suuply (0) 2844 6/87 6/95 425.0 /c 192.4 25 India Talcher Thermal Power C*) 2845 6/87 3/96 375.0 53.6 26 India Second Karnataka Power 2938 5/88 12/96 260.0 # 27.7 27 Indis Uttar Pradesh Power 2957 6/88 12/96 350.0 47.0 28 India Nathpa Jhakri Power 3024 3/89 12/97 485.0 36.7 29 India Maharahstra Power 3096 6/89 12/96 400.0 24.0 30 India Northern Region Transmission 3237 6/90 9/98 485.0 22.2 31 Tata Private Power Utilities (TATA) 3239 6/90 6/95 98.0 0.0 32 SSES Private Power Utilities (ISES) 3344 6/91 12/95 200.0 32.5 Total 6442.2 2653.0 (Total Loans for NTPC Projects) ( 2501.3 ) . ... ... .....U /a Ou of original loan amount of USS300 million, US$20 mitilon were cancelled. /b Out of original Loan amount of US$157.4 million, USS140 milLion were cancelled. /c Out of original loan amount of US$485 million, USS60 million were cancelled. IDA Credits .. ....... I India Fourth OVC - Durapur 19 2/62 12/69 21.9 19.9 Complete 2 India Second Koyna Power 24 8/62 9/70 21.1 21.1 Corplete 3 India Kothagudem Power 3t St63 12/68 24.1 24.1 Comptete 4 India Seas Equiprent 89 6/66 6/74 26.6 26.3 Complete S India Second Power Transmission 242 4/7i 3/77 75.0 72.9 Complete 6 India Third Power Transmission 377 3/73 9/78 85.0 85.0 Complete 7 Indfa Rural Electrification 572 7/75 12/80 57.0 57.0 Complete 8 India Fourth Power Tranrmission 604 1/76 6/83 150.0 149.9 Complate 9 India Singraulf Thermal Power (0) 685 3/7 6/84 150.0 150.0 Complete 10 India Korba Thermal Power () 793 4/78 3/86 200.0 199.9 CoupLete 11 India Rnmagundam Thermal Power (0) 874 1/79 6/87 200.0 200.0 Complete 12 India Second Rursl Electrification 911 5/79 3/84 175.0 171.7 Coiplete 13 India Second Singrauli Thermal Power (0) 1027 5/80 3/89 300.0 292.8 Complete 14 India Farakke Thermal Power (0) 1053 6/80 12/88 225.0 225.0 ComWlete 15 India Second Korba Thermal Power (M) 1172 7/81 12/89 400.0 # 370.3 Complete 16 India Upper Indrovati Hydro 1356 5/83 12/91 170.0 161.3 17 India Indira Sarovar SF020 5/84 6/92 13.0 /d 0.6 18 India Indira Sarover 1613 5/86 6/92 13.2 0.0 Total 2306.9 P227.8 (Total Credits for NTPC Projects) ( 1475.0 ,.. ....... .. (0) NTPC Projects /d out of original credit of Us$129.8 equivalent, US$116 equivalent were cancelled. U 0eaS not yet reflect cancellotions ade on Decomber S. 1991. INDIA POWER UTILITIES EFFICIENCY OVEMENT PROJECT Power Financ Corporatlon Ltd. Organization Chart Chairman and Managing Director Intemal Company SCcrelay Managemnt Coporate Planning, Policy Vigilance Audit and Legal Auidii l Formulation and Co-Ordination _ Diroctor Director Direct (Financiail) (Technical) (Operational) __ ~~Specialist b n vLoan ] rResource Financial SPecialist Development Cell for Administration " | Mobilization | | Advice Suppor Function Power Studies Accounting, axation, Liquidity Planning Control Fonulation Human Resource Managemnent, Personnel Budget.[S._and lnvesuwnt Planning and Administraton, Publicity and P.R. Financial Technology Scanning Appraisal and Co-Ordination |Co-Ordination||_ l o~~~nvirnmntal | nstitutaonal Devclopmnent ---- Funtional relationship I I4 Project Appraisal and Monitoring _ _ _J Technical, Economic and Financial App=aisal - 52 - Annex 2.2 Page 1 of 6 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Operational Policy Statement (This is a summary of PFC's document entitled "PFC: Operational Policy Statement (OPS): Its Rationale, Operational Philosophy, Objectives, Programs and Procedures", dated November 2, 1990 and approved by PFC's Board on November 12, 1990.) The Rationale 1. PFC has a critical developmental role in the power sector that is pursued through: (a) the promotion of improvements in the operational performance and financial managements of the sector's entities; and (b) through the encouragement of a balanced growth of the sector. Beneficiaries 2. The Memorandum of Association allows PFC to provide assistance to any power utility in the country. However, in view of the fact that state-owned utilities comprise the largest segment of the sector and are the utilities where the need for improvement in technical efficiency and strengthening of the financial management is most acutely felt, PFC will consider this an area of immediate priority. Operations Financed by PFC 3. In its comprehensive role as a development bank, PFC provides financial assistance for power projects, issues guarantees for payment of money, imparts training and supports the provision of consultancy services. 4. PFC's main objective is to finance: - power projects, including generation (thermal and hydro), transmission and distribution; - renovation and modernization of power plants; - system improvements and energy conservation schemes; - maintenance and repair of plant and equipment; - training; - research and development; - 53 - Annex 2.2 Page 2 of 6 promotion of renewable energy; and - consultancy. Linkage with the Five-year Plan 5. Funds provided by PFC to power sector entities constitute an additionality to the funds assigned to them through the Plan. The borrowers cannot substitute PFC's funds for earmarked allocations by the Planning Commission. 6. PFC funds are not allocated to the states. PFC'c financing decisions are based solely on the merits of individual projects. Eligibility Criteria 7. PFC will assist only those SEBs and SGCs who agree to implement Operational and Financial Action Plans (OFAPs) satisfactory to PFC. 8. PFC will lend only to projects that meet the following criteria: (a) are economically justified, with a rate of return of not less than 12%; (b) are technically sound; (c) technical solutions proposed must be least cost; (d) are compatible with existing expansion plans; (e) solutions proposed should meet GOI, State environmental and impact standards; and (f) schemes should have all clearances required by state and federal agencies. 9. Schemes for environmental upgrading of power stations have to meet acceptable engineering standards, and should be the most cost-effective means of mitigating environmental effects. 10. Priority areas for funding are the following: (a) renovation and modernization of thermal and hydro power plants; (b) system improvement; (c) expansion of transmission and distribution systems; and (d) completion of on-going generation projects. - 54 - Annex 2.2 Page 3 of 6 Reoavment Quarantees and ExDosure Limits 11. PFC will extend financial assistance only to those SEBs whose State Governments have given confirmation that PFC will have priority on the SEBs' surplus revenue over the loans granted by the State Governments to the SEBs, in accordance with the Electricity Act. 12. PFC's maximum exposure limits are set according to both its clients' credit worthiness and the guarantees offered by them. The following matrix combines the credit worthiness of the client and the guarantees offered by the client, to determine the credit risks weights to be used in calculating the maximum levels of exposure per client as a percentage of PFC's net worth: Matrix of Risk Exposure and Guarantees On-Balance Sheet Assets and Off-Balance Sheet Items Credit Guarantee Risk Level Rating (a) Offered (b) Weight (c) 1 A STG/BG .5 2 STG+EA .3 3 B STG/BG 1.0 4 STG+EA .5 5 C STG/BG 2.0 6 STG+EA 1.0 7 Backed by GOI 0.0 ----------------------------------------------------------- Definitions: (a) Credit Rating A: Debt Service Coverage in excess of 1.3 Credit Rating B: Debt Service Coverage between 1.0 and 1.3 Credit Rating C: Debt Service Coverage below 1.0. (b) STG: State Government Guarantee SG: Bank Guarantee EA: Escrow Account. (C) Risk Weight is the factor by which the loans outstanding that qualify under each level should be multiplied to calculate the exposure. F Por example, a Re 100 loan ranked as Level 1 will be computed as equivalent to Rs 50 (Re 100 X 0.5) for calculating the risk exposure. - 55 - Annex 2.2 Page 4 of 6 13. The Maximum Level of Exposure per client is as follows: 1991/92: 35% of PFC's Net Worth 1992/93: 30% of PPC's Net Worth 1993/94: 25% of PFC's Net Worth 1994/95 and thereafter: 20% of PFC's Net Worth (subject to review before the end of 1993/94 to determine its adequacy). 14. For the purpose of calculating the credit rating to determine the credit worthiness of a client, a debt service coverage (DSC) is established. In calculating the DSC: (a) the servicing of the loans from its State can be excluded, provided the State Goverument commits In writing not to ask the borrower for payment of interest and principal on its loans while any loan or guarantee received from PFC remains outstanding; and (b) any rural electrification subsidy not received should be excluded from revenues. In establishing the credit worthiness of its clients, PFC gives due regard to the amounts remaining due and unpaid to institutional lenders. Appraisal Procedures 15. During appraisal PFC will: (a) ensure that the project proposed meets PFC's selection criteria (para. 8); and (b) ensure that the borrowing entity agrees to implement an OFAP acceptable to PFC. Terms and Conditions 16. Although PFC mobilizes resources from different sources, its on-lending terms and conditions will be uniform irrespective of the source of financing. Non-rescheduling of Loans 17. PFC's loans will not be rescheduled. However, in exceptional circumstances, if PFC considers it financially prudent, it may provide a financial restructuring package supported by appropriate conditionality. Adiustabilitv of Lendina Rates 18. When PFC begins borrowing at variable interest rates it will include provisions in its loan documents to allow its lending rates to be adjusted both on the disbursed as well as the undisbursed portions of its loans. Procurement and Disbursement Procedures 19. Funds will be made available to the borrower only when the expenditure takes place. PFC has developed detailed disbursement procedures that apply to every operation. - 56 - Annex 2. Page 5 of 6 Supervision and Monitoring 20. The borrower shall furnish periodic progress reports, satisfactory to PFC, in respect to implementation oft (a) the project; and (b) the OFAP. In addition, PFC's supervision teams will periodically visit the projects to assess progress and to provide support to the borrower as needed. Remedies 21. PFC may suspend or cancel any part of a loan if the borrowing entity fails to perform any obligation under the legal agreements. PFC has developed a set of Guidelines for Application of Remedies (See Attachment). Financial Manaaement of PFC 22. PFC will endeavour to operate as a commercial entity, earning an adequate return on its capital (positive in real terms), maintain a healthy portfolio and build a strong financial base to enable it to borrow on attractive terms. Caotal Structure 23. Initially a maximum debt-to equity ratio of 4sl will be maintained. As PFC becomes better established, this ratio will be periodically revised. Debt Service Coverage Ratio 24. PFC's operations will be managed so as to maintain a debt service coverage ratio not lower than 1.2. Liauldity 25. PFC will maintain liquid assets equal to not less than the equivalent of the anticipated disbursements for the following three months. Profitabilitv Targetc 26. PFC's lending rates will be positive in real terms and will reflect its borrowing and operational costs, plus a margin to ensure its financial viability. Lending documents will include a provision to ensure that lending rates are adjusted to reflect this objective. Foreign Exchanae ard Interest Rate Risks 27. PFC will not bear the interest rate and foreign exchange rLsks in its operations. Guaranteelf 28. PFC will be lending to SEBs and BGCs only with the backing of guarantees provided by the State Governments or commercial banks. in addition, PFC may - 57 - Annex 2.2 Page 6 of 6 request contingent arrangements, like escrow accounts, to be invoked in certain cases, like when the guarantees have not been honored, or the OFAPs are not implemented to the satisfaction of PFC, or when SEBs/SGCs want to enhance their borrowing limits as indicated in para. 12. Term Transformation 29. PFC will determine the average repayment periods of its loans so as to ensure that the average maturity of its assets does not exceed that of its liabilities. Guarantees provided by PFC to SEBs/SGCs 30. The provisions in the preceding paragraphs relating to remedies, foreign exchange and interest rate risks, loan guarantees etc. will equally apply to guarantees granted by PFC to SEBs and SGCs for payment of monies by them. Accounting and Audit Systems 31. PFC will maintain its accounts in conformity with the requirements of the Companies Act (1956) and directives from the Gol. PFC's statutory Auditor is appointed by the GOI on the advice of the Comptroller and Auditor General, who may also carry out his own audit of PFC. Oroanization and Staffing 32. PFC is aware of the need to develop an efficient organization staffed with competent professionals from different disciplines. To support this effort PFC intends to maintain training programs that provide access to the latest developments in the different disciplines. Review of Policies 33. The above set of policies and procedures will be revised fzom time to time to reflect the changing needs in the operations of the Corporation. Note: PFC's Operational Policy Statement includes four annexes, as follows: Annex 1: Terms and Conditions of PFC's Loans. Annex 2: Disbursement Procedures of PFC's Loans. Annex 3: Guidelines for Application of Remedies in the Event of Default by its Borrowers. Annex 4: Accounting Policies The full text of he OPS, together with its annexes is included in the Project Files. - 58 - Annex 2.3 Page 1 of 5 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Guidelines for Preparation of Action Plans General Approach 1. The effectiveness of action plans as a tool for improving the performance of power utilities depends largely on the commitment of the utility to its implementation. The best way to ensure said commitment is by getting the utility involved, from the outser, in the preparation of the Plan. This approach avoids the risk of an adverse reaction to the Plan as the utility may consider that the actions included in it are "imposed" on them and are unrealistic. First Step: Diagnosis 2. The purpose of this first step is to determine the recent history and current status of the different aspects of the operations of the utility, including, inter alia, Organizational Structure, Financial Management and Control, Planning, Engineering and Construction, System Operations & Maintenance, Human Resources Administration, Support Services, Billing and Collections, Management Information System, etc. The preparation of the diagnosis requires a group of experienced professionals, with good knowledge on how each one of the functional areas of the utility should work and of the levels of performance that should be expected from each area. It is very important that the diagnosis be undertaken with direct participation of those to be later involved in the preparation of the Actio:i Plan and in its subsequent monitoring. Their participation in the diagnosis will give them an irreplaceable insight in the operations of the utility. When due to staff constraints, or because of the need to have specialized expertise in certain areas, it is necessary to retain consultants, it is highly advisable that the control of the diagnosis remains under the responsibility of the official in PFC in charge of the project. 3. An initial step in the diagnosis is the preparation of a set of financial statements (income statements, funds flows and balance sheets) for the 'last three to five years and projections for the next five to ten years, assuming a status quo in the operations, to show what the situation would be if the current level of tariffs and performance are maintained in the future. To provide a more realistic idea of the funds required, the investment program has to be properly adjusted for price escalation. These proforma statements are very important because they provide the reference point against which the impact of the action plan will be measured. They also give an initial view of - 59 - Annexi 2. 3 Page 2 of 5 the problems the utility may be facing (for example, liquidity, cost structure, inability to service debt, high level of work in progress). Experience shows that this stage can be productively used to introduce the financial staff of the utility in the use of computers for financial analysis. 4. Each one of the functional areas of the utility is reviewed by the experts in the diagnosis team. For this purpose, the development of a check list is -iery helpful, although care must be exercised to ensure that its use does not result in a mechanical approach. It is important for the team to maintain at "iI times an investigative attitude, trying to differentiate between the symptoms and the causes of the deficiencies detected. In tho process of preparing the evaluation, the team interviews the staff responsible in the utility, reviews documents, prepares flows, visits the relevant offices to see how the work is carried out, and in some cases interviews customers, suppliers, etc. The purpose is to gain a balanced and objective assessment of the situation. 5. The outcome of the evaluation is summarized for each functional area, ideally in tabular form to facilitate processing of the subsequent steps. The preparation of a diagnosis normally can be undertaken in no more than three weeks by a team of two or three expert professionals. Second Step: Discussion of the Diagnosis 6. It is at this level where the full participation of the utility should start. The purpose of this step is to reach agreement with the management of the utility on the diagnosis. There are two reasons that justify the need for this agreement. The first one, is to ensure that the evaluation team has not made any error of judgement. This is not impossible to happen, no matter how experienced the team is or how carefully the work has been done, the risk of reaching erroneous conclusions always exists. The second reason is that, unless the utility accepts the existence of the weaknesses detected in the diagnosis, any effort in getting them corrected would be wasted. 7. The best approach to discuss the diagnosis is to have meetings with the staff responsible for each particular activity. The objectives of these meetings are to: (a) establish whether they agree with the diagnosis of their respective areas; (b) get a better understanding of the causes of the problem; (c) confirm that no major issues remain unidentified; and (d) determine whether any corrective action is already being implemented. This step normally takes no more than three days. At the end of the discussions a revised diagnosis would be produced. Third Step: Preparation of the Action Plan 8. It is critical to stay away from the traditional approach of pretending to solve problems by simply stating that certain improvements in - 60 - Annex 2.3 Page 3 of 5 the performance targets should be reached by a future date. What is needed is to agree on the actions required to correct the weaknesses detected. For example, it is not of much use to say that Transmission and Distribution losses should be reduced to 18Z by December 1990, without indicating the specific actions to be taken in order to reach that performance. Here is where the participation of the SEBISGC staff becomes critical. With the active participation of each one of those in the utility responsible for the activity where a weakness is detected, ideas on how to deal with the problems will be explored. It is advisable to begin by asking those responsible for the activity about potential solutions. This tends to generate interesting proposals and gets them involved. They tend to know better than anyone what would work and what will not. Often it is better to adopt solutions that, although not optimal, are realistic. However, sometimes one encounters too negative or pessimistic positions that need to be changed through dialogue. In addition, PFC staff and the consultants can bring fresh ideas and experiences tried successfully in other utilities to broaden the scope of options. 9. After pondering the different options open in each case, one solution is selected. These options fall into two categories of actions: those under the control of the SEB/SGC and those outside their control (normally under the control of the State). The solutions may either include corrective actions to be iundertaken by the management of the SEBISGC, or require the assistance of specialized experts, in which case each one of the steps required to retain said experts should be included in the action plan (terms of reference, short list, selection, contract etc.). 10. Once the actions to deal with each problem have been agreed upon, the next step is L- establish: (a) when each action should be implemented; (b) who is responsible for implementing it; (c) what results are expected from its implementation, trying to quantify the outcome or present it in terms of changes in performance indicators (plant availability, PLF, rate of return, collection performance, etc); (d) resources required to implement the action; and (e) how and how frequently the implementation is going to be monitored. Fourth Step: Ranking of Issues and Phasing 11. It is not realistic to expect to solve every problem in one shot. Accordingly, the weaknesses detected should be ranked, giving priority to - 61 - Annex 2.3 Page 4 of 5 those that, if corrected, would have the greatest impact in terms of cash flow generation capability of the utility. This ranking should be done jointly with the management of the utility. Once the ranking is completed, the issues to be tackled in a First Phase should be selected. The duration of this First Phase has to be determinad in each case. In the case of PFC, since the objective is to have frequent operations with each SEB/SGC, each phase should probably include only the actions that could be completed in, say, 12 to 18 months, given: (a) the time required to undertake them, and (b) the implementation capability of the utility. The funds required to implement the action plan should be quantified and a financing plan to ensure its timely completion should be agreed upon. 12. Since institutional improvements should be a continuous operation, the action plan should include a trigger point, be it a date or the completion of a critical activity, indicating when the following phase should be initiated. Fifth Step: Financial Impact of the Action Plan 13. Most improvements in the performance of a utility have an impact on rhe utility's finances. For this reason, it is important to prepare a second set of financial projections reflecting the expected financial impact of the improvements intended to be accomplished through the Action Plan. These projections should be comppred with those prepared as part of the diagnosis, where a status quo was assumed. This comparison would clearly show how meaningful the proposed Action Plan is. If the Action Plan is not meaningful enough, it would need to be revised as needed until satisfactory results are obtained. 14. The financial projections showing the impact of the Action Plan also serve the purpose of providing a reference point for future monitoring. The pru!jaration of the Action Plan, its phases and the revised projected financil statement3 normally require about four weeks of two professionals, with ample experienct in power utilities management (one engineer and one financial analyst) wo,-king closely with the staff of the utility. - 62 - Annex 2.3 Page 5 of 5 Summary of Key Elements of OFAPs Approved for the SEBs of Puniab, Andhra Pradesh, Madhva Pradesh and Guiarat Functional Area Actions Tariff Restructuring Incorporation of automatic fuel surc.harge Annual tariff review and revision process Appointment of Committee to review tariff structure Payment of Subsidy Agreement by state governments to pay subsidy (in advance or monthly and on a cash basis) to allow the SEB to meet the 3% rate of return Capital Restructuring Conversion of part of State Government loan into equity to achieve debt equity ratio of 1:1. Billing and Collection Settling of inter-state and government outstanding accounts receivables Computerize billing and collection accounts Conduct meter testing Introduce age analysis of accounts Materials Management Review and develop inventory control systems for thermal power stations Review T&D stores management system and issue timely stores control reports Internal Audit Undertake technical audit (cost and quality) Accounting Systems Staff training on commercial accounting Appoint consultants to develop and implement costing system for thermal plants Planning & Budgeting Develop project evaluation and prioritization criteria Involve financial department in planning Link budgeting process with accounting system Introduce manpower planning Systems Efficiency Generation Conduct of full plant inspections Preparation of plant upgrading plans Preparation of detailed station maintenance manuals Transmission Conduct transmission network system analysis and prepare and implement least cost corrective actions. Distribution Prepare 10-year sub-transmission and distribution master plans for selected urban centers Prepare 3-year plans for addressing deficiency of low tension service for selected centers. - 63 - Annex 2.4 INDIA PROJECT UTILITIES EFFICIENCY IMPROVEMENT PROJECT ....................... .............................. PFC s Lending Operations Up To March 31, 1991 ,..... ........ ..... ......... ................. (Rs. MilLion) A. Summary of Loans Approved - Purpose-Wise No. of Type of Project Loans Amount X ..........--- ------. .... ... ... ..... .. ......... ...----....... 1. Generation 83 17,278 55 2. Transmission 132 9,364 28 3. Urban Distribution 56 2,138 4 4. Renovation and Modernization 55 3,332 7 5. Shunt Capacitors 26 1,548 6 TOTAL 352 33,660 100 R. Summary of Loans Approved by Borrower ............. ................................... No. of State/SEB Loans 1987-88 1988-89 1989-90 1990-91 TOTAL X .............. . ...... .......... ...... ............. ................... .... ...........---- ...... 1. Andhra Pradesh 36 152 963 1,088 1,470 3,673 10.9 2. Arunachat Pradesh 1 0 15 0 15 0.0 3. Assam 1 0 0 42 0 42 0.1 4. Bihar 14 0 323 543 643 1,509 4.5 5. Gujarat 23 0 362 465 1,070 1,897 5.6 6. Haryana 20 131 368 33 509 1,041 3.1 Himachal Pradesh 5 0 0 0 263 263 0.8 7. Janm & Kashmir 1 0 0 250 0 250 0.7 8. Karnataka 16 34 275 1,244 417 1,970 5.9 9. Kerata 9 0 0 9 232 241 0.7 10. Madhya Pradesh 47 35 571 1,265 1,912 3,783 11.2 11. Maharashtra 21 150 981 660 1,193 2,984 8.9 Nisoram 1 0 0 0 246 246 0.7 12. Nagaland 5 0 0 8 69 77 0.2 13. Orissa 18 105 213 206 790 1,314 3.9 14. Punjab 12 0 38 641 677 1,356 4.0 15. Rajasthan 12 151 498 19 489 1,157 3.4 16. Sikkim 4 0 0 30 50 80 0.2 17. Tamil Nadu 33 150 957 875 2,342 4,324 12.8 18. Tripura 1 0 0 9 9 0.0 19. Uttar Pradesh 54 167 1,590 2,403 719 4,879 14.5 20. Ust Bengat 16 0 627 964 887 2,478 7.4 21. DPL 2 0 58 14 0 72 0.2 TOAL 35 1,075---- ....7839 .... --------- 13,9.... -- 6 ......0 TOTAL 352 1,075 7,839 1D 768 13,978 33 660 100.0 - 64 - Annex 2.5 Page 1 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Environmental Assessment and Monitoring Unit Scope of Work and Procedures 1. Introduction 1.0 GOI and a number of States require that environmental assessment of power projects be submitted to the concerned authorities as a condition to obtain environmental and forest clearances for project implementation. In addition, there are Central and State norms for compensation and rehabilitation of population affected by Public Projects that power utilities must observe. GOI and the States issue environmental and forest clearances provided the concerned utilities undertake actions indicated in the letter of clearance to minimize adverse effects of proposed projects. Only projects which have been cleared in this respect by all concerned agencies would be eligible for Bank financing. 2.0 The World Bank requires, for all projects it finances, that the environmental and social implications of the same be appraised and dealt with in accordance with Bank policies in this regard. If Central and State regulations exist, the Bank requires that the project ronforms to the most stringent of all of them, including the Bank's. 3.0 Because of the public interest in environmental matters and the need that PFC financed projects meet the necessary environmental and social standards, the Corporation created an Environmental Assessment and Monitoring Unit (EAMU) under the Technical Director. 2. Respogsibilities The EAMU would: 'a) ensure that environmental assessment "nd social impact assessment of the project are incorporated in early stages of formulation as a factor in the analysis of alternatives and design of the project; (b) assist the borrowers as necessary in identifying major environmental and social issues associated to the project; (c) assist in the preparation of terms of reference for socio- environmental assessments (SEAs) of different kinds of projects and keep a roster of Consultants who can help in preparing assessments and impact mitigation plans; - 65 - Annex 2.5 Page 2 of 2 td) monitor execution of SEAs to ensure that they meet acceptable quality standards; (e) ensure that costs of mitigatory actions are properly considered in selecting and costing projects; (f) ensure that SEAs are conducted in accordance with the applicable standards; (g) monitor implementation of mitigatory plans and ensure that actions indicated by the concerned agencies for environmental clearance are carried out; (h) assist borrowers in assessing and proposing solutions for the correction of environmental deficiencies of power plants already in operation; and (i) promote and assist utilities in the creation of units specialized in environmental aspects of power utilities (i.e. design, monitoring etc.) The EAMU would not carry out itself SEAs but would provide assistance, review and monitoring of any work undertaken by the SEBs or their consultants in regards to PFC financed projects. 3. Staffing The EAMU would be staffed initially with one environmental engineer (emission, effluents, etc) one part time environmental scientist Cforest, wildlife, fisheries, etc.) and one part time sociologist/ anthropologist with experience in rehabilitation of displaced persons. - 66 - Annex 3.1 Page 1 of 8 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Detailed Project DescriRtion I. TRANSMISSION AND DISTRIBUTION 1. The project includes a number of transmission and distribution schemes which have been selected to alleviate most urgent deficiencies in the system. Typically schemes include: (i) removal of transmission constraints for power evacuation from power plants; (ii) reinforcement of overloaded transmission lines; (iii) increase of capacity of associated substations; (iv) expansion of overloaded distribution substations; (v) reinforcement of 66, 33, and kV distribution grid; (vi) installation of capacitors and distribution transformers to improve service and reduce losses; and (vii) purchase and installation of single-phase and three-phase consumption meters for new connections or to replace defective ones. The following are the schemes identified thus far: A. Punjab Transmission Lines - Phase I Ropar - Rajpura, 220 kV, 76 ckt-km Installation of second circuit for evacuation of power from Ropar thermal plant. Rajpura - Patiala, 220 kV, 26 ckt-km Extension of single-circuit line to evacuate power from Ropar station via Rajpura. Bhakra - Mahlipur - Jalandhar II, 220 kV, 94 ckt-km. Installation of double-circuit towers and first circuit of line to evacuate Punjab's share of Bhakra power plant. Includes setting up of a 220/66-kV substation at Mahlipur with 1 x 100 MVA module. Mukastar - Jallalabad, 220 kV, 35 ckt-km Installation of double-circuit towers and first circuit of line to increase supply to Jallalabad. Includes setting up of a 220/66-kV substation at Jallalabad with 1 x 100 MVA module. - 67 - AnneL 3.1 Page 2 of 8 Transmission Lines - Phase II - Ropar - Jalandhar II, 220 kV, 220 ckt-km Double circuit line for evacuation of power from Ropar thermal plant. Includes expansion of Jalandhar II 220/66-kV substation by 1 x 100 MVA. - Ropar - Govindgarh, 220 kV, 120 ckt-km Double circuit line for evacuation of power from Ropar thermal plant. Includes expansion of Govindgarh 220/66-kV substation by 1 x 100 MVA, and setting up of Govindgarh II, 220/66 kV substation with lxlO0 MVA. - Guru Nanak Dev (GND) (stage III) - Mukatsar, 220 kV, 65 ckt-km Single circuit line from Guru Nanak Dev for power evacuation. Includes connection of stages II and III of GND. - GND (stage III) - Sunam, 220 kV, 170 ckt-km. Double circuit line via Mansa for power evacuation and expansion of substation at Sunam by 1 x 100 MVA (220/66 kV). - xMoga - Mukatsar 220 kV 35 ckt-kin Installation of double circuit towers and first circuit of line to tap Punjab's share of NHPC plants. Distribution Schemes Distribution improvements in seven urban center as presented in Table 1. TABLE 1: DISTRIBUTION WORKS IN PUNJAB TOWNS FARIDROT JALANDUHAR HOSHIARPUR PHAGWARA PATIALA XHANNA BHATINDA TOTALS DISTRIBUTION WOS: - Increase in substation capacity No. of substations . 1 1 3 2 3 11 Total (MVA) 8.0 8.0 8.0 17.0 40.0 15.0 96.0 - Installation of capacitots (M4VAR) 1.5 1.5 1.5 4.5 6.0 3.0 18.0 - Installation of 66, 33 b 11 kV overhead lines and underground cables (km) 49 244 19 15 19 76 57 479 - Installation of distribution transformers go. 59 413 24 24 160 83 78 841 NVA 5.9 51.3 3.4 3.2 21.5 18.5 8.2 106.0 - Installation of censumption mtoter 40000 49000 6000 16000 8000 5000 3000 93000 - 68 - Annex - 3. Page 3 of 8 B. Andhra Pradesh Transmission Lines - Phase I - Chitoor-Renigunta-Sullurpet, 220 kV, 180 ckt-km Closing of southern 220-kV ring in the state. Installation of double circuit towers and first circuit to improve reliability of supply to this area. Includes bay extensions at Chitoor, Renigunta and Sullurpet. Transmission Lines - Phase II - Cuddapah - Renigunta, 220 kV, 132 ckt-km Construction of double circuit line to. feed power from Ramagundam thermal plant into Southern Andra Pradesh. Includes extension of one bay at Cuddapah and Renigunta substations and increase of transformation capacity at Renigunta by I x 100 MVA. - Ramagundam - Nizamabad, 220 kV, 147 ckt-km Installation of second circuit of this line to evacuate power from Ramagundam thermal plant. Includes extension of line bays at Ramagundam and Nizamabad substations, and addition of 1 x 100 MVA transformer at Nizamabad. - Ramagundam - Warangal, 220 kV, 90 ckt-km Installation of second circuit of this line to evacuate power from Ramagundam thermal plant. Includes bay extensions at Ramagundam and Warangal substations and addition of 1 x 100 MVA transformer at Nizamabad. Distribution Schemes Distribution improvements in seven urban centers are presented in Table 2. TABLE 2: DSSTaTrIT!ON WORKS rN ANDHRA PRADESE TOWNS C8STOOR KURNOOL NELLORE RAJABKUNDRY KAKINADA NIZAMDAD WARANGAL TOTALS OISTUBUTZON WORKS: - IAcrCase Ln substation capacity No. of substations 3 3 2 2 2 1 6 19 Total MVA) 35.0 20.0 30.0 40.0 20.0 10.0 72.0 227.0 -installation of capacitors (MVAR) 1.8 2.4 4.8 3.6 3.0 3.0 18.0 36.6 - nstallotion of 33 & 11 kV evehrbod lt.s and underground cables (km) 19 21 14 28.5 46.5 6.0 23.6 158.6 -tntallation of dlstribution transformers So. 189 223 334 374 349 199 100 1768 MVA 18.9 22.3 33.4 37.4 34.9 19.9 10.0 176.8 - Installation of consumption motors 17000 35000 41000 36000 36000 27000 380003 23J400 - 69 - Annex 3.1 Page 4 of 8 C. Madhya Pradesh Transmission Lines - Phase II - Bina - Malanpur, 400 kV, 532 ckt-km Construction of double circuit line to utilize MP share of power from Korba & Vidhyachal power plants. Includes the following associated works: - Construction of 400/220 kV, 315 MVA substation at Malanpur. - Addition of two 400 kV bays at Bina. - Double circuit interconnection between 220 kV and 400 kV substations at Malanpur (20 ckt-km). - Addition of four 220-kV bays at Malanpur. - Birsinghpur - Damo - Katni, 400 kV, 432 ckt-km. Construction of double circuit line to utilize MP share from Amarkantak and Birsinghpur thermal plants and from Tons hydro plant. Includes construction of 220/132-kV substation at Katni with 160 MVA capacity and extension of two 220-kV bays each at Birsinghpur and Damoh. Satna - Katni, 220 kV, 200 ckt-km Construction of double circuit line to increase supply to Katni & Damoh area. Includes extension of four 220-kV bays at Katni and four 220-kV bays at Satna, 20 ckt-km interconnection (_32 kV) between 220-kV and 132-kV sections at Katni, and addition of 132 kV bays at Katni. Distribution Schemes Distribution improvements in seven urban centers are presented in Table 3. - 70 - Annex 3.1 Page 5 of 8 TABLE 3: DISTRIBUTION WORKS IN MADHYA PADBESH TOWNS rNDORE UJJAlN KATNI DURG JABALPuIR RAiPuR KHANDWA TOTALS DISTRIBUTION WOS: - Increase in substation capacity No. of substations: NeV 2 3 3 2 3 3 2 18 Exgpansions 5 1 1 4 7 4 2 24 Total 7 4 4 6 10 7 4 42 Total (NVA) 35.0 20.0 17.0 18.0 41.0 35.0 20.0 186 - Installation of oapacitors (MVAR) 12.0 12.0 6.0 7.2 12.0 12.0 7.2 68.4 - Installation of 33 & 11 kV oYrhead lines and underground cables (kin) 115.8 116.6 136.7 183.0 74.5 71.0 65.0 762.6 - Installation of distrLbution trensforers: go. s0 62 172 117 108 73 94 676 I4VA 15.7 10.3 27.9 19.8 21.6 10.0 10.9 116.2 - Installation of Trivector neters 27 30 27 27 90 35 21 257 D. Guj arat Transmission Lines - Phase II - Gandhar - Kapadvanj 220 kV, 120 ckt-km Double circuit line to feed power to Kapadvanj from Gandhar station via Deghan. Includes 2 x 50 MVA substation at Kapadvanj (220/132 kV) - Deghan - Ranasan, 220 kV, 40 ckt-km Construction of double circuit line to feed power to Ranasan from Gandhar via Deghan. Includes addition of two 220 kV bays at Ranasan. Distribution Schemes Improvements of distribution systems in five urban centers as presented in Table 4. - 71 - Aex 3. 1 Page 6 of 8 *ABLE 4: DISTRIWUTION WORKS IN GUJARAT TOWNS RAJKOT BHAVNAGAR ISARUCH JAMNAGAR JUNAGARU TOTALS DISTRIBUTION WORKS. - Increase in substation capacLty No. of substations: (Includes Augmentation) - No. 1 2 1 1 1 7 - MVA 20 20 10 22.5 10 82.5 - Installation of capacitors (MVAR) 10 7.5 6 14.5 3 41 - Installatton of 132166111 kV 0/H lines and V/C cables 77.5 49 25 39 33 223.5 - Installation of distrLbution transformers: No. 70 46 35 71 45 267 :VA 10 10 7 16 7 50 - Installation of consumption motors 2250 1S00 1150 1700 1150 8050 ENVIRJONMENTAL UPGRADING OF POWER STATIONS 2. PFC has received financing applications for installation of electrostatic precipitators (ESPs) or expansion and renovation of existing ones in a number of power plants. These are expected to be financed by the Bank as follows: State Power Station Gujarat Ukai Uttar Pradesh Harduagang Obra Panki West Bengal Durgapur The estimated investment in these plants is about US$100milionu. In addition, PFC expects to receive requests for the following schemes during 1990/91- 1992/93 which could be financed by the Bank or other cofinanciers on a first- come-first served basis depending upon the availability of funds: S.tate Powr Station Gujarat Wanakbori Uttar Pradesh Obra (Phase II) - 72 - Anneg 3. 1 Page 7 of 8 Madhya Pradesh Satpura West Bengal Kolas '. Bihar Patr. ctU Baraun. Orissa Talcher Assam Bongaigaon Andhra Pradesh Kothagudem Estimated investment on these stations is about US$ 60 million. It has been assumed that 60% of the plants identified would be eligible for Bank financing under this component. Participating SEBs would also conduct .-I parallel an environmental audit of each plant included in the program to determine, and implement, any actions necessary to correct environmental deficiencies of the station (Annex 3.2) . The objective is for the station to meet the environmental standards established by GOI, the State or the Bank, whichever is more stringent. It has been estimated that about 100 consultant-months would be required to conduct the environmental audits, prepare the upgrading programs, and assist the SEBs in their implementation. III. INSTITUTIONAL DEVELOPMENT FOR SEBs 3. PFC and the participating SEBs have identified areas in which SEBs need immediate assistance for improvement. Actions to obtain and implement such assistance and associated timetables have been included as part of the OFAPs agreed between PFC and the SEBs. Many of these actions require participation of consultants and training of staff. There is also a need for the SEBs to acquire data processing systems, including computer equipment and software. Major areas in which assistance is required are: accounting, management information systems, organization and msthods, inventory management, operation and maintenance of plant, system modernization, advanced distribution planning, and billing and collections. The latter subject is discussed in further detail below. It has been estimated that about 400 consultant-months (average of 65 staff-months per participating SEB) would be required of which about 300 would be local and about 100 foreign. Letters of invitation for proposals including terms of reference for specific assignments are under preparation and would be issued by individual SEBs in accordance with the timetables agreed in the OFAPs. IV. SYSTEM RENOVATION STUDIES 4. This component is aimed at identifying high-priority investments in the areas of upgrading of generating plant as well as in transmission and distribution. The main objectives of the program are: (i) determine the causes of inefficient use of installations; (ii) propose ways to attack such causes or modification of existing designs or operating practices to avoid causes the elimination of which is uneconomical; and (iii) prepare the necessary - 73 - Annex 3.1 Page 8 of 8 engineering and implementation plan to carry out the recommendations. All SEBs and SGCs are eligible to participate in this program. It is expected that about 25 power stations, one or two major transmission systems, and about six urban distribution centers would be included in the program. It has been estimated that about 400 consultant-months would be required for the studies of which some 300 would be local. Annex 3.3 gives the suggested terms of reference for renovation of thermal stations. V. INSTITUTIONAL DEVELOPMENT OF PFC 5. This a program to strengthen PFC's capabilities to discharge its responsibilities. The program will provide specialized services, equipment, software, and training. An Implementation Plan is presented in Annex 3.5. The major activities to be covered under this program include: (a) enhancing PFC's management information system; (b) developing administrative manuals and procedures to guide internal operations: (c) developing manuals for project appraisal and monitoring; (d) training PFC staff in financial management, utility management, project management, power economics, upgrading of power plants, transmission and distribution, and planning and design of distribution systems; and (e) establishing a unit at PFC for sector studies to support the Corporation's operations. VI. PREINVESTMENT FUND 6. Annex 3.6 gives the details of functions and operation of the Preinvestment Fund. VII. IMPROVEMENTS OF BILLING AND COLLECTIONS 7. This component is geared to support efforts being made by various SEBs to improve their billing and collection systems. Some participant SEBs nave agreed, as part of the OFAPs, to revamp and modernize their billing and collections. The objectives are, inter alia, to reduce cycle times, simplify procedures, set proper customer accounts, improve controls, and facilitate customer access to collection points. SEBs are in the process of preparing terms of reference and letters of invitation for consulting services in accordance with the timetables agreed in the OFAPs. A second set of operations under this component comprises support to pilot billing and collection schemes of an innovative nature. Two of such schemes have already been identified: one is related to possible implementation of prepaid supply by use of magnetic cards and the other is a customer self-reading of meter being already tested successfully by Uttar Pradesh SEB. The details of how to support these pilot trials will be developed jointly by PFC, the SEBs and the Bank. - 74 - Annex 3.2 Page 1 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Environmental Review of Power Stations Suggested Terms of Reference OWl ectives 1. The objectives of the environmental review are to: (i) determine the degree to which participating power stations are meeting environmental standards set by GOI, the States and the Bank; (ii) identify the corrective actions needed to meet such standards in sustainable way; (iii) recommend other actions to restore plant environs to acceptable environmental condition and maintain such condition thereafter; (i , recommend an environmental monitoring system for the plant; and, (v) prepare a detailed program for implementation of the recommendations. The review should comprise handling of inputs (coal, oil, etc.), emissions and effluents from the plant (stack emissions, water discharges, ash, dust control, etc), sanitary conditions in and around the station, including colonies and camps, foci of deterioration around the station stemming from plant operations, irregular settlements associated to the plant, and any other environmental impacts the need to be mitigated or corrected. The recommendations of the review should be action oriented. In some cases the initial review may recommend more detailed studies of certain aspects to establish proper solutions to particular problems. These studies should not slow down other actions to arrest or mitigate environmental deterioration that can be implemented in parallel with the studies. Scone of the Review 2. The review would comprise the following main activities: (a) determination of environmental compliance requirements (review of applicable regulations and policies); (b) review of any existing past records on environmental monitoring of the station and assess quality and relevance of record keeping; (c) establish deficiencies in monitoring and formulate temporary program for sampling and collecting missing information for purposes of this review; (d) assess quality of reporting and procedures for notification of environmental conditions of the plant (for the utility and for other external authorities); (e) assess adequacy of administrative arrangements to handle environmental aspects of the station (authority and responsibility) and skills improvement needs; - 75 - Annex 3.2 Page 2 of 2 (f) assess employees and staff awareness of environmental aspects of the operation and need for educational programs; (g) determine adverse environmental effects, potential risks and deviation from norms being caused by handling of plant inputs including fuels, chemicals, water,and materials (dust, noise, spills potential, working conditions of operators, etc.); (h) determine adverse environmental affects, potential risks and deviation from norms being caused by handling of plant outputs (gas and particulate emissions, liquid effluents, ash, dust, refuse, etc); (i) assess the adequacy of on-site/off-site facilities to handle station inputs and outputs; (j) assess the adequacy of pollution control equipment installed at the plant, including gas emissions, particulate retention and removal, water and sewage treatment, noise abatement devices, dust control, etc; (k) review laboratory facilities, equipment, procedures, and standards; (1) review adequacy of procedures and frequency of maintenance of antipollution equipment including inspection and calibration of monitoring equipment; (m) assessment of the overall sanitary conditions throughout the station (water supply, sewage disposal, garbage disposal, rodents control, sanitary facilities for staff,etc.) including colonies and camps; and (n) identification of other adverse effects on environment around the plant, caused by its operat'on, which should be addressed or mitigated. ReDort and Recommendations 3. The results and recommendations of the review should be presented in a report which should include a timetable for implementation of each recommendation, proposed approach and administrative arrangements, cost estimates, and additional studies required if any, etc. '.mnlementation 4. PFC would, as a condition of financing the installation of electrostatic precipitators, agree with the concerned SEB that it would conduct the environmental review and implement the recommendations as per the agreed timetable. - 76 - Annex 3.3 Page 1 of 9 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT '.. Tentative Scope of Technical Assistance for System Renovation Background 1. Facing severe power shortages, India has decided, as part of its power sector development strategy, to identify and implement actions for modernizing and upgrading existing facilities as a cost effective way to improve supply. PFC is expected to play a significant role in this task through providing financing for renovation and modernization schemes and by assisting SEBs and SGCs in the identification and formulation of such schemes. With these objectives in mind, PFC is interested in obtaining technical assistance to enhance its knowledge of system rehabilitation and modernization. The assistance would cover renovation of thermal and hydropower plants, transmission systems and substations and urban distribution grids. Scope 2. PFC is particularly interested in the following topics: - system constraints analysis to identify elements suitable for upgrading; - detailed methodology for inspection and diagnosis of system elements (thermal and hydro plants, transmission lines, subctations' distribution systems); - determination of cost effectiveness of rehabilitation schemes; - approach to preparation and planning of rehabilitation projects; - availability and suitability of state of the art equipment and materials for modernization projects, and planning of retrofitting schemes; - organizational set-up for implementation and monitoring of rehabilitation and modernization projects; and - ex-post evaluation of renovation or modernization projects. Methodology 3. PFC considers that the most effective way to induct and familiarize its staff with current practice is to expose its personnel to actual practice in utilities successfully implementing renovation and - 77 - Annex 3.3 Page 2 of 9 modernization programs. Under this approach, PFC staff would be invited by participating utilities to work in different phases of project formulation and implementation. 4. In addition, staff from participating utilities would visit India to make classroom presentations, and organize workshops on specific aspects of rehabilitation and modernization. This activity should be heavily oriented to the practical aspects of planning and implementation as opposed to theoretical analysis of projects. 5. Participating utilities would subsequently provi_. support and advice through PFC to predetermined SEBs in identification and preparation of pilot schemes for modernization and rehabilitation. 6. The program is expected to last from three to four years. A detailed program would be prepareJ when participating utilities are identified. Financing 7. PFC is interested in obtaining grant finance from the home countries of participating utilities, Any expenses not covered by donor countries would be financpd by the Bank. - 78 - Annex 3.3 Page 3 of 9 B. Suggested Terms of Reference for Thermal Plant Rehabilitation Objective 1. The objective of the work is to formulate and execute a program to upgrade the performance of the existing thermal plant in the most cost effective manner. The program will include a review and improvement of equipment and installations, operational procedures, environmental operating conditions of the plant, plant management and support services, and identification of training needs of the staff. The main objectives of the program would be to: i) identify the causes of malfunctioning or poor performance of units; ii) identify ways of economically eliminating or mitigating these causes of the problems; and, iii) implementing remedial actions as needed to restore plant to acceptable performance levels. Phases 2. The proposed program is to be developed in three phases whose precise scope will depend upon the results of the preceding phase. GOI and the SEBs have carried out diagnostics of the physical conditions of the units. Many SEBs have also partially upgraded a number of stations. These diagnostics and actions should be taken as a basis, to be verified and modified as appropriate. The following paragraphs describe the general scope of each phase. Phase I 3. During Phase I, a work team (WT) including SEBs' staff and consultants as needed would identify and select the corrective actions to be proposed in the program, including their economic justification and priority. In this phase the WT should: (a) review the already existing reports or studies on the units prepared by GOI and the SEBs; (b) confirm, modify or expand the proposals contained in the above documents through visits and inspections to the units, discussions with operations staff of the concerned plants, and review of the existing information about the units' performance and operation; (c) review and analyze the operation practices, the reliability, accuracy and relevance of the data being collected by the SEB, the quality of their analysis and the use being made of the information; (d) review the practices for maintenance planning and scheduling; - 79 - Annex 3.3 Page 4 of 9 (e) assess the need for staff training and for administrative changes in the operation and maintenance, if needed; (f) reviaw the support systems, like management of spares, fuel, etc.; (g) assess the quality of the monitoring system, and appropriateness of the instrumentation being used; and, (h) develop cost estimates for the different corrective actions and prepare a cost-benefit analysis to rank them in merit order; 4. At the end of Phase I, the WT will prepare a report with their findings and recommendations, the cost estimates, and a tentative implementation plan for approval by SEB senior management. Phase II 5. During this phase the WT will 6-velop a detailed implementation and monitoring plan to carry-out the meast selected under Phase I. In addition, the WT will develop the engineer .tg, technical specifications, drawings, and packaging for procurement of the necessary parts and equipment. Among other aspects, the following should be considered: (a) organizational set-up for implementation; (b) procurement schedule including recommended packaging and procurement procedure to be followed (ICB, LCB, etc.) for each package; (c) repair schedule for each unit considering its operational commitments, delivery time for parts and equipment to be procured and the options for power substitution; (d) staff needed to carry-out the program by specialty and timing; (e) training program of the staff; (f) program for changes in procedures and practices for operation and maintenance; and, (g) monitoring for physical progress, cost control and results of the program, including the preparation of a model for progress reports; Phase III 6. The SEB, with the assistance of the WT, would implement the program and evaluate the results. - 80 - Annex 3.3 Page 5 of 9 Sco0e of Work 7. The following is the list of plants and units and plant services systems to be renovated: SEB Plant Name Unit Nos. KW Size Plant Systems 8. The WT will, for each unit and plant included in this program, carry out the following tasks: (a) review the records and reports on the history of each of the units and plant systems under evaluation. This shall include the O&M material procurement and spares status, records and any other pertinent files which may reveal data for evaluation. The information revealed by these reviews shall be used in defining the tasks to be included in the renovation of the units. This shall include the reasons for forced outages and unscheduled load reductions. The tabulation of the tasks to be performed on each unit/system under evaluation, shall be comprised of two lists; one will include the tasks common to most of the units of this size and manufacture and the other list will relate only to conditions prevailing in the individual plant or unit(s). If there is a need for the redesign of a piece of equipment or a system, the WT will draw up the terms of the redesign work and recommend who would do the redesign. The plant engineering personnel shall be incorporated into the WT research, testing and inspection teams; (b) discuss with the plant engineers any and all problems known to them that either impact on the performance and availability of the unit or where designs have been furnished which are not compatible with the current fuels and/or operating regimen; (c) inspect the entire unit and plant services during a scheduled outage. The WT will pre-test equipment and related systems for performance and/or integrity prior to the outage and analyze the data to establish the areas which require detailed inspection and evaluation during the outage; (d) review with plant managers and engineers the records, types and format of the reports issued by each group, the oral and writ-ten operating methods and procedures employed by the Operation and Maintenance departments, the performance of engineering and laboratory test groups and any documents which will establish the ways and means of managing the functioning of the plant. Maintenance planning procedures shall be given special consideration; - 81 - Annex 3.3 Page 6 of 9 (e) review the spare parts procurement and material conitrol procedures. The fact that many of the plants are remote from any other industrial facilities shall be weighed in the WT review of the personnel qualifications, spare parts and machine shop facilities on hand; (f) assess the adequacy of the administrative organization of the plant. 9. The WT shall review the plant organizations as they are now with the purpose of making suggestions and/or observations where improvements in the plant organization and skills can be enhanced through the proposed program. 10. Two major areas of improvement in unit efficiency and performance lie in: (a) the renovation and modernization of the instrument and controls; and, (b) the degree of upgraded or modern equipment, system and materials to be installed on the unit. The WT shall determine and evaluate the condition and suitability of the instruments and controls and the capability of the existing equipment to efficiently process the fuels and ash materials and the air, gas, water, steam and power flows being transmitted through the units. The ability of the existing design equipment to function under actual conditions shall be evaluated against the installation of modern design equipment which would further enhance the performance and reliability of the units. The evaluation shall include the life extension benefits by the renovation of the systems. 11. The following unit systems and equipment shall be included in the WT scope of review and evaluation: (a) mill system from the feeder to the burners, including the coal pipes and the hot air ducting from the primary air fans to the mill. The upgrading of the mills with new, modern design parts is also to be investigated and evaluated; (b) fans, including the forced and induced draft fans, primary air fans and if applicable, recirculating gas fans; (c) coal and fuel oil burners including turn down ratios, flame stability, flame monitoring and control, wear rates, efficiency of combustion, etc; (d) furnace and convection pass tubes, supports, hangers and headers. Include the effect on life span due to high temperature excursions and due to high ash erosion and excess air operation; (e) boiler casing/setting air tightness; (f) air preheater operation, maintenance and thermal performance; - 82 - Annex 3.3 Page 7 of 9 (g) general condition and upkeep of insulation and lagging; (h) high pressure and temperature piping and valve systems including hangers, snubbers and weld integrity, creep and stress cracks, etc.; (i) ash handling and storage facilities, capacity and wear rates; (j) feedwater heaters and piping, valves, and support system; (k) pump and motor drive units performance, control and reliability; (1) turbine-generator functioning, equipment integrity and performance from front standard to the exciter. This includes bearings, governor, rotor and stator integrity (turbine and generator), seals, blading, electrical windings, etc.; (m) condensing, cooling water and auxiliary equipment systems, instruments and controls including vacuum and seal systems, cathodic protection, level control and tube erosion/corrosion rates and pluggage and wear rates. The cooling towers and condensate, hotwell and circulating water pumps' condition and performance are also to be established; (n) make-up water rates shall be assessed. Target consumption is to be less than one percent; (o) control and instrumentation functioning, control accuracy, parts availability, capacity to control to within required set points, flame stability and monitoring and control systems, etc.; and (p) the electrical system equipment and materials conditions are to be examined, including the history of reliability of service on such items as the motors, switchgear and motor control centers, transformers, the relays and electrical controls and auxiliary power consumption. The CEA statistical report on equipment failures indicates an unusually high incidence of electrical equipment failures. This should be studied and a program drafted for the improvement in the reliability of this equipment. 12. In addition to the units to be evaluated and renovated, there are specific plant systems which also require inspection by the WT. The plant systems to be evaluated are listed below: (a) the coal handling system shall be inspected and evaluated as to the adequacy and suitability of service as it pertains to the present quality, quantity and physical size and extraneous material content of the coal being delivered. The inspection shall cover from coal delivery wagons to its discharge into the mills. The coal sampling system(s) and the magnetic separator(s) - 83 - Annex 3.3 Page 8 of 9 and the size, number and capacity of the plant coal crushers are to be considered in this analysis; (b) the stacking procedures used for storing the coal at the site as it pertains to rain drainage and the size of the storage pile (plant equivalent operating time), shall be included in the assessment of the coal handling system; (c) the ash handling system shall include the ash pipe conveying systems from the unit hopper to the storage pond. The integrity of the ash pond volume is also to be evaluated including the adequacy of the size of the pond based on load forecasts, the ash content in the coal and the ash collected with the installation of the new high efficiency ESP's. The planting of trees and vegetation on the filled pond surfaces also shall be evaluated; (d) the plant water treating and coal analysis test laboratories and instrument test and repair shop facilities shall also be assessed for suitability based on the size and complexity of the station; (e) the cooling and makeup water systems may be installed as a common plant system and as such should be included in the inspection and renovation program. This includes the water storage tanks and the cooling towers and circulating water pumps and motors; (f) the chimney may be installed as a common system and should also be appraised. This would include the flues and ducts as well as the insulation and lagging and stack liner(s) integrity; and (g) the plant control and instrument systems which are not included in the units package. 13. It is recognized that the renovation and modernization of the units may restore them to full rating. However, it is also apparent that unless the original causes of the deterioration are also corrected, the units will return to the same poor condition again in 5 to 6 years time. This is especially the case if the boiler furnace and convection pass sections continue to experience the present day coal and ash flow rates. The WT shall also include in the scope of services a realistic boiler rating which will permit the unit to operate at acceptable availability rates (902) and maintenance costs. It is assumed that the balance of the cycle will be capable of operating at full rating after the modernization of the unit. The WT shall verify this point. In order to achieve full unit nameplate ratings and still maintain acceptable performance on the boiler, the VT shall also investigate and establish the technical and economic feasibility of installing an additional boiler unit to supplement the lost steam flow from the derated boilers. This cost shall be evaluated against the addition of new thermal capacity. - 84 - Annex 3.3 Page 9 of 9 Environmental Upgrading 14. The WT will conduct a thorough inspection of the environmental aspects of the stations to determine whether they meet established pollution standards and whether they are generally operated in a way that minimizes adverse environmental impact. The WT will also review the station's monitoring arrangements and systems to ascertain their adequacy in light of existing regulations and current practice. The work of the WT will include air pollution, coal handling and stacking practices, ash disposal system and reclamation of ash ponds, water discharges and thermal pollution. The planting of trees and vegetation on the filled pond surfaces also shall be evaluated. 15. The WT will pay particular attention to safety and industrial security practices being enforced by the stations management on SEBs' staff and workers and those employed by sabs~ontractors working for the SEB. Monitoring and Reporting 16. The WT will submit monthly project progress reports on the status of the project in each plant, including cost expenditures, cash flow, schedule, construction progress with pictures, and any and all other matters of interest pertaining to the overall status of the project and also the status of the work at each plant site. - 85 - Annex 3.4 Page 1 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Draft Terms of Reference for Preparation of a Training Program for PFC 1. Study the various functions to be performed at different levels within each department of the Power Finance Corporation. Growth Plans of PFC should be considered to find out functions needed/likely to be performed in next 5 years. 2. Determine the expertise required at various levels to efficiently carry out tasks. This would take into consideration work methods currently used the likely impact of any computerization/automation. As far as practicable the dynamics of environment changes and technological innovations would be kept in mind. 3. Identify existing skills available within PFC depending upon the qualifications, experience and training of different personnel. 4. Evaluate gaps between the skills required to carry out tasks and skills available within PFC. 5. Define the type of skills required into technical, inter- disciplinary and behavioral areas. Special emphasis would be laid on types of induction level training, refresher training and on the job training, and retraining of individuals as they move from one level to another. 6. Evaluate training needs at various levels based on the above, and classify the as short term (to carry out specific tasks) and long term (to upgrade inzer-disciplinary skills and behavioral skills). 7. Study and recommend a corporate training plan for next 3-5 years. 8. Analyze and recommend an organization set up to look after training functions in PFC. This includes defining roles and responsibilities for training officers and mechanisms for their implementation. -Indicate training resources required and budgetary estimates. 9. List the institutions within and outside the country that can provide training to PFC personnel in various functions. List the institutions for different functional areas of training vis-a-vis their specialization. 10. Prepare course outlines for various training programs to be organized on regular basis. - 86 - Annex 3.4 Page 2 of 2 11. Develop a feedback mechanism to evaluate the impact of training based on participants' feedback, instructors' appraisal and occasional independent review. 12. Develop linkage of training to performance evaluation, Cadre Develo-naent, job enrichment and institutional strengthening of PFC. - 87 - Annex 3.5 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT POWER FINANCE CORPORATION PLAN FOR IMPLEMENTING THE INSTITUTIONAL DEVELOPMENT PRoGRAM ACTIVITY SOURCE STEP 1 STEP 2 STEP 3 STEP 4 OF --- --.- ---- ........... FINANCING Action Deadline Action Deadline Action Deadline Action Deadline -- -- .. ..... ...... - - - - - - - ...... - -- ...... 1. Strengthening of PFC: (a) Structure 1 (b) Managerial FunctAons I (incLuding manuals I and procedures) I USAID Prepare 1 month Hire 3 months Interim 3 months Final 6 months (c) Human Resource Mgmt. I T.O.R. after loan consul- after Action after Action after (d) SEBa' Support Functions I is made tants loan is Plan start of Plan start of (e) M.I.S. 1 effective effective study study (f) Office Technology l 2. Establish Sector Studies IBRO Define 3 month ApprovaL 4 months Staffing 6 months Work 8 months Unit in PFC Scope of after loan by PFC6s after after Program after Unit is made Board loan is loan is for the loan is effective effective effective First Year effective 3. Establishment of Pre-investment Fund in PFC (a) Set-up of Separate Fund I Prepare 6 months Retain 12 months (b) Define Policies & I T.O.R. after loan Consul- after Procedures 1 IBRD is tents. loan is (c) Prepare ManuaLs I effective effective (d) Organize Consultants J Rtoster 1 (e) Appoint Staff 4. Enhancement of SESs' Prepare 5 months Retain 12 months Billing and Collections USAID/ T.O.R. after Loan Consul- after IBRD is made tents. loan is effective effective . ............... ........... ...................... ........ ................ ............ ......................... .............................................. 5. Institutional Development of SEBs: (a) Preparation of OFAPs I (b) Consultancy to I USAID/ lAs needed according to each individual OFAPI Implement OFAPs I IiRD (c) Training of SEBs Staff I 6. Engineering Studies for System Renovation (a) Further Improvement to I Identify 4 months Prepare 6 months Retain 12 months plants renovated during 7thl IBRO Require- after loan T.O.R. after Consul- after Plan 1 ments is made Loan is tants. loan is effective effective effective (b) High Priority I tBRD Identify 6 months Prepare 8 months Retain 14 months Upgrading of Other PLants 3 Candidate after T.O.R. after Consul- after plants loan Is ioan is tents. loan is effective effective effective - 88 - Annex 3.6 Page 1 of 3 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT "ROJECT Power Finance Corporation Preinvestment Fund ConceRt and Scope of Operations Background 1. Power sector operations and expansion have been hindered in India, inter alia, by a shortage of adequately prepared schemes to improve efficiency and to expand system's capacity. The problem is particularly severe in hydropower projects and distribution schemes but it extends also to renovation of thermal stations and in some cases to transmission projects. The situation is the result of inadequate availability of funds to prepare projects and inadequate staffing of the SEBs or both. Moreover the level of preparation of many, projects are frequently below that required for financing decisions. This results in delays in obtaining funding and, more seriously, in unexpected technical difficulties and cost over-runs duritrg construction. Objectives 2. To alleviate the shortage of well prepared projects PFC has decided to create a Preinvestment Fund (PFCPF) which, would provide financing for project preparation and design. The proposed PFCPF would f4nance the following activities according to terms to be established by Pil: (a) Preparation of prefeasibility or identification of power expansion or improvement schemes; (b) preparation of feasibility studies for power schemes; (c) preparation of detailed engineering for power schemes; (d) preparation of studies of institutional nature and those necessary to improve the managerial, financial or operational efficiency of power sector or power utilities; (e) technical assistance and training necessary to implement actions recommended in the studies mentioned in (d); (f) studies necessary for system integration at regional or national level and for improved and efficient integrated operation; (g) studies of a sectoral nature leading to improve sector-wide policies and efficiency. - 89 - Annex 3.6 Page 2 of 3 Eligible ExRenses for Financing 3. PFC would finance the following items: (a) Salaries (including social benefits), overheads, fees and reimbursable expenses of consulting firms or individual consultants retained by the utilities (salaries, social benefits and overheads of Government ownedO Consultant Organizattons, Government consultants or utility s staff are not eligible for Bank financing but reimbursable expenses are); (b) purchase of specialized equipment such as surveying and laboratory equipment, specialized office equipment, computer hardware and software, equipment required for field investigation of projects, environmental monitoring equipment, etc; (c) field exploration for projects contracted out including geological investigations, exploratory, audits, laboratory, modelling costs, specialized material testing. establishment of instrumentation systems (hydrological, seismological environmental, etc.) and any other activities necessary to support sound technical project design and preparation; AnDroval of Loans 4. PFCPF financing would consider upon submission of properly supported requests submitted by the concerned utilities. The proposal should include a justification of the proposed study, the scope and terms of reference, cost estimate and basis for it, schelule of main activities and detailed arrangements for implementation (i.e. employment of consulting firms, individual consultants, counter part staff and facilities. etc.) and detailed procedures to be followed for procurement of goods, works and services. Amount of Financing 5. PFC could finance up to 100% of eligible study costs on tents be determined from time to time by PFC Board. Source of Funds 6. PFC would finance the activities of PFCPF through equity contribution from GOI, grants and loans from various donors and multilateral financial institutions and reinvestment of profits that may be generated through its own operations. Accounts and Audit 7. Accounts of PFC would be kept in such a way that all PFCPF operations can be clearly identified and audited by independent auditors. - 90 - Annex 3.6 Page 3 of 3 Prganization and Responsibilities 8. The PFCPF would operate as a specialized unit within PFC and not as a separate entity. This unit would be staffed as needed to discharge the following responsibilities: (a) Review and recommend to the Board of PFC requests for financing studies; (b) assist potential borrower in the identification and preparation of financing applications; (c) keep a roster of firms and individuals qualified ftc consultancy assignment for use by users of the PFCPF; (d) establish guidelines for selection and use of consultants; (e) assist borrowers in the selection of consultants; (f) assist borrowers in the preparation of terms of reference and typical contracts for consultancy services; (g) assist borrowers In administration of consultancy contracts; and (h) monitor execution of studies. - 91 - Annex 3.7 INDIA Page 1 of 5 POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Project Cost Sunmary Hill. Rs. HIll. USS LocaL Foreign Total Locat Foreign Total A. Sub-projects Fully CLeared: 1.Transmission Andhra Pradesh 261 154 415 9 5 15 PunJab 691 408 1.099 24 14 39 Madhya Pradesh 1,688 998 2.686 59 35 94 GuJarat 172 102 274 6 4 10 Sub-total 2,812 1,662 4,474 99 58 157 2.Dustribution Anndhra Pradesh 213 126 339 8 4 12 PunJab 197 116 313 7 4 11 Madhya Pradesh 232 137 369 8 5 13 Gujarat 129 76 205 5 3 7 Sub-total 771 455 1,226 27 16 43 3.Plant Envirorunent Upgrading Gujarat 171 1O1 V72 6 4 10 Total Sub-projects Fully Cteared 3,754 2,218 5.972 132 78 209 B. Sub-projects under preparation I.Transm. & Distrib. 226 134 360 88 52 140 2. Plant Envirornental Upgrading 847 500 1.347 61 20 81 Total Sub-projects under prep. 1,073 634 1,707 149 72 221 Total A+B 4.827 2,852 7.679 281 150 430 C. Project Support Tech. Assist.: Studies for Syst. Renovation 30 73 103 2 4 6 0. Capacity Building Tech. Assist.: Institutional Develop. of SE8s 48 50 98 3 3 6 Institutional Devolopment of PFC 10 10 20 1 0 1 E. Creation of Preinv. Fund 75 184 259 4 10 14 TOTAL SASELINE COSTS 4.990 3,169 8,159 291 165 457 Physical Contingencies 482 284 767 28 15 43 Price Contingencies 2,318 596 2,915 101 39 140 TOTAL PROJECT COST 7,791 4,050 11,840 420 219 640 Interest During Construction: World Bank 545 583 1.128 19 20 40 Others 907 62 969 30 2 32 TOTAL FINANCING REWUIRED 9,243 4,695 13,937 470 242 712 ...... ..........Totals ma,ntaL.... Note% Totats may not tatty due to rounding. - 92 - Annex 3.7 Page 2 of 5 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT GUJARAT STATE ELECTRICITY BOARD Project Cost Suanary Rs. Million US$ Million Local Foreign Total Local Foreign Total Transmission 172 102 274 6 4 10 Distribution 129 76 205 5 3 7 Environment 171 101 272 6 4 10 ......... ---- ---- .. ..... ...... ... ... .... . TotaL Baseline Costs-3/91 472 279 751 17 10 26 PhysicaL Contingencies 47 28 75 2 1 3 Price Contingencies 227 59 286 8 2 10 TOTAL PROJECT COST 746 366 1,111 26 13 39 Interest During Construction: worLd Bank 31 33 64 1 1 2 Other 69 0 69 2 0 2 T FN R R1 ....2.. ...... 4 ..3. TOTAL FINANCING REQUIRED 846 399 1,244 29 14 43 - 93 - Annex 3.7 Page 3 of 5 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT MADHYA PRADESH ELECTRICITY BOARD Project Cost Summary Rs. Mitlion USS Million Local Foreign Total Local Foreign Total Transmi'sion 1,688 998 2.685 S9 35 94 Distribution 232 137 369 8 5 13 ... ... ---- .. .... .... ... ---- ------ Total Baseline Costs-3/91 1,919 1,135 3,054 67 40 107 Physical Contingencies 192 113 305 7 4 11 Price Contingencies 922 239 1,162 32 8 40 -- - .... ...... ...... ...... ......_ TOTAL PROJECT COST 3,034 1,488 4,521 106 52 158 Interest During Construction: Wo-:d Bank 83 134 217 3 5 8 Other 336 0 336 12 0 12 TOTAL FN R E.. .....3...... ---50 ...... ...... TOTAL FINANCING REQUIRED 3,453 1,622 5,075 120 57 177 - 94 - Annex 3.7 Page 4 of 5 INDIA POWER UTiLITIES EFFICIENCY IMPROVEMENT PROJECT PUNJAB STATE ELECTRICITY BOARD Project Cost SLvmary Rs. Zitlion USS Mittion Local Foreign Total Local Foreign Total Transmission 691 408 1,099 24 14 39 Distribution 197 116 313 7 4 11 Total Baseline Costs-3/91 887 525 1,412 31 18 49 Physical Contingencies 89 52 141 3 2 5 Price ^ontingencies 426 111 537 15 4 18 _- - -- -- -- -- -- - .. . . . . . TOTAL PROJECT COST 1,402 688 2,090 49 24 73 Interest During Construction: World Bank 38 62 100 1 2 3 Other 155 0 155 5 0 5 TOTAL FINANCING REQUIRED 1,596 750 2,346 56 26 82 - 95 - ANNEX 3.7 Pasge 5 of 5 INDIA POWER UTILITIES EFFICIENCY IMPROVlEMENT PROJECT . ..... .... ........... ................................ ANDHRA PRADESH STATE ELfCTRICITY BOARD Project Cost Suunary Rs. Million US$ Million Local Foreign TotaL Local Foreign Total Transmission 261 154 415 9 5 15 Distribution 213 126 339 7 4 12 Total Baseline Costs-3191 474 280 754 17 10 26 Physical Contingencies 47 28 75 2 1 3 Price Contingencies 228 59 287 8 2 10 ..... ...... . ------ ...... ... ...... .......... . ..... ..... .... TOTAL PROJECT COST 749 367 1,116 26 13 39 Interest During Construction: World Bank 20 33 54 1 1 2 Other 83 0 83 3 0 3 ..... ......T ...... 1,2-3-30 ...... .....14 .. TOTAL FINANCING REQUIRED 852 401 1,2F3 30 14 4 - 96 - Annex 3.8 Page 1 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Procurement Arrangements 1. Procurement of materials and equipment for the project would be carried out by individual beneficiary SEBs under the coordination of PFC. Model bidding documents, approved by the Bank, would be used to ensure consistency of procedures. PFC plans to hold two main international bidding rounds as follows: Activity Date Date (Phase I) (Phase II) Finalization of bid documents 10/91 Invitation of bids 12/91-2/92 4/92-6/92 Bid opening 3192-5192 7/92-9/92 Bid evaluation and review by Bank 5/92-7/92 9/92-11/92 Award of Contracts 6/92-8/92 10/92-6/94 The main packages to be procured comprise the follo-tng materials, equipment and works: Transmission Towers Conductor & Earthwire Insulators & Hardware HV Transformers & Reactor Circuit Breakers Isolators CTs, CVTs, PTs Lightning Arrestors Miscellaneous Equipment for: Power Cables Circuit Breakers & Instrumentation Distribution Meters Conductor Power Transformers Capacitors Rail Poles Concrete Poles Steel Structures Batteries and Chargers Insulators and Fittings Earthwire Low-tension Circuit Lightning Arrestors Communications Equipment Miscellaneous Equipment Erection of Equipment Miscellaneous Civil Land Antipollution Equipment Engineering and Administration Studies for System Studies for SEBs Development Studies for PFC Development Preinvestment Studies - 97 - Annex 3.8 Page 2 of 2 2. Invitation of proposals for consuLing services for Training and Institutional Development of PFC would be procured starting in January 1992. Consultancs are expected to mobilize by July 1992. Consultants for the SEBs would be retained in accordance with the timetable agreed in the OFAPs for each SEB. - 98 - Annex 3.2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Schedule of Estimated Disbursements Proposed Project Starndard Bank FY Half Yearly Profilel/ and Semester Disbursement Cumulative Cumulative Z CumulativeZ 1992 I 0 0 0 0 II 15.9 15.9 6 6 1993 I 10.6 26.5 10 10 II 21.2 47.7 18 18 1994 I 21.2 68.9 26 26 II 31.8 100.7 38 38 1995 I 42.4 143.1 54 54 II 31.8 174.9 66 66 1996 I 10.6 185.5 70 74 II 21.2 206.7 78 78 1997 I 21.2 227.9 86 86 II 31.8 259.7 98 90 1998 I 5.3 265.0 100 100 iL Standard Disbursement Profiles. All Regions, Distribution Transmission. - 99 - ANNEX 4.1 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT SES's FINANCIAL PERFORMANCE 1986-1990 (Rs. Million) 1985/86 1986/87 1987/88 1988/89 1989/90 Total FY86-FY90 A. Consolidated Income Statement Operating kevenue 67,913 83,623 95,566 112,070 128,203 487,375 Rural Elec. Subsidy 3,763 9,283 14,849 11,805 9,662 54,362 Total Revenue 76,676 92,906 110,415 123,875 137,865 541,737 Operation & Maintenance 59,507 70,937 R5,666 100,328 115,176 431,614 Depreciation 6,102 6,953 8,037 9,230 10,812 41,134 TotaL Operating Expenditures 65,609 77,890 93,703 109,558 125,988 472,748 Income before Interest 11,067 15,016 16,712 14,317 11,877 68,989 interest: to Goverment 10,334 12,498 14,288 16,629 19,647 73,396 to Others 7,630 8,881 10,733 13,065 14,922 55,231 Net Income (6,897) (6,363) (8,309) (15,377) (22,692) (59,638) 8. Estimate of Internal Cash Generation: Income before Interest 11,067 15,016 16,712 14,317 11,877 68,989 Depreciation 6,102 6,953 8,037 9,230 10,812 41,134 Gross Internal Generation 17,169 21,969 24,749 23,547 22,689 110,123 Less:Subsidy not received (a) 8,763 9,283 14,849 11,805 9,662 54,362 Increase in Receivables(b) 3,528 3,928 2,986 8,609 4,679 23,729 Interest payments(c) 7,630 8,881 10,733 13.065 14,922 55,231 Repayment of Loans 5,251 6,470 8,018 9,342 9,289 38,370 Net Ir.ternal Cash Generation (8,003) (6,593) (11,837) (19,274) (15,863) (61,569) Net Int. Cash Generation US$ million (635) (509) (850) (1,188) (910) (4,091) C. Financial Ratios --------------- Average Net Fixed assets, beg. of year 136,870 166,060 180,850 204,570 244,220 191,545 Average Rate of Return (d) -5.0 -3.8 -4.6 -7.5 -9.3 -6.2 Adjusted Av. Rate of Return(e) -11.3 -9.4 -12.8 -13.3 -13.2 -11.9 Debt Service Coverage (f) 0.65 0.83 0.53 0.52 0.54 0.60 Debt Service Coverage (g) 0.36 0.46 0.30 0.30 0.30 0.33 Source: Planning Comission, Annual Reports on the Uorkings of the SE0s, New Delhi, 1989, 1990; PFC data. (a) Subsidies are seldom paid. In some cases they are upset against interest. (b) Assuming that receivables are equivalent to about 90 days of sales . tc) Assumes that interests on Goverrnment Loans are not paid. (d) On net historical fixed assets, after interest. (e) Adjusted for subsidies not received. (f) Adjusted for subsidies not received. Excludes interest on Goverrumnt loans (g) Adjusted for subsidies not received. Includes interest on Government loans - 100 - Annex 4.2 INDIA Page 1 of 4 POWER UTILITIES EFFICIENCY 1MPROVEMENT PROJECT POWER FINANCE CORPORATION Historical and Projected Income Statemnts (Rs Million) Fiscal Year ending March 31 1987-88 1988-89 1989-90 1990-91 1991-92 1992-93 1993-94 1904-95 < - ActuaLs----------> Estimates<------- Projected.---------.------ Interest Income Interest on Loans 1 112 G7 1,263 3,015 4,522 7,245 9,667 Income fros. Investments 57 489 570 1,043 822 732 767 784 Total Operating income 57 601 41,156 2,306 3,837 5,253 8,012 10,451 :peratini Expense Administration 1 8 16 33 53 72 92 115 Bond Issue Exr .nses 24 16 20 24 62 80 93 100 Interest:9% Bonds 26 349 642 990 1,260 1,260 1,260 1,260 11.5 Bonds 6 29 58 81 121 193 293 13% Bonds 0 0 0 390 1,268 2,308 3,44S IBRD 19 78 186 353 0 Other Foreign Loans 0 0 55 176 248 253 253 other 11 3 36 0 0 0 0 Total Interest Cost 26 366 673 1,158 1,985 3,082 4,366 5,251 Financing Charges 6 7 9 10 12 Total Operating Expenses 52 390 709 1,221 2,107 3,242 4,561 5,478 Prior Year Adjustments 0 3 Incom before taxes 6 211 450 1,085 1,730 2,011 3,452 4,973 Less: Provision for taxes c 63 146 275 363 422 725 1,044 etInom4 14 34 10 1,6 .... ...... ......2............7... 2 Ilet Incane 4 148 3tl4 810 1,366 1,589 2,727 3,928 - 101 - Arsex 4.2 POWER FINANCE CORPORATION Page 2 of 4 Historicat and Projected Sources and A plication of Funds (Ras Milion) Fiscal Year e,iding 1987-88 1988-89 1989-90 1990-91 1991-92 1992-93 1993-94 1994-95 Total Total March 31 -------ActuaLs.-- ---> Estimates ------- Projected-................ FY88-FY90 FY91-FY95 --------,,--- ----.---..-- --... -... .- -...- ., .-- ................. ........... ........ ........... ..... . Sources of Funds Surptus from Previous Year 1,302 4,594 i,502 8,216 7,318 7,674 7,839 0 2,502 Equity Contribution 1,000 2,000 3,000 2,201 2,000 2,000 2,000 2,000 6,000 10,201 Borrowings: 0 0 IBRO 332 690 1,193 1,t29 0 3,944 Other Foreign Loans 0 0 1,106 1,318 105 0 0 0 2,529 Issue of Bonds 9X(10 yrs) 1,000 6,000 1,000 6,000 0 0 0 0 8,000 6,000 Issue of Bonds 11.5X(20yrs) 200 200 200 200 500 750 1,000 400 2,650 Issue of Bonds 13X(7yrs) 0 0 0 6,000 7,500 8,500 9,000 0 31,000 Other Loans 574 500 1,074 0 Repayment Received 285 600 1,576 1,341 2,524 3,666 5,400 885 14,507 Retained earnings 4 148 304 810 1,366 1,589 2,727 3,928 456 10,421 Incr. in Current Liabitities 62 67 34 223 39 42 47 51 163 401 Other 0 1 0 1 0 . ........... ........................................ ............................................................... Total Sources 2,066 10,576 10,i33 14,618 20,812 22,269 26,555 30,948 16,978 84,155 . ....... ............................. ...................................................... .......................................... Application of Funds Loans Disbursed 1,011 4,978 6,976 8,968 10,640 14,370 18,440 22,920 12,965 75,338 Debt Repayment 0 525 549 0 0 0 28 525 577 Fixed Assets 2 1 3 5 5 5 5 3 23 Increase in Current Assets (248) 1,003 229 (3,116) 2,849 220 271 335 983 558 Increase in Other Assets 1 (1) (0) (2) 0 0 0 0 (0) (2) Short Term Investment 1,302 4,594 2,502 8,216 7,318 7,674 7,839 7,660 2,502 7,660 .... ..... ................................. ................................................... Total Applications 2,066 10,576 10,233 14,618 20,812 22,269 26,555 30,9 16,978 84,155 -......--------......---------...... ..----....-..---......----....---.. ...---..........--...--....... -... .... ....-. ........ .................. - 102 - Amnex 4.2 ... ... ..... ..... Page 3 of 4 POWER FINANCE CORPORATION Historical and Projected Salance Sheets (Rs Million) Fiscal Year eadirn Warch 31 1987-88 1988-89 1989-90 1990-91 1991-92 199Z-93 1993-94 1994-95 . -------Actuals--------- > Estimates ------- Projected---- -----> Liabilities and Equity .................................................. -------------------- ...... .......... .... Equity Paid-up Capital 1,304 3,304 6,304 8,505 10,505 12,505 14,505 16,505 Reserves & Surplus: Special Reserve 122 302 700 1,247 2,051 3,432 5,421 Debenture Redbopt. .eserve 0 25 148 168 851 851 851 851 General Reserve & Surplus 2 4 5 397 534 1,318 2,664 4,604 Totat Equity 1,308 3,455 6,759 9,770 13,137 16,725 21,452 27,381 Long-term Liabilities Bonds 1,000 7,249 ca,400 14,600 20,800 28,800 38,050 48,050 IDRD 332 1,022 2,187 3,831 Other Foreign Debt 0 0 0 1,106 2,424 2,529 2,529 2,529 Other 0 0 0 0 0 0 0 Total Long-term Liabilities 1,000 7,249 8,400 15,706 23,556 32,351 42,766 54,409 Current Liabilities Current Naturitiesz 0 525 549 0 0 0 28 85 Other 62 129 163 385 424 466 512 564 Total Current Liabilities 62 654 712 385 424 466 540 649 ~~~~~. .......................................... ............................._ Total Liabilities and Equity 2,370 11,358 15,871 25,861 37,116 49,542 64,758 82,439 _........ .... _. . _ _ . _.. ...... . ....... ...... . . . . . . . . Assets Short Term Investments 1,303 4,594 2,502 8,216 7,318 7,674 7,839 7,660 Loons & Advances 726 5,104 10,504 18,131 26.24? 36,951 49,991 67,511 Current Assets Repayment Due Next Year 285 600 1,576 1,341 2,524 3,666 5,400 5,400 Cash & nk B0talances 14 800 1,078 (2,041) 787 984 1,230 1,537 Other 38 255 206 208 229 252 277 305 Total Current Assets 337 1,655 2,859 (492) 3,540 4,901 6,907 7,242 Fixed Assets 2 3 6 11 16 21 26 Other Assets 4 3 3 1 1 1 1 1 . ....... ....... .............. .......... .......................... . . . .. Total Assets 2,3?0 11,358 15,871 Z5,861 37,116 49,542 64,758 82,439 ............. .......................... *............................................................................. - 103 - Annex 4.2 Page 4 of 4 POWER FINANCE CORPORATION Historicat and Projected Performance Indicators Fiscal Year ending 1987-88 1988-89 1989-90 1990-91 1991-92 1992-93 1993-94 1994-95 Merch 31 -------Actuals.--------- Estimates ------- Projected-.--------------- ... ... .................. .............. ......................... .. ...... ........ A-EARNINGS PERFORMANCE Internal Generated (IG)RsHilt. 4 433 379 1,837 2,707 4,113 6,392 9,301 IG as X of Loans Disbursed 0 9 5 20 25 29 35 41 Interest as X of Expenses 49 81 79 77 80 84 83 81 Net Returm on Portfolio X 0.4 3.5 2.9 4.5 5.2 4.3 5.5 5.5 Net Return on Total Assets % 0.2 1.3 1.9 3.1 3.7 3.2 4.2 4.8 Income Growth Rate X 105.7 166.6 68.6 16.3 71.6 44.1 Revenue Growth Rate X 92.4 99.4 66.4 36.9 52.5 30.4 Admninist. as X of PortfoLio 0.1 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Return on Net Worth X 0.3 4.3 4.5 8.3 10.4 9.5 12.7 14.3 Return on Paid-up Capital 0.3 4.5 4.8 9.5 13.0 12.7 18.8 23.8 Interest Paid as X of Income 45.6 60.9 58.2 50.2 51.7 58.7 54.5 50.2 Profit as% of Operating Income 7.0 24.6 26.3 35.1 35.6 30.2 34.0 37.6 Average Cost of Borrowings X 8.34 8.05 9.24 9.80 10.62 11.16 11.52 Interest Spread X 4.16 4.45 3.26 2.70 4.38 3.84 3.48 B-LIQUIDITY RATIOS Debt Service Coverage (DSCR) 2.2 2.4 1.5 2.3 2.6 2.5 2.7 3.0 DSCR Excluding Collections 2.2 *.6 1.0 1.4 1.9 1.7 1.8 2.0 Liquid Assets: Next Period Disbursements (months) 3.17 9.28 4.79 6.96 6.77 5.63 4.75 8.51 C-CAPITAL ADEQUACY Debt:Equity Ratio 0.8 2.2 1.4 1.7 1.8 1.9 1.9 1.9 - 104 - Annex 4.3 Page 1 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Assumptions Followed In Financial Projections Base Case Income Statement 1. Interest on Loans: 12.5Z p.a. up to 1991/92; 15? afterwards. 2. Income from Investments: 10? p.a. on cash reserves invested. 3. Administration: one half of one percent of loans disbursed during the year. 4. Bond Issue Expense: 1? of the bonds floated during the year. 5. Tax Provision: 212 of income before taxes. Sources and Applications of Funds 1. Equity Contribution: it was assumed that GOI would continue making its contributions towards PFC's capital at the same pace of prerious years. 2. Borrowings: although it is recognized that, to help develop PFC into a major player in the power sector, GOI intends to allow it to tap the domestic market in amounts much larger than those of the initial years, for the base case it was decided to take a more pessimistic approach. Accordingly, the level of borrowing grows gradually. On the other hand, the limitations in the availability of 10 year, 92 and 20-year, 11.5? bonds, were taken into consideration. Most of the borrowing is assumed to be through 7 years, 13t bonds. On-lending from GOI to PFi of the proceeds of foreign loans is assumed at 11.5Z p.a., with a total maturity of 15 years including 3 years grace period. GOI assumes the foreign exchange risk. - 105 - Annex 4.3 Page 2 of 2 3. Repayment Received: In the spite of the securities designed into PFC operations, to maintain a conservative margin it was assumed that only 80? of the payments due were collected. 4. Loans Granted: Several factors affect the future level of PFC's lending. These include: (a) receptivity to PFC's conditionality; (b) ability of clients to comply with PFC's eligibility criteria; (c) availability to SEBs/SGCs of alternative sources of funds; and (d) PFC's own access to sources of financing. For thebe reasons, a rather conservative posture was assumed. However, it is recognized that the level of lending assumed in the base case may not be compatible with the share of the sector funding GOI expects to take in the Eighth Plan. Balance Sheet Investments: The cash reserve was assumed equivalent to about six months of disbursements. It was assumed that it would be invested in assets readily convertible into cash. - 106 - Annex 4.4 Page 1 of 2 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Sensitivity Analysis - Selected Cases Case "A" Parameters (1990191-1994/95): (a) Lending Volume: Rs 125,000 million, at 12.5Z p.a. (b) Foreign Borrowing: Rs 10,000 million (112 of borrowings), at 82 p.a. plus 62 foreign exchange risk. (c) 10-year, 9% Bonds: Rs 46,800 million (532 of borrowing). *d) 20-year, 11.52 Bonds: Rs 31,200 million (35Z of borrowing). Financial Performance: Fiscal Year Ending 90-91 91-92 92-93 93-94 94-95 March 31 <---------Projected----------> IRG as Z of Loans Granted-Rs. Million 11 14 20 27 34 Debt Service Coverage Ratio (DSCR) 2.2 2.1 2.2 2.4 2.5 DSCR Excluding Collections 1.9 1.8 1.7 1.6 1.6 Interest as Z of Operating Expenses 80 83 85 86 87 Net Return on Portfolio Z 3.9 3.4 3.2 3.1 3.1 Administration as Z of Portfolio 0.1 0.1 0.1 0.1 0.1 Return on Net Worth 2 13.1 13.2 13.5 13.7 13.6 Debt Equity Ratio 2.6 3.1 3.4 3.6 3.6 Case "BO Parameters (1990/91-1994/95) (a) Lending Volume: Rs 44,650 million, at 152 p.a. (b) Foreign Borrowing: Rs 6,400 million (26Z of borrowings), at 142 p.a. (c) 10-year, 9% Bonds: nil. (d) 20-year, 11.5Z Bonds: Rs 16,750 million (67X of borrowing). (e) 7-year, 13? Bonds: 1,750 (72 of borrowings). (f) Cost to the Equity: 1O0 of share capital. - 107 - Annex 4.4 Page 2 of 2 Financial Performance: Fiscal Year Ending 90-91 91-92 92-93 93-94 94-95 March 31 <- ---Projected-----------> IRG As X of Loans Disbursed 15.74 26.60 35.78 33.98 33.92 Debt Service Coverage Ratio 2.15 2.60 2.86 2.65 2.50 Interest as Z of Optg Cost 98.20 97.82 97.51 97.43 97.38 Return on Loan Portfolio 4.73 5.61 5.26 4.90 4.66 Admn Expl Portfolio 0.06 0.06 0.06 0.05 0.05 Return on Net Worth 2 12.61 14.24 13.40 12.88 12.85 Interest Paid As 2 Of Total 47.53 43.43 45.65 48.46 50.91 Case "C" Parameters (1990191-1994195) Substantially the same as the Base Case, but assuming PFC's lending rate remains at 12.5? (a) Lending Volume: Rs 73,338 million, at 12.5% p.a. (b) Foreign Borrowing: Rs 6,051 million. (c) 10-year, 91 Bonds: Rs 6,000 million. (d) 20-year, 11.52 Bonds: Rs 2,650 million. (e) 7-year, 13Z Bonds: Rs 29,800 million. (f) Cost to the Equity: 10? of share capital. Financial Performance: Fiscal Year Ending 90-91 91-92 92-93 93-94 94-95 March 31 <--- Projected- -- --> IRG as X of Loans Disbursed 21 24 27 31 33 Debt Service Coverage Ratio (DSCR) 2.3 2.4 2.3 2.5 2.5 DSCR Excluding Collections 1.4 1.7 1.6 1.6 1.6 Interest as Z of Ope. Expenses 77 82 86 86 87 Net Return on Portfolio X 3.2 2.8 2.9 3.0 3.1 Administration as Z of Portfolio 0.2 0.2 0.2 0.2 0.2 Return on Net Worth 2 8.5 9.0 9.3 9.5 9.8 Debt Equity Ratio 1.7 2.2 2.2 2.2 2.2 - 108 - Annex 5.1 Page 1 of 19 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT PUNJAB SEB TRANSMISSION AND DISTRIBUTION PROJECT Economic Analysis 1. Punjab State Electricity Board is seeking PFC financing under the proposed Bank loan for its proposed set of transmission and distribution expansion schemes. This section illustrates the methodology applied by PFC in evaluating the economic viability of the T&D schemes based on the approach recommended by the Bank. Similar analyses were undertaken in the economic appraisal of project proposals from other SEBs. 2. To assess the economic viability of PSEB's proposed transmission and distribution schemes, the sub-projects were reviewed as to whether: (a) they are part of t.ie least cost power system expansion program for the State as well as for the Northern Region p..wer grid; and (b) the investments will yield adequate economic benefits to the country. Pro.ect Scope and Objectives 3. Punjab SEB's proposed project for PFC financing from the World Bank loan consists of: (a) construction of about 331 km of single circuit and 250 km of double circuit 220 kV lines, and associated substation with aggregate transformer capacity of 600 MVA; and (b) reinforcement of distribution system in seven (7) major towns by providing additional sub-transmission lines, associated sub-station and distribution transformers as well as capacitor banks and meters. 4. The transmission system improvements will help meet the growing electricity demand in Punjab State by facilitating the evacuation of power from the 2x210 MW capacity additions to PSEB's Ropar Thermal Plant and Guru Nanak Development Thermal Plant (GNDTP), respectively. In addition, the project will improve the dispersal of the allocated share of power from the nodal point of the central sector (NTPC and NHPC). Other components of the transmission project involving network revamping will result in the upgrading of delivery voltages, increased service reliability and reduced system losses. - 109 - Annex 5.1 Page 2 of 19 5. The parallel expansion and reinforcement of the discribution system being proposed is expected to result in delivery of electricity to more users, increased reliability of existing services and lower distribution losses. Market Profile. 6. Over the past 5 years, peak demand for power served by the Punjab grid, increased at an average annual rate of 12.7% reaching 2,771 MW in 1989/90. Actual peak demand is however estimated to be even higher in view of the load curtailments that have been experienced due to the shortage of demand capacity at periods of system peak. In the coming 5 years, peak demand is expected to grow at an average of 7.3% per annum or to just below 4000 MW by 1994/95. Energy sales have increased since 1985 at a corresponding rate of 12.3%, and is estimated to have reached 12,037 GWh in 1989/90. Sales is projected to rise at a yearly average of 7.1% growing to nearly 17,000 GWh by 1994/95. 7. The present structure of electricity demand in Punjab comprise of 39.7% agricultural, 34.6% industrial, 11.0% domestic, 7.8% fertilizer production served through common hydro pool, 2.6% commercial, and the balance of 4.3% for streetlighting and bulk supply. The high share of agricultural demand is expected to be sustained over the coming years since Punjab is a lead agriculture center of India accounting for about 60% of the country's cereal production. Svstem SUDPly 8. PSEB's current installed capacity is 3,050 MW consisting of 1280 MW coal-fired plants, 515 MW of hydro and 1254 MW share of common pool hydroplant. In addition, PSEB has an allocation of 575 MW from the central sector power projects operated by NHPC and NTPC. 9. The Board operates an extensive high voltage transmission grid at voltages of 220 kV, 132 kV, 66 kV and 33 kV. Major expansion has occurred in the 220 kV and 66 kV network, including upgrading of 132 kV supply to 220 kV, and of 33 kV supply to 66 kV, At the same time, the 33 kV network is progressively being phased out. PSEB's substation capacity has expanded at an average annual rate of 7.6% since 1984. As of March 31, 1989, PSEB's transmission and distribution facilities are as follows: Table 1: PSEB's T&D Network Voltage TED Lines Substation (in ckt.km.) No. Capacity (MVA) 220 kV 1646 18 2812 132 kV 2773 52 2833 66 kV 3140 198 3033 33 kV 1535 108 912 Total 9094 376 9590 S - 110 - Annex 5.1 Page 3 of 19 System Operation 10. System peak normally occurs in late summer and fall (September to November) under high temperature conditions. The rise in demand is primarily due to irrigation pumping requirements for agricultural purposes. In 1989/90, the peak demand of 2771 MW was registered in September and the system's load factor was about 65%. Transmission and distribution losses were 17%. 11. Generation dispatch in the grid is based on the seasonal pattern of hydro production which accounts for about 60% of the system's energy requirements. Major pondage inflows occur in summer, during the monsoon season, and after winter when snow melt from the mountains. Overhaul maintenance of theri,ial stations is pursued at time of maximum hydro production; conversely, hydroplant maintenance is carried out when irrigation releases are low, at which time, thermal production is maximized. 12. This seasonal interplay of thermal and hydro production is a critical factor in the design of PSEB's transmission network. A salient feature of the proposed project is the strengthening of the transmission linkage between the thermal and hydro stations so as to permit optimum and flexible operation of the grid under varying conditions of hydro and thermal mix. Least Cost Analysis 13. The PSEB has carried out internal staff studies to arrive at the least cost options of attaining the operational objectives targetted by their proposed projects. These analyses were in terms of detailed load flow studies to identify the weak points of the network and possible circuit and transformer overloadings. Alternatives satisfying system reliability and voltage design criteria have been examined at various stages of planning to arrive at the best option based on technical and cost considerations. 14. PFC has reviewed the alternative options considered by the PSEB. In a number of cases, there were no reasonable alternatives to the proposed schemes, e.g. the stringing of a second circuit on transmission towers already erected and lines traversing the shortest direct route between designated loading points. Moreover, as in other systems, PSEB has generally standardized transmission system voltages at 220 kV and conductor ratings at 100 MVA per circuit, such that consideration of alternative voltages have largely been limited to cases of upgrading from 132 kV to 220 kV. For sub- transmission systems, the voltages and type of substations depend on various factors, such as load density and network layout. Transformer size and ratings have also been standardized; the most common voltage ratings of the secondary sub-transmission systems are 132/110/66/33 kv, and for primary distribution system, 11, 22 or 6.6 kV. 15. The 220 kV works itself have been cleared by CEA following its transmission planning criteria. These criteria require transmission systems to be planned based on regional self-sufficiency, capable of transmitting the - All - Page 4 of 19 respective state's allocation from the Central Sector, and able co withstand specified levels of outages I/ without having to resort to load shedding or rescheduling of plant generation. 16. In the case of distribution schemes, whenever possible, low cost alternatives have been considered by PSEB, e.g., outdoor substations over indoor, overhead lines following shortest direct routes over underground cables, etc. Since the schemes cover mainly critical works for immediate relief to the systems and are to meet the load growth up to the next five years only, consideration of alternative voltages was limited. The procedure adopted by PSEB has been to select the reinforcement and renovation requirement in the distribution system to satisfy design criteria mutually agreed with PFC. These criteria cover statutory requirements of supply (e.g., voltage regulation), reliability norms, flexibility for future expansion and other technical considerations. State oer Investment grogram Analysis 17. The State Power Investment Plan for Punjab calls for the installation by PSEB of 930 MW of generating plant addition between 1990 and 1995, of whi.h over 90% is in terms of additional coal thermal capacity. Together with the planned transmission and distribution improvements, the program will involve capital outlays of about Rs 21 billion (excluding IDC and contingency) over the five-year period ending 1995. Of this aggregate investment, 60% represents the cost of generation plant expansion, 26% for transmission development, and the balance of 14% for distribution improvement. PSEB's system expansion under the program will be further supplemented by additional power allocation from the Central Sector resulting from NTPC's and NHPC's respective investment expansion activities. Energy transfers from the Central Sector is projected to increase from 2144 Gwh in 1988/89 to 3438 GWh in 1991/92 and stabilizing thereafter. 18. Under the Program, reserve capacity margin is expected to decline from 29% to 15% suggesting that peak capacity shortfall will continue to be a problem despite the planned plant additions. State Proaram Costs 19. In addition to the capital costs of the program, the operating and maintenance (O&M) expenses associated with ,he grid operation including the cost of energy purchases from the Central Sector were considered. The cost and technical operating parameters assumed are: (a) Fuel costs are based on the purchase price of Rs 642 per ton of coal and Rs 3.33 per liter of fuel oil; and fuel consumption rates of 0.66 kg per kWh generated for coal, and 0.0132 kg per kWh for oil as per existing plant operation; 11 These are outages of (a) two circuit of 220 kV system, or (b) of one circuit of 400 kV or higher voltage system, or (c) of one pole of HVDC bipole, or (d) of an EHV transformer. - 112 - Annex 5.1 Page 5 of 19 (b) Annual capacity factor of thermal units is taken at 60%; auxiliary consumption at 8%; (c) Other O&M expenses are estimated at 2.0% of capacity cost for generation, 2.5% for transmission, and 3% for distribution. These estimates are consistent with historical levels of O&M costs of PSEB with due allowance for incremental effects of plant improvements; and (d) Purchases from Central Sector projects was priced at Rs 0.44 per kWh based on anticipated price levels to be set by NHPC and NTPC. 20. In calculating the economic costs, taxeE and duties are excluded from the above financial estimates, and local currency costs subject to a standard conversion factor (SCF) of 0.8. Coal used at PSEB's thermal plants are railed from mines situated near the border of Bihar and West Ber.gal and is classified as low grade CIL class E steaming coal with specific heating value of 16.0 GJ/Tonne (or 3800 to 3900 kcal/kg). In view of its relatively poor quality and low heating value, the coal is considered non-tradeable and its economic cost is estimated at Rs 429 per ton. The economic price of fuel oil is based on the border price plus local handling and delivery costs and is estimated at Rs 2.5 per liter. State Program Benefits 21. The benefits of the State Power Investment Program consist of the additional power supply arising from capacity expansion in power plants (930 MW) as well as in the transmission and distribution network. Commissioning of new generation facilities is expected to meet increases in system demand as well as displace less efficient thermal generation during the plants' initial years of operation. Table 2: Projected Energy Dispatch from New PSEB Capacity (in GWh) Additional GWh GWh Displacement Total GWh Fiscal Year Input to System of Less Efficient Units Generation 1991-92 619 853 1472 1992-93 1783 1160 2943 1993-94 2705 1160 3865 1994-95 4045 423 4468 1995-96 onward 4468 - 4468 22. The benefit due to incremental power supply (including those resulting from power purchases) is assessed in terms of the revenues derived from the equivalent electricity sales (assuming 17% T&D lo3ses). The pattern of end-user consumption is assumed to remain stable at 40% agriculture, 40% industries, and 20% residential/commercial. Average sales revenue is assumed to remain constant at Rs 0.70 per kWh based on prevailing tariffs and State - 113 - Annex 5.1 Page 6 of 19 subsidy. PSEB's average tariff increased by less than 5% a year since 1984/85 and has thus not kept abreast with inflation. Domestic and industrial customers have shouldered most of the increase, while agricultural users enjoyed even larger tariff subsidy resulting in reduced agricultural rates of Rs 0.08 per kWh in 1988/89 compared to Rs 0.19 per kWh in 1985. 23. For the purpose of determining the economic value of electricity consumption, the prevailing tariff adjusted by SCF of 0.8 is taken as the lower limit of the consumers' willingness to pay, i.e. Rs 0.56 per kWh. The upper limit is established based on the consumers' cost of electricity from alternative power sources. For residential and commercial consumption, the alternative is taken to be the cost of autogeneration from small diesels estimated at Rs 2.75 per kWh. For industrial users, the relevant cost is that of autogeneration from larger diesel units (250-400 kW) estimated at Rs 2.07 per kWh. For agricultural consumers, the upper limit was taken to be the equivalent energy cost of providing irrigation pumping from diesel pumps in lieu of electric pumps, estimated at Rs 3.41 per kWh. Applying these costs to the sectoral pattern of electricity consumption in Punjab yields an average upper limit of Rs 2.74 per kwh. To estimate the consumer surplus, it is assumed that to avail of additional power, consumers will be willing to pay a premium equivalent to about 50% of the difference between the cost of substitutes and existing tariffs; i.e., an average consumer surplus of Rs 1.09 per kWh. 24. The value of energy displacement of generation from less efficient thermal generation is expressed in terms of cost savings arising from the higher thermal efficiency derived from the operation of the new units compared to the existing units at GNDTP at Bhatinda. Investment Returns on State Program 25. Financial evaluation of the 5-year State Power Investment Program indicates that for as long as the ex.sting average tariff of Rs 0.70 per kWh prevails, the program will yield a negative financial return. The cost of incremental supply attributable to the program is Rs 0.92 per kWh sold, assuming zero interest rate of financing. Of this, Rs 0.785 per kWh is due to the generation component; Rs 0.087 per kWh is due to transmission, and Rs 0.05 per kWh due to distribution. If the program were to yield sufficient financial margins to service funds at say, 12% interest, the tariff would have to be set to at least Rs 1.41 per kWh. The OFAP mutually agreed to between PSEB and PFC will address deficiencies in PSEB's financial operations, and if successfully implemented will improve the financial returns to PSEB's investment program. 26. In contrast, the economic internal rate of return (EIRR) of the State Power Expansion Program is 2i6, yielding a net present value (NPV) at 12% of Rs 12,634 million. Benefits considered include the consumer surplus associated with incremental electricity sales. If consumer surplus were excluded, the EIRR would be negative given that tariffs continue to be set below the marginal cost of supply. - Ii.s - Annex 5.1 Page -' of 19 27. Sensitivity analyses under conditions of reduced electricity sales, project cost overruns and delayed commissioning result in the following indicators of economic returns: Table 3: Results of Sensitivity Analyses of the State Prozram EIRR NPV at 12% (V) (Rs million) Base case 26 12,634 Benefits less 20% 18 5,772 Costs over 20% 20 8,468 Benefits less 20% and costs over 20% 13 1,438 One year delay in commissioning 20 8,903 28. Even under adverse variations in benefit and cost levels, the State investment program is expected to yield more than the target minimum economic rate of return of 12%. Nevertheless, prudent control of program expenditures will have to be exercised together with efficient operation of proposed system facilities to ensure that the program's service targets are fully met and benefits maximized. Average Incremental Cost (AIC) of Power SuDPlY 29. As a measure of the long run marginal cost (LRMC) of el :tricity in the State of Punjab, the average incremental cost (AIC) of supply at the levels of generation, transmission and distribution were derived based on the costs associated with the State's Power Investment Program. The resulting AIC estimates per kWh sold, at the discount rate of 12%, are: Rs 0.81 per kWh at the generation level, Rs 0.162 per kWh at transmission, and Rs 0.09 per kWh at distribution. The total AIC per kWh sold comes to Rs 1.062 per kWh compared to the value of electricity based on an estimate of consumers' "willingness to pay" of Rs 1.65 per kWh. Northern Region ExRansion Program Analysis 2/ 30. PSEB's proposed transmission projects have been sanctioned by CEA as consistent with the overall power development plan for the Northern Rlegion Power Grid. In addition to Punjab, the regional plan is based on the power requirements of the States of Himachal Pradesh, Jammu and Kashmir, Rajasthan, Uttar Pradesh, and the union territories of Chandigarh and Delhi. / This discussion is based on the regional program analysis undertaken in connection with the Northern Region Transmission Project. The calculations were adjusted with respect to: (a) consideration of 0 and M expenses starting only in 1996/97; and (b) exclusion of projected increases in tariff level to match the constant tariff assumption used in the evaluation of the State program and of the individual sub- projects. - 11S - Page 8 of 19 31. Peak load served by the grid has expanded at an annual average rate of 13.2% from 5,694 MW in 1981/82 to 11,991 MW in 1987/88. Energy deliveries grew at an average of 10.1% per annum, 'rom 30,035 GWh to 53,566 GWh over the same period. However, regional grid supply has been unable to keep pace with the growth in demand. It is estimated that in 1987/88, the peaking capacity deficit was 3,276 MW or 27% of peak demand, and the energy supply shortfall was 6,155 GWh equivalent to 10% of total requirement. Over the coming years, CEA projects that system peak load and energy demand in the region wouid grow at about 9.8% a year to reach 36,646 MW and 182,239 GWh by year 2000. Capacity and energy supply deficits (in the order of 6000 MW and 13,600 GWh, respectively) will continue to be a problem despite the programmed expansion in powez infrastructure. 32. The current (1989/90) pattern of electricity consumption in the Northern Region is characterized by 42% industrial use, 28% agricultural, 16% domestic, 9.6% commercial, and the balance due to public utilities. By year 2000, it is projected that industry and agriculture will retain their relative ranks, with modest gains in the share of domestic and commercial sectors expected. Regional Program Costs 33. Among the expenses and operating parameters considered in the estimation of the costs associated with the Northern Region power program for the time-slice 1989/90 to 1999/2000 are the following: (a) Economic value of investments in generation plants are projected to involve over Rs 200 billion. Capital costs of transmission and distribution facilities are estimated to be in the range of 60% of generation investments; (b) Incremental operating and maintenance costs are assumed proportional to the capacity costs of the respective facilities; i.e., at 2.5% for thermal plants, 1.1% for hydroplants, 1.0% for transmission and distribution; (c) System losses are projected to decline from the current 22% to 15% by 1996/97. Plant station use is assumed at 10% for thermal stations and 1% for hydroplants; and (d) Fuel costs are based on fuel consumption rates of 0.61 kg. of coal per kWh and 10 ml of oil per kWh. Average cost of coal supply is Rs 237 per tonne, assuming 50% of thermal stations are located at the pithead, and 50% near load centers. Economic price of fuel oil is assumed at Rs 2.7 per liter. 34. The economic costs applied excludes all forms of taxes and duties, and includes adjustment of local costs by the 0.8 standard conversion factor. - 116 - Annex 5.1 Page 9 of 19 Program Benefits 35. Benefits derived from the regional expansion program and their valuation are similar to those resulting from the State program. Existing average tariff in the region is Rs 0.67 per kWh, or after applying the 0.8 SCP, it is equivalent to the lower limit of consumers' willingness to pay of Rs 0.53 per kWh. The consumer surplus is estimated at Rs 1.10 per kWh, yielding an average value of electricity service of Rs 1.63 per kWh. Program Returns 36. Assuming benefits reflect consumer surplus, the derived economic rate of return for the program is 15%, or yielding a net present value of Rs 51.400 million at the 12% hurdle rate. If consumer surplus were excluded, the EIRR would be 0.6%. Transmission Project Analysis 37. PSEB's proposed 220 kV transmission project involves two major categories of works under which CEA clearances have been obtained, namely: (a) evacuation and dispersal of power from generation stations, and (b) system revamp and upgrading. 38. Specifically, the project calls for the completion of transmission lines associated with the Ropar Thermal Plant (RTP) Stage II, installation of new 220 kV routes in conjunction with the commissioning of RTP Stage III, establishment of a tie-line between the existing (Stage II) and forthcoming (Stage III) at GNDTP, and 220kV access to the south-eastern region of Punjab by connecting GNDTP Stage III to Sunam via Mansa. The system revamp component will involve voltage upgradin-, relieve ove-..;.. 4ng of existing circuits, provide 220 kV service to the Jallalabad loa, cer:er, as well as facilitate efficient dispersal of power from the Bhakra r,_-o complex. 39. The transmission activities will involve eight line segments of which three are associated with RTP power evacuationi, two with GNDTP and the rest involving general system improvement. Proposed substation expansion calls for additional transformer capacity totalling 600 MVA compo3ed of the following: Table 4: Proposed Substation Transformer Expansion Location Cagacity & Voltage Associated with: Jalandhar lxlOOMVA 220/66kV RTP III Khanna 2xlOOMVA 220/66kV RTP III Sunam lxlOOMVA 220/66kV GNDTP III Jallalabad lxlOOMVA 220/66kV System Revamp Mahilpur lxlOOMVA 220/132kV System Revamp - 117 - Annex 5.1 Page 10 of 19 40. The transmission project will involve Rs 970 million capital outlay over the period 1992 and 1994, representing 18% of PSEB's aggregate transmission expansion program for the coming 5 years. In addition to ensuring that the proposed set of transmission schemes is consistent with the system expansion plan for the Northern Region and for the State, the transmission project was analyzed an to its net benefit and investment return. 41. The initial approach was to view the project from its operational objectives and to gauge the deleterious effects on PSEB's system operation if the proposed schemes were not pursued. Load flow studies at system peak demand were provided by PSEB both with and without the new lines for selected years. An analysis of these load fliws indicate that as early as 1992/93, the absence of the proposed lines for evacuating power from the Ropar Thermal Station (RTP) will cause an overloading in the existing circuits, namely, RTP- Lalton Kalan (LTKL) and RTP-Gobindgarh, during maximum thermal conditions which would result in load curtailment of at least 150 WW during peak hours. Moreover, even with the shedding of the 150 MW load, the probability of outage incidence under both maximum thermal and maximum hydro conditions is increased due to heavier circuit loading. Transmission expansion in RTP's service area represent at least 50% of the incremental sales served by the project. 42. A second set of benefits is derived from the operation of the lines associated with the commissioning of the GNDTP III at Bhatinda and erection of the Mukatsar-Jallalabad line. Based on the load flow configuration of 1994/95, the proposed circuits in the Bhatinda service area are expected to carry a combined peak load of about 190 MW from the GNDTP station during maximum thermal production of which at least 60% represents incremental load. Part of this incremental demand is attributable to the load growth in Sunam and Jallalabad estimated to reach 87 MW and 105 MW by 1994/95. 43. A third set of benefits is the reduction in overall system loss estimated at 37 MW resulting from the implementation of the proposed system revamp. 44. In addition to the capital and associated operating and maintenance costs of the project, the incremental capacity and operating costs of generation and distribution based on the AIC estimates derived from the State program are considered. Incremental sales from the increased plant generation permitted by the project are valued in terms of consumers' willingness to pay. Savings due to prevented load curtailment, reduced outage risks, and reduced system losses are likewise expressed in terms of improved levels of energy delivery. 45. The resulting economic rate of return (EIRR) is 87% for the transmission package and its net present value (NPV) at the discount rate of 12% is Rs 5.568 million. The high economic return reflects the critical nature and urgent need for the lines, as their absence would create a system bottleneck in the delivery of additional power available from the thermal plants and will hinder improvement of existing electricity service in the State. On the other hand, the financial rate of return is negative since tariff is set below financial cost of supply. - 118 - Annex 5.1 Page 11 of 19 Alternative ARproach 46. In order to assess the relative contribution of each of the eight line segments comprising the proposed transmission package, and thus facilitate investment decision in case funding limitation requires PFC to rank and prioritize sub-projects, an alternative estimation approach was pursued. It was assumed that since the package accounts for 20% of the transmission investme.nts in the State over the next 5 years, additional PSEB transmission capacity equivalent to a year's expansion is attributable to the package. Accordingly, it is assumed that the eight lines will service a one-year increment in system sales and this service level is taken to remain constant over the operating life of the lines. The proportion of incremental sales attributable to each line is assigned based on the relative magnitude of the load that is expected to flow through the line; i.e., proportional to the ratio of peak load flowing on the individual circuit to the sum of peak load serviced by all the project lines. In addition, the reduction in transmission losses resulting from installation of each circuit were also identified. 47. The estimated average peak loading and loss reduction for each component are given in Table 5. Table 5: Avgraee Peak Load Flow and Loss Reduction (in MW) Sub-Project Peak Flow Loss Reduction 1. RTP-RAJPURA-PATIAIA 119 2.3 2. RTP-JALANDHAR 225 21.4 3. RTP-GOBINDGARH 324 5.6 4. GNDTP-MIJKATSAR 150 1.7 5. GNDTP-MANSA-SUNAM 150 2.0 6. MUKATSAR-JALLALABAD 80 1.4 7. MOGA-MUKATSAR 100 0.9 8. BHAKRA-MAHILPUR 204 15.0 48. Expectedly, the resulting financiel returns for all the transmission components are negative reflecting the low level of tariff relative to the cost of production. However, the economic rate of return (inclusive of benefits due to consumer surplus) consistently exceed the hurdle rate of 12%. - 119 - Annex 5.1 Page 12 of 19 Table 6: Net Present Values and Economic Rates of Return of Pronosed Transmission Lines Sub Project NPV at 12% (Rs million) EIRR ( L ) 1. RTP-RAJPURA-PATIAIA 343 107 2. RTP-JALANDHAR 861 112 3. RTP-GOBINDGARH 910 119 4. GNDTP-MUKATSAR 420 115 5. GNDTP-MANSA-SUNAI 353 59 6. MUKATSAR-JALLAIABAD 150 31 7. MOGA-MUKATSAR 273 128 8. BHAKRA-MAHILPUR 720 90 49. If the cost and benefit flows derived for each of the project lines were consolidated, the resulting EIRR for the transmission package is 90j. The return is slightly higher than the j1 return obtained under the first approach due to the deferred timing of circuit loadings in the Bhatinda area assumed under the first approach as well as the lower level of system loss reduction considered. I/ Both approaches reflect similar findings on the relative economic contribution of each of the transmission components. 50. Since detailed load flow simulations (under different generation mix conditions and for several operating years) necessary for analysis under the first approach are not readily available as it requires detailed computer simulations, it has been agreed that in the interim, the second method will be used by PFC in evaluating all the other transmission proposals submitted by the various SEBs. In addition to facilitating the evaluation of multiple- line proposals, the approach is able to reflect the salient operational characteristics of each scheme and provides an adequate estimation of the economics of the transmission projecc. Further, since the power sector in India is experiencing major capacity shortfalls, it can be assumed that the new transmission lines will fully absorb incremental demand upon line commissioning. _/ 1/ From an overall system perspective, the effective reduction in losses derived from the package is 38 MW, while linear addition of loss reduction per transmission segment yields an overestimated system loss reduction of 50 MW. I/ In practice, the proposed lines will likely service part of existing loads during initial years of operation, but will eventually carry higher loads as it absorbs more '.ncremental demand over the years. The potential overestimation of benefits in initial years is offset by the conservative assumption of constant line loading through the project life. - 120 - Annex 5.1 Page 13 of 19 Distribution Project Analysis 51. The proposed urban distribution projects in seven towns in Punjab involve a total investment outlay of about Rs 276 million over a four-year period from 1990/91 to 1993/94. Each distribution project is treated as a discrete project and is individually appraised as to its economic viability. 52. In addition to the iirect capital costs and operating and maintenance expenses associated with each distribution scheme, the AIC of generation and transmission are applied on the incremental supply assumed to flow through the proposed distribution facilities so as to arrive at the full cost of power delivery. 53. Two set; of benefits were identified namely, (a) incremental sales in the urban area served by the network expansion, and (b) reduction in distribution losses. To arrive at the estimated level of incremental sales, the annual load connections and load flows per major feeder and transformer "with and without" the proposed improvements for the forecast period 1989/90 to 1994/95 were analyzed. In calculating the loss reduction attributable to the projects, three sets of losses were considered; i.e., energy losses per feeder line losses, distribution transformer losses and power transformer losses. A summary of the resulting benefits expressed in equivalent incremental energy sales is given in Table 7. Table 7: Benefits from PSEB's Proposed Urban Distribution Projects Additional Energy Loss Towns Sales Reduction (GWh) (GWh) 1. Faridkot 4.76 6.23 2. Jalandhar 52.44 3.53 3. Hoshiarpur 12.76 2.59 4. Phagwara 12.31 3.03 5. Patiala 67.42 3.58 6. Khanna 86.35 13.02 7. Bhatinda 27.03 3.33 Total 263.07 36.31 54. Except for the investments in Faridkot City, the financial rates of return derived for the distribution projects are negative due to low tariff levels. In contrast, their economic rates of return exceed the 12% hurdle rate confirming the projects' economic viability. The estimated net present values (NPVs) and EIRRs of the distribution schemes are summarized in Table 8. - 121 - Annex 5.1 Page 14 of 19 Table 8: Net Present Values and Economic Returns of PSEB's Urban Distribution Projects Project Area NPV at 12% EIRR (Rs Millions) (%) 1. Faridkot 14 21 2. Jalandhar 129 34 3. Hoshiarpur 36 39 4. Phagwara 45 56 5. Patiala 227 72 6. Khanna 309 80 7. Bhatinda 73 38 Sensitivity Analysis 55. Sensitivity analyses carried out under conditions of adverse variations in cost and benefits indicate that satisfactory economic returns for both the transmission and distribution sets of sub-projects are maintained. Sensitivity tests using higher AIC values were also performed inasmuch as project returns were based on average incremental cost (AIC) estimates developed under the discount rate of 12% and to the extent that the State's Power Expansion Program yields a return higher than 12%, additional return attributable to other program components have pai:tly been credited to the project. Accordingly, AIC estimates based on a 26% roturn for other investment components were used and the results show that all project schemes are still able to generate at least 12% rates of return as follows: Table 9. Sensitivity Tests Using Higher AIC Values Sub Project NPV at 12% (Rs million) EIRR ( % ) Transmission 1. RTP-RAJPURA-PATIALA 128 54 2. RTP-JALANDHAR 452 68 3. RTP-GOBINDGARH 322 53 4. GNDTP-MUKATSAR 148 56 5. GNDTP-MANSA-SUNAM 81 23 6. MUKATSAR-JALIALABAD 6 13 7. MOGA-MUKATSAR 92 55 8. BHAKRA-MAHILPUR 350 54 Distribution 1. Faridkot 3 14 2. Jalandhar 17 16 3. Hoshiarpur 6 18 4. Phagwara 15 29 5. Patiala 47 29 6. Khanna 82 36 7. Bhatinda 8 15 IIIDI POWER UTILITIES IflICIEICT INFROVYEENT PROJICT POIJAB State Poser Expansion Prograc Icomonic Aaalysia NPV at 12 1: BB 12634 Billion (In lupees Nillion) HRER 26 1 61111tiOlU tMISHISSIOU DISTRIBUTION Fiscal -------------------------------------------- ------------------- ------------------- TOTAL ADDITIONAL oE? Year INPORT CAPITlL FOEL EXPENSIS SOI- CAPITAL SUB- CAPITAL SUB- D2LIVIRY SALES TARIFF CONSONEB COST TOTAL ECOKOOIC Reding COSTS a/ COSTS COAL OIL OAR TOTAL COSTS OAU TOTAL COSTS 0A TOTAL COSTS GWh RIIENUIb/ SURPLOSc/ SAVINGS BENEFITS BElEFITS 1990 944 944 944 -944 1991 1720 1720 640 0 640 400 400 2760 -2760 1992 101 2000 175 25 53 2355 760 16 776 400 12 412 3543 712 399 776 23 1198 -2345 1993 119 2240 S05 72 93 3029 840 35 875 440 24 464 4368 1644 921 1792 31 2744 -1624 1994 119 1856 166 1O9 138 2988 1000 56 1056 480 37 517 4561 2514 1408 2740 31 4179 -382 1995 119 1784 1145 163 175 3386 1120 81 1201 600 52 652 5239 3537 1981 3855 It 5847 608 1996 119 1265 180 211 1175 109 109 70 TO 1953 3860 2162 4207 0 6369 4416 1997 119 1265 180 211 1775 109 109 70 70 1953 3860 2162 4207 0 6369 4416 1998 119 1265 180 211 1775 109 109 70 T0 1953 3860 2162 4207 0 6369 4416 1999 119 1265 180 211 1775 109 109 70 70 1953 3860 2162 4207 0 6369 4416 2000 119 1265 180 211 1775 109 109 70 70 1953 3860 2162 4207 0 6369 4416 until 2030 119 1265 180 211 1775 109 109 TO 70 1953 3860 2162 4207 0 6369 4416 a/ The average cost of pomer purchases is asuned at Is 0.44 per kWh. b/ The economic value of the average tariff is estimated at lo 0.56 per Hh. -U cl The consuaer surplus is eatiuted at s 1.09 per kWh. o ax Source: PHC and Bank estimates INDIA P0o1i DYILITIES IIFICIIIIC P 1BOVEIEIT PROJECT Northern Begiou EIpansion Progran Economic lAalysis 1pf A? 122 : 6 51,408 niliioD (in lapees Milliocl E188 15.2 2 Fiscal Capital Costs Operating 2tpenses lncreeental Benefits TTAL Year ------------------------------------------------------------------- TOTAL ----------------------------- -- 7OTAL 18t ending Tbereal lydro T?D Sub-Total Fuel 0&N Sub-total COSTS Sales Revenue Consqmer Surplos BEN1FITS BE1FITS al b/ cJ 1990 576.2 1390.2 1l66.4 1966.4 -1966.4 1s9l 2410.2 3917.2 6327.4 6321.4 -6327.4 1992 5923.6 7957.8 13881.4 13881.4 -13881.4 1993 1085l .0 140819.6 24946.6 24946.6 -24946.6 1994 15615.0 18533.7 12055.8 46204.5 46204.5 -46204.5 1995 18288.2 19322.5 18083.7 55694.3 55694.3 -55694.3 1996 17260.9 16661.3 18083.? 52005.9 52005.9 -52005.9 1997 13668.4 11288.0 24111.6 49068.0 445.8 1025.4 1471.2 50539.3 5567.0 2950.5 6123.7 9074.2 -41465.0 1998 9057.8 5434.7 24111.6 38604.1 2087.3 2262.9 4350.2 42954.4 12439.4 6592.9 13683.3 20276.2 -22678.2 1999 46817.3 1936.9 12055.8 18680.0 5157.9 3503.6 8661.5 27341.6 23824.1 12626.8 26206.5 38833.3 11491.8 2600 1417.5 576.3 12055.8 14109.6 91497.9 3667.6 13165.5 27275.2 40956.2 21706.8 45051.8 66758.5 3U483.4 2001 9497.9 4843.7 14341.6 14341.6 57275.5 30356.0 63003.1 93359.1 79011.5 2002 9497.9 4843.7 14341.6 14341.6 57275.5 30356.0 63003.1 93359.1 79011.5 until 2021 8497.9 4843.7 14341.6 14341.6 57275.5 30356.0 63003.1 93359.1 19017.5 a/ AJ suses 302 hyAroplant nitilizatioa nd progressive reduction of TAD losses fron the 222 in 1989/90 to 15 in 1999/2000. hi Eaud ao prevailing economic tariff level of is 0.53 per k h c/ Consumer rplus estimated at is 1.10 per kiI. Source: laek and CIA estimates o INDIA PONIR OTILIItS IFFICIKICY rRPBOv?IIil PROJECt Punjab SIR Transaission Project economic Analysis as a Single Project NP! at 12% Re 5568 million 21PB: 812 t o is BBillions I fiscal TBlaSlISSiO3 COSTS TOTIL IDCORIINTAL NiT Tear --------------------------- GEIRR&TIO DISTIBIUTION DILIVRY SALIS TARIFF CONSOMER COST TOTAL ECOlOMIC Ending Capital OAl Sub-Total COSTS al COSTS b/ COStS cob BRI2U0 c SORPLOSd/ SAVINGS BUNlFITS 0EIIFITS 1990 0 0 0 0 1991 0 0 0 0 1992 278 278 278 0 -278 1993 349 341 349 0 -349 1991 202 7 209 660 73 143 815 456 888 81 1426 483 1995 22 22 95? 108 1085 1182 662 1208 121 2071 986 I99 22 22 957 106 1085 1182 662 1288 121 2071 906 199? 22 22 951 106 1085 1182 662 1288 121 2071 986 1998 22 22 95? 106 1085 1182 662 1288 121 2071 986 1999 22 22 957 106 1085 1182 662 1288 121 2071 986 2000 22 22 957 106 1085 1182 662 1288 121 2071 986 until 2030 22 22 957 106 1085 1182 662 1288 121 2071 986 a/ The average lncrenental cost of (AIC) of generation is estiaated at BI 0.81 per Whl based on Punjab SIBOs poser expansion program. g X Ix bl The AIC of distributioo is eutinated at go 0.09 per ilk. 4 c/ The econoate value of the tariff is astumed at the prevailing rate of Be 0.56 per lhU. < LJu d/ The consuaer surplus is estimated at Be 1.09 per kUh. 11018 P0o11 OTILITIES IffICIKiCT IIPIOTVKl0T PROJICT Punjab SID Transnissiou Project economic inalysis by Line Component 'YP-UAJPDUA-PAI ULA LIII hPY at 12. iB 343 Billion (in Rupees Billion) 1121 10: I fiscal ADDITIOIAL Gi6l- tRlliSISSIOI 1PIIISI TOTAL ADDITIONAL piT year G6itRUTIOl 61TIO1 DISTRIBOTIOl DILIVO!9 SAlES TARIFF CONSUMER COST tOT&L ICONONIC lnding c6b COSTS a/ Capital 0A1 7otal COSTS h/ COSTS Gib REVIKIIc/ SURI,LOS6d SaIIUCS B1111ItS BENEFITS 1990.0 1991.0 1992.0 21.0 21.0 21.0 -21.0 1993.0 21.0 21.0 21.0 -21.0 1994.0 115 71.3 4.7 1.0 5.7 7.9 85.0 88 49.3 96.0 6.9 152.1 67.2 1995.0 115 71.3 1.2 1.2 7.9 80.4 88 49.3 96.0 6.9 152.1 71.7 1916.0 115 71.3 1.2 1.2 7.9 80.4 88 49.3 96.0 6.9 152.1 71.7 1Ig7.0 115 71.3 1.2 1.2 7.9 80.4 88 49.3 96.0 6.9 152.1 711. 1998.0 115 71.3 1.2 1.2 7.9 80.4 88 49.3 96.0 6.9 152.1 71.7 1999.0 115 71.3 1.2 1.2 7.9 80.4 88 49.3 96.0 6.9 152.1 71.7 2I00.0 115 71.3 1.2 1.2 7.9 80.4 88 49.3 96.0 6.9 152.1 71.7 until 2030.0 115 71.3 1.2 1.2 7.9 80.4 88 49.3 96.0 6.9 152.1 71.7 al Thb aen ge iocreneutal cost (AIC) of eneratiom Is estioated at Is 0.81 per kgb based on Punjab SIB's pover expansion program. | bI The UIC of distribution is estimated at Ba 0.09 per k0h. - X c/ The economic value of prevailing tariff i6 asmuned at is 0.56 per NbI. Go 4 LO dJ The cosu er surplus is estimated at 3m 1.09 per hUh. 0 Source: PVC and Bank estimates INDIA PONER OTILITIES IFFICIENCT [FPPOVIENNT PBOJICT Puajab Sti Distribution Project Economic Analysis FARID5OT CITY NPV at 12S Rs 14 million (In Rupees Billion) FIER 21.1 t flscal ADDITIODUL 6EN1- TEU,S- DISTRIBUTION EZP1SIS TOTAL ADDITIONAL NIT Year GENERTIION RATION NISSION ---------------------------- DELIVERY SALES TARIFF CONSUMER COST TOTAL [COOMOIC lading Guh COSTS a/ COSTS b/ Capital 041 Total COSTS GWh RIVENUIc/ SORPLUSd/ SAVINGS BENEFITS BENEFiTS 1990 0.00 0.00 0.00 1991 3.11 3.11 3.11 0.00 -3.11 1992 2.02 1.25 0.25 8.29 0.26 8.55 10.05 1.54 0.95 1.65 2.60 -7.45 1993 2.48 1.53 0.31 8.29 0.26 8.55 10.39 1.89 1.16 2.02 3.19 -7.20 1994 2.97 1.84 0.37 1.04 0.50 1.53 3.74 2.27 1.40 2.43 1.42 5.24 1.50 1995 3.50 2.16 0.43 1.04 0.50 1.53 4.13 2.67 1.65 2.86 1.68 6.19 2.06 1996 4.07 2.52 0.50 0.50 0.50 3.52 3.11 1.92 3.33 1.96 7.20 3.68 1997 4.69 2.90 0.58 0.50 0.50 3.98 3.59 2.21 3.84 2.36 8.40 4.42 116 5.24 3.24 0.65 0.50 0.50 4.39 4.00 2.47 4.28 2.18 9.53 5.14 1999 5.91 3.60 0.72 0.50 0.50 4.81 4.44 2.74 4.75 3.27 10.76 5.94 2000 6.23 3.86 0.7? 0.50 0.50 5.12 4.76 2.93 5.09 3.84 11.86 6.74 matil 2030 6.23 3.86 0.71 0.50 0.50 5.12 4.76 2.93 5.09 3.84 11.86 6.14 al Average incremental cost (AICI of generation is estimated at Ra 0.81 per kNh sold based on Punjab SIR's power ezpansion program. b/ lIC of transeission is estimated at Rs 0.16 per kib sold. c/ ecomomic value of prevailiag tariff ts assnued at Is 0.62 per klh sold. - t x d/ Conssuer surplus is estimated at Bs 1.01 per kth sold. Source PIC nd Bank estimatee - 127 - Annex 6.1 INDIA POWER UTILITIES EFFICIENCY IMPROVEMENT PROJECT Documents in Project File 1. Punjab State Electricity Board, Sub-project Appraisal Report; PFC: June 1991. 2. Andhra Pradesh State Electricity Board, Sub-project Appraisal Report; PFC: June 1991. 3. Madhya Pradesh State Electricity Board, Sub-project Appraisal Report; PFC: June 1991. 4. Gujarat State Electricity Board, Sub-project Appraisal Report; PFC: June 1991. 5. PFC's Operational Policy Statement; PFC: November 1990.
Группа Всемирного банка · Staff Appraisal Report
India - Power Utilities Efficiency Improvement Project
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