Document of The World Bank

FOR OFFICIAL USE ONLY

Report No: 30269

IMPLEMENTATION COMPLETION REPORT(TF-20006 CPL-40140 SCL-4014A)

ON A

LOAN

IN THE AMOUNT OF US$350.0 MILLION

TO THE

GOVERNMENT OF INDIA

FOR AN

ORISSA POWER SECTOR RESTRUCTURING PROJECT

December 9, 2004

Energy and Infrastructure Sector UnitSouth 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.

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CURRENCY EQUIVALENTS

(Exchange Rate Effective June 30, 2004)

Currency Unit = Rupee (Rs) Rs 1.00 = US$ 0.02US$ 1.00 = Rs 45.93

FISCAL YEARApril 1 - March 31

Measures and Equivalents

1 kilovolt (kV) = 1,000 volts1 kilovolt-ampere (kVA) = 1,000 volts-amperes

1 megawatt (MW) = 1,000 kilowatts = 1 million watts1 kilowatt-hour (kWh) = 1,000 watt-hours

1 megawatt-hour (MWh) = 1,000 kilowatt-hours 1 gigawatt-hour (GWh) = 1,000,000 kilowatt-hours

ABBREVIATIONS AND ACRONYMS

AES − AES Transpower IncorporationBSES − Bombay Suburban Electricity SupplyCAS − Country Assistance StrategyCESC − Calcutta Electric Supply CorporationDSM − Demand-Side ManagementERR − Economic Rate of ReturnGOI − Government of IndiaGOO − Government of OrissaGRIDCO − Grid Corporation of OrissaHSE − Health, Safety and EnvironmentNTPC − National Thermal Power CorporationOERC − Orissa Electricity Regulatory CommissionOHPC − Orissa Hydro Power CorporationOPGC − Orissa Power Generation CorporationOSEB − Orissa State Electricity BoardPLF − Power Load FactorSAR − Staff Appraisal ReportSCF − Standard Conversion FactorWTP − Willingness-to-Pay

Vice President: Praful C. PatelCountry Director Michael F. CarterSector Manager Penelope J. Brook

Task Team Leader/ICR Task Team Leader: Judith K. Plummer/Alan F. Townsend

INDIAOrissa Power Sector Restructuring Project

CONTENTS

Page No.1. Project Data 12. Principal Performance Ratings 13. Assessment of Development Objective and Design, and of Quality at Entry 24. Achievement of Objective and Outputs 45. Major Factors Affecting Implementation and Outcome 116. Sustainability 127. Bank and Borrower Performance 148. Lessons Learned 169. Partner Comments 1810. Additional Information 18Annex 1. Key Performance Indicators/Log Frame Matrix 19Annex 2. Project Costs and Financing 20Annex 3. Economic Costs and Benefits 22Annex 4. Bank Inputs 31Annex 5. Ratings for Achievement of Objectives/Outputs of Components 36Annex 6. Ratings of Bank and Borrower Performance 37Annex 7. List of Supporting Documents 38Annex 8. Map IBRD 26751 39Annex 9. Financial Performance 40

Project ID: P035170 Project Name: Orissa Power Sector Restructuring Project

Team Leader: Judith K. Plummer TL Unit: SASEIICR Type: Core ICR Report Date: December 29, 2004

1. Project DataName: Orissa Power Sector Restructuring Project L/C/TF Number: TF-20006; CPL-40140;

SCL-4014ACountry/Department: INDIA Region: South Asia Regional

Office

Sector/subsector: Power (99%); Sub-national government administration (1%)Theme: Regulation and competition policy (P); Pollution management and

environmental health (P); Other financial and private sector development (P); Climate change (S); State enterprise/bank restructuring and privatization (S)

KEY DATES Original Revised/ActualPCD: 06/06/1994 Effective: 09/24/1996 09/24/1996

Appraisal: 00/00/0000 MTR: 05/14/1999 05/14/1999Approval: 05/14/1996 Closing: 12/31/2002 06/30/2004

Borrower/Implementing Agency: GOVERNMENT OF INDIA/GOVERNMENT OF ORISSAOther Partners:

STAFF Current At AppraisalVice President: Praful C. Patel D. Joseph WoodCountry Director: Michael F. Carter Heinz VerginSector Manager: Penelope J. Brook Jean-Francois BauerTeam Leader at ICR: Judith K. Plummer Kari J. NymanICR Primary Author: Alan Townsend

2. Principal Performance Ratings

(HS=Highly Satisfactory, S=Satisfactory, U=Unsatisfactory, HL=Highly Likely, L=Likely, UN=Unlikely, HUN=Highly Unlikely, HU=Highly Unsatisfactory, H=High, SU=Substantial, M=Modest, N=Negligible)

Outcome: U

Sustainability: UN

Institutional Development Impact: M

Bank Performance: U

Borrower Performance: U

QAG (if available) ICRQuality at Entry: S

Project at Risk at Any Time: Yes

* The loan was suspended from July 9, 2001 until January 23, 2002.

The Orissa Power Sector Restructuring Project was a complex and challenging project. Orissa became the first state in India to launch an ambitious reform program based on unbundling, partial privatization, and implementation of a new regulatory framework. This approach, in modified form, was subsequently followed in several other major Indian states. But in Orissa itself, restructuring and reform remained a work-in-progress by the end of the project. The sector was unbundled, major components of distribution and generation were privatized, and a regulatory agency was established. Service quality has improved. But one private distribution company (CESCO) had had its license suspended, and was under state administration. More critically, financial and operational issues continue to plague the sector. Even with some progress in reducing losses and improving collections over the course of the eight years of the project, distribution companies lose about one of every two units of power they buy in bulk, either through technical loss, theft, or non-collection of bills. Debt has increased and cannot be serviced, but even so retail tariffs have not been adjusted in nearly four years; this situation is aggravated by the fact that some of the investments financed by the loan have not come into service yet and may remain unproductive investments for some time. Orissa is at a crossroads: the state has benefited significantly, compared to the alternative of no reform, but even so the power sector requires a massive financial overhaul so that the achievements of the project can be saved and built upon. It is for this reason, primarily, that at this time (December 2004) the overall outcomes of the project are rated as "unsatisfactory." With a financial recovery plan in place and under implementation, a more positive assessment of the project would almost certainly be merited. Without such a plan, the positive impacts of the project in Orissa may well prove to be unsustainable.3. Assessment of Development Objective and Design, and of Quality at Entry

3.1 Original Objective:

The objectives of the project were to: 1) implement a program of regulatory, institutional and tariff reforms in Orissa's power sector; 2) support the institutional development of the Orissa Electricity Regulatory Commission, the Grid Corporation of Orissa (GRIDCO) and the Orissa Hydro Power Corporation (OHPC); 3) reinforce and rehabilitate Orissa's power system and its demand side management to make power supply and consumption more efficient; and 4) upgrade the environmental performance of the power sector, and strengthen the environmental management capabilities of the power utilities. The project was intended to address comprehensively the challenges of power sector development in the state. Restructuring and unbundling would be supported through a major program of institutional strengthening, reinforced by new forms of commercial relationships and regulatory disciplines. Meanwhile, significant investment in rehabilitating and expanding the transmission and distribution network would deliver better service to customers and enable expected load growth, especially among industrial customers, to be met. Demand-side and environmental management strengthening were to be integral parts of the program.

3.1.1 Assessment: The Project Development Objectives were highly relevant in the Orissa context at that time. In 1993, the Orissa State Electricity Board (OSEB) was the worst performing SEB of any major state, blackouts and brownouts were common, and only about 20% of the households in the state were connected to the grid. The power sector was a major fiscal

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burden on the state, and inefficiency, losses, and corruption were endemic. The PDOs were in line with Bank strategy in the power sector. Orissa became the first Indian state to embrace what was then a new, and bold, power sector restructuring model for India. OSEB would undergo a comprehensive vertical and horizontal restructuring, leading to private participation in distribution and generation, the eventual introduction of competition first in bulk power and eventually in retail supply services, and establishment of a new, independent agency to regulate the sector. Orissa’s lead was followed by the embrace of this model in other major Indian states including Haryana, Uttar Pradesh, Andhra Pradesh, and Rajasthan. State-level power sector interventions were an essential component of the Bank’s country assistance strategy (CAS) at the time, and states that stepped forward for power sector assistance were generally states in which the Bank had broader assistance programs. Orissa was no exception, where the Bank was and is active in power, water, roads, health, and education. Orissa also has obtained a state adjustment loan in FY05.

3.1.2 The project was recognized as high risk from the beginning. Orissa was a very challenging state in which to engage in major power sector reform. Its population was then and is now only about half as rich as the all-India average, its economy relatively dependent on heavy industry, and it had a long history of governance issues. Complicating matters further was the fact that power sector restructuring in India in the early 1990s was a trip into uncharted waters – it had never been done at the state level, and the central level was unprepared to deal with, efficiently, the complex questions for which it had responsibility. As such, while the basic ingredients of the restructuring model were fairly simple – horizontal and vertical restructuring, privatization, competition, and regulatory reform were well established then as international best practice (and in fact, remain best practice today) – the state and national context in which the reform would be implemented was complex, challenging, and capacity-constrained.

3.2 Revised Objective:

Project objectives were not revised.

3.3 Original Components:

3.3.1 Reinforcing and Rehabilitating the Transmission and Distribution Systems and Developing Private Power Distribution (US$599 million, or 81% of the project’s $740-million base cost) – the project was designed to assist in rehabilitation of the network to reduce high losses, to enable the network to meet the demand for power, and to complement the reform objective of developing commercially viable, efficient utilities. Sub-projects covered 400, 220, and 132 kV transmission lines and substations; 33, 11, and 0.4 kV sub-transmission and distribution lines; and substations, capacitors, and non-technical loss reduction. This component also financed a portion of initial working capital, vehicles, transformer workshops, laboratory equipment, and other items, contributing to the institutional development of Gridco.

3.3.2 Demand-Side Management (US$97 million, 13% of base cost) – a mix of pricing reform, metering, and other load management and conservation strategies was to be funded. The metering program covered 13,600 meters for grid sub-stations and the largest customers, 27,500

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three phase meters for other large customers, and 600,000 single phase meters for small consumers.

3.3.3 Institutional Development, Training, and Technical Assistance (US$44 million, 6% of base cost) – this component encompassed technical assistance to help with project management, development of the regulatory commission, distribution privatization, new generation capacity procurement, competitive market evolution, Gridco and OPHC institution building, environmental and DSM management, and staff rationalization and training.

3.3.4 Assessment: The components were well-related to the PDOs but might have been better designed in their specific details. The 400 kV transmission investments should have been explicitly tied to the development of new generation capacity in the Ib Valley, to which they were to have been dedicated. Cancellation of this power plant project in 2001 has meant that the largest single Bank-financed investment in the project will not be used until at least 2008. The weak institutional capacity of OSEB might have argued for greater selectivity in sub-project selection – this is especially true of the non-metering parts of the DSM component. The inclusion of significant investment funds for loss reduction and meters was entirely appropriate. Also noteworthy was the substantial but appropriate allocation for technical and advisory assistance, which provided an adequate level of continuous support over a long period of time for a variety of activities (of which support for Gridco institution building, OERC development and operational support, and distribution transaction advice were the most important). In the event, thanks to significant support of this component by DFID, heavy demand for technical assistance was met to the tune of over $75-million over the course of the project. Finally, the project might have put less emphasis on the move to a competitive market in Orissa. The impossibility of implementing a competitive power market before basic prerequisites are in place is now well-recognized. Passage of the Electricity Act 2003 at the federal level now sets the stage for Orissa to manage better a staged transition to more competition, provided that further reform can be implemented to put the sector on a firm financial footing.

3.4 Revised Components:

There was no formal revision of components. Faster-than-expected privatization of distribution companies necessitated subsidiary loan agreements with the four discoms. Out of an initial loan of $350 million, a total of $95 million in financing for civil works, equipment and materials was cancelled, at Government of India and Orissa's request, in two tranches: $60 million effective October 10, 2001, and $35 million effective from February 18, 2003, since it was clear that the amounts could not be used before the loan closing date. The DSM component was most significantly reduced, with only about one third of the original $96-million target actually disbursed. Two extensions were granted, the first of 13 months until January 31, 2004, and the second of five months until June 30, 2004; these extensions were justified on the basis of maximizing the probability of achievement of the project’s development objectives.

3.5 Quality at Entry:

Satisfactory. Reform aspects in particular were very well prepared – the Orissa

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Electricity Reform Act had been enacted on January 10, 1996 and came into effect on April 1, 1996 – a major accomplishment, given that preparation work had only started in earnest in 1993. The Act created the Orissa Electricity Regulatory Commission (OERC) which by March 1997 had issued its first tariff ruling. The Act also created the successor agencies to the OSEB, including Grid Corporation of Orissa (Gridco, upon formation including transmission and distribution assets) and Orissa Hydropower Corporation (OHPC). Capacity at Gridco and in the State’s Department of Energy was severely constrained in the projects early years, leading to major delays in procurement and later problems in contract administration (especially payments to contractors). Here the quality at entry can be questioned, as the project team overestimated the implementation readiness of the investment and DSM programs. It is hard, though, to fault the project team for moving as rapidly as possible to corporate formation and learn-by-doing in the course of implementation. A final quality issue concerns the load forecast and whether or not this provided an adequate basis for programming the investment component. In hindsight, it is very clear that the load forecast was overly optimistic about demand growth, particularly from the industrial segment. As will be discussed in section 8 (Lessons Learned) some of the risks related to the load forecast might have been better mitigated.

4. Achievement of Objective and Outputs

4.1 Outcome/achievement of objective:

Unsatisfactory. The project has nominally achieved many of its development objectives; other than, notably, in the area of demand side management, and more critically with regard to tariff reform. The biggest single achievement of the project is that today, Orissa is the only state in India in which the power sector is a contributor to, rather than a drain on, the state budget. Since privatization of distribution, no direct subsidy has been paid to the sector. Sales of the Talcher and OPGC power plants, and of the stakes in the discoms, were worth about $250-million, over half of which went directly to the state budget. OPGC in particular has been a profitable holding (the state share is 51%) which has regularly paid dividends. However, the sustainability of this and other achievements is in significant doubt. The sector remains very weak financially despite improvements from the early 1990s. Net profits for the T&D sector as a whole have been negative for every year of the project (see Table 1). Earnings (before interest and depreciation) have been positive only in wet years, when Gridco is able to sell surplus power from its hydro purchase contracts with OHPC at a substantial profit. During drought years, as in FY2003, EBID and net profits for the sector are steeply negative. There may not be action on tariffs until next year, when a multi-year tariff may be implemented by OERC, meaning that – assuming tariffs are indeed increased – there will have been no increase in tariffs for over four years (the last retail tariff increase was in February 2001). Orissa needs a financeable recovery plan for the sector, but immediate prospects for such a plan are not good, despite discussions among the stakeholders that go back well over two years. This section assesses outcomes against objectives of the project.

Table 1: Financial Performance of thePower Sector (T&D only)

EBID Net ProfitFY Rs Billion Rs Billion

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1997 -0.96 -2.951998 -1.05 -3.191999 -2.29 -5.792000 -0.27 -5.242001 0.34 -5.832002 1.43 -5.242003 -3.89 -11.332004 5.25 -1.77

4.1.1 Objective 1: Implementing a program of regulatory, institutional and tariff reforms in Orissa's power sector. Unsatisfactory. While the overall outcome of the reform objective is disappointing, the assessment must be seen in light of progress on individual reform components.

4.1.2 On the institutional side, the project: a) unbundled the Orissa State Electricity Board, and corporatized the successor entities; b) created the Grid Corporation of Orissa (Gridco) and the Orissa Hydro Power Corporation (OHPC); c) created the Orissa Electricity Regulatory Commission (OERC); and d) introduced private sector participation, via 51% share sale, into four distribution companies that were spun off from Gridco. In steps related to the overall reform effort, Orissa also sold the Talcher Thermal Power Plant to the National Thermal Power Corporation; and sold a 49% stake (with management control) in the Orissa Power Generation Corporation (whose sole asset is a 420 MW coal-fired plant in the Ib Valley) to an independent power producer, AES of the United States. All of the above was accomplished by 1999. These are very significant accomplishments. Indeed, the sales of the distribution companies actually happened well ahead of plan because of the failure, in 1996-97, of an attempt to introduce private participation in the poorest performing distribution entity (the Central Zone) by management contract. The response of the Government, to accelerate distribution privatization, showed great flexibility and underscores the commitment of the Government at that time to the reform program. Performance on the institutional aspects of reform must be seen as marginally satisfactory, with only concerns about sustainability preventing a better assessment.

Table 2: Efficiency of the Energy Sector (%)

Financial Year2000 2001 2002 2003 2004

Collection efficiency 77 77 74 80 84

Transmission and distribution (T&D) loss 47 47 50 44 43

Aggregate technical & commercial (AT&C) loss

59 59 63 55 52

4.1.3 On regulatory and tariff aspects, outcomes are unsatisfactory. OERC, critically, never revised the 35% loss allowance that was essentially adopted from the World Bank's project preparatory work. This allowance has proven far too low, and letting losses in excess of that figure be booked as a regulatory asset for future recovery must be seen as an inadequate remedy. OERC development has also been affected by the two year period, beginning in 2000, when it did not have the full complement of commissioners. Since then, household tariffs have not been

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adjusted, despite the fragile financial condition of the sector. Discoms buy power from Gridco at around Rs 1.3/kWh to which they need to add their own distribution network costs. They are allowed to charge only Rs 1.4/kWh for the first 100 kWh per month of consumption to their domestic customers plus an amount for demand charge which brings the revenue to some Rs1.5 to 1.6/kWh (see the full statistics in Additional Annex 9). But half of all purchased power, on average among discoms, is either lost, stolen, or not paid for by customers. Sales to domestic consumers account for more than a third of total discom sales, and average consumption of the 1.8-million domestic customers is only about 110 kWh per month. So while other categories pay closer to cost recovery rates (and noting that Orissa is not burdened by heavy losses in supplying agricultural customers, who pay only Rs 1/kWh, but consume less than 2% of total discom sales), the discoms are absorbing huge losses in a core area of their business. GOO and OERC support to discoms in sustained anti-theft and disconnection programs has been uneven. It is true that private sector performance, particularly upon assuming control of the discoms in 1999, has been sub-par; but in light of the low tariffs and the lack of support for theft reduction, it is no surprise that discoms have been very reluctant to invest money to lower losses. As a result losses have remained high, with total losses (AT&C) at 52% in FY2004. OERC has been working to process orders on a multi-year tariff, open access, monitoring indicators, and other initiatives, but needs a more conducive policy environment in which to develop. The project has created a foundation that could yet deliver on the promise of fair and effective regulation in Orissa, but ultimately regulatory effectiveness in Orissa must be measured by sustained commitment to tariff levels and enforcement that allow distributors to achieve and maintain financial viability.

4.1.4 Objective 2: Supporting the institutional development of the Orissa Electricity Regulatory Commission, the Grid Corporation of Orissa (GRIDCO) and the Orissa Hydro Power Corporation (OHPC). Unsatisfactory. The project has been moderately successful in supporting the institutional development of the newly created operational and regulatory entities, but the achievements have fallen short of a satisfactory outcome. OERC, India’s first state-level power sector regulator, has three full-time commissioners and a staff of 20 professionals. From its establishment in 1996 and first tariff order in 1997, it had achieved a reasonable level of legitimacy with the difficult political economy of Orissa. But this progress was stymied when out-going commissioners were not speedily replaced. Tariff orders since then have not matched the boldness of earlier orders, and today wires companies are in effect being regulated on a cash-needs basis – barely able to meet operating costs, and unable to service debt (note that the generators such as OPGC are insulated from this danger by their energy sales agreements, which courts have shielded from attempted OERC intervention – although Gridco has not always paid OHPC and OPGC in full for purchased power). Gridco and OHPC have made major strides since being created out of the old Orissa State Electricity Board. OHPC is a focused organization that has effectively operated and maintained hydro assets. It successfully brought Upper Indravati into service. But it is exposed to significant regulatory risk, however, as demonstrated in 2001 when non-Indravati rates were cut in half, from 50 paise/kWh, to 25 paise/kWh, as a way of enabling discoms to increase margins without increasing household rates. Gridco has made some progress when compared to OSEB, but is not profitable in its core businesses of system operations, transmission, and bulk power supply to customers in Orissa. Gridco profit of Rs 3.8 billion in FY2004 was entirely due to extraordinarily high interstate sales of Rs 7.8 billion, a consequence of hydro availability in a wet year and the robust margins that it can get since the reduction in

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OHPC’s non-Indravati price. This price cut has also pushed OHPC into consistent losses since 2001 (though in 2004, thanks to high sales during that wet year, OHPC eked out a Rs 57 million profit).

4.1.5 Objective 3: Reinforcing and rehabilitating Orissa’s power system and its demand-side management to make power supply and consumption more efficient. Unsatisfactory. Power supply in the state has stabilized, compared to early and mid-1990s, due to a combination of factors: the industry is more efficient, though losses (not counting non-collections) are still at 43% and only 84% of bills are collected; a significant investment program has de-bottlenecked critical parts of the infrastructure; and expected load and bulk power supply did not materialize. But the distribution sector needs at least five years of solid performance improvement to get to a reasonable level of supply efficiency, and there is little evidence suggesting that consumption has become more efficient. By contrast, in generation there have been significant efficiency gains. Talcher, one of the worst performing coal plants in India under OSEB, went from a power load factor (PLF) of about 30% in the early 1990s to a steady 75% under NTPC management. OHPC brought the first two units of Upper Indravati into production in 1999 (with all four units now on-line) and it has since provided a significant portion of Orissa’s energy requirements at a cost of only Rs 0.64/kWh. OPGC’s operation of its 420 megawatt coal plant at Ib stands out as well – from a PLF of 36% in 1995 (with restrictions in coal mill availability), the plant has averaged an 80% PLF since 2000. OPGC has also been a regular payer of dividends to GOO, which owns 51% of OPGC equity; dividend payouts by OPGC to its shareholders have totaled over Rs 8.3 billion since 1997. In transmission, technical losses in transmission have fallen from 4.9% in 2000 (the first year of disaggregated data) to 3.9% last year, and reliability has improved. When asked the major reform achievements, the most common answer among stakeholders in Orissa is “24-hour power” – though Gridco has not quantified these gains and, in fact, power quality remains uneven in most rural areas. There is also the challenge of completing transmission sub-projects that were started with Bank financing, but not completed (600 km of lines, 7 substations, and 13 substation expansions were incomplete and not yet in service at the time of Bank project closing).

4.1.6 Objective 4: Upgrading the environmental performance of the power sector, and strengthening the environmental management capabilities of the power utilities. Unsatisfactory. Environmental management was not mainstreamed in Gridco or discom operations. There was some capacity built up in the PMU to implement and effectively monitor environmental management plans for sub-projects, during initial period of project supervision. However, this capacity was significantly eroded as the environment and social unit at the PMU was made defunct during the later phases of project implementation. Similarly, Gridco had initiated Health, Safety and Environment (HSE) audits of substations and transmission lines, but this too was discontinued by Gridco after August 2003.

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4.2 Outputs by components:

The overall rating is Unsatisfactory, based on the following assessments of the components:

4.2.1 Reinforcing and Rehabilitating the Transmission and Distribution Systems and Developing Private Power Distribution. Unsatisfactory. The component goal has only been partly achieved, and sustainability is in doubt. T&D infrastructure is more robust but many sub-projects remain incomplete; and the largest single investment, the Ib-Merramundali 400 kV transmission line and associated infrastructure, will not be used for at least four years. The system still suffers from persistent theft of power and equipment. Assessment is complicated by the large numbers of transmission sub-projects that will not be completed until mid-2005. On a more positive note, introduction of private companies into the distribution sector was an early achievement of the project. Total connections are up by 34% from 2000 (38% for domestic customers), to over 2.1 million. On average, over 100,000 domestic customers per year have been added for five years running. While industrial customer numbers have been flat over this period, commercial customer numbers have increased 27%, suggesting that power quality has indeed improved to the point where new companies, and old companies that were self-generating, are attracted to the network. But 3 of every 5 households still do not have a network electricity connection. And private distributor performance has been uneven in many areas, suffering a setback in 2001 when AES pulled out of CESCO. Only at the end of the project have BSES (now Reliance Energy) and, possibly, AES, seemingly re-committed themselves to these businesses, but the outcome of this re-commitment is uncertain. As with many aspects of the project, only time will tell if this objective is ultimately achieved; the foundation is there, but strong commitment will be necessary for the promise of the project to be realized.

4.2.2 Demand-Side Management. Unsatisfactory. This component was cut significantly to include only a metering program. In total (including both Bank-financed and non-Bank financed items) discoms have installed about 800,000 meters since 1999; most customers are now metered, though companies estimate that, in addition to the remaining unmetered customers, there are just under 300,000 old, defective meters in operation on customer premises. Better metering has contributed to the reduction in aggregate losses to 52%, but a greater impact was anticipated. It will be important to resolve remaining billing and collection issues as a whole for the full potential of the metering sub-component to be realized.

4.2.3 Institutional Development, Training, and Technical Assistance. Satisfactory. All transmission and distribution entities are sending personnel to the Gridco training center, financing of which was a key DFID contribution. Technical assistance has been implemented relatively smoothly, although knowledge transfer to the PMU from its consultants could have been better. In particular, Gridco had difficulty with supervision of construction contracts as evidenced by the lengthy delays suffered by many of the transmission sub-projects (some of which remain incomplete). Support to OERC was extensive and went well in the early parts of the project but OERC has now functioned without significant technical support for some years, which is undoubtedly a factor in its diminished effectiveness as a balancer of interests among various

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stakeholders.

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4.3 Net Present Value/Economic rate of return:

4.3.1 The baseline economic rate of return (ERR) of the T&D investment program is estimated at 13.5%, when benefits are measured using a willingness-to-pay (WTP) estimate of Rs 2.5/kWh. This includes the (so far unproductive) investment in the 400 kV Ib-Merramundali line. It also includes a conservative estimate of the economic benefits of pilferage (and/or defective metering); if this were excluded, the ERR falls to 11%. This estimate of economic returns is based on the investment program of the consolidated T&D business (i.e. the aggregation of Gridco and the discoms). At appraisal, the ERR for the Orissa power sector investment program was estimated at 14.4% (when benefits were measured at the tariff), and 16.8% when benefits were measured using WTP (changes in consumer surplus) as the measure of benefits. A sensitivity analysis in the SAR indicated robustness to the main uncertainties, with ERR in the range of 12.5% to 16.8%. No financial return was estimated in the Staff Appraisal Report (SAR).

4.3.2 Returns are negative when measured by the prevailing tariff. As shown in the figure, in real terms the average tariff (including interstate sales, which in FY2003 amounted to 31% of total GRIDCO sales) has decreased since FY97. While tariffs for domestic and commercial consumers were increased in FY2000 and FY2001, they have stayed unchanged since then. The result is a negative ERR. [Please see Annex 3 for a summary of the Economic Analysis.]

1.8

2

2.2

2.4

2.6

2.8

3

2.27 2.57 2.65 2.53 2.64 2.93 2.90 2.692.27 2.45 2.40 2.18 2.15 2.29 2.20 1.95

Nominal

Constant 96 Rs

Rs/k

Wh

FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04Nominal RsConstant 96Rs

4.3.3 Economic and financial returns are sensitive to the assumption used for Gridco interstate sales. In the analysis, it is assumed that Gridco averages Rs 1.8 billion in interstate sales revenue from FY2004 forward (this is the average for the period FY2000-03). Returns are lower if these sales are replaced by Orissa sales, because Orissa buyers pay about Rs 1.5/kWh compared to Rs 2.4/kWh in the interstate market, and because of the effect of losses and theft on power sold into the Orissa market. Interstate sales depend partly on availability of power for out-of-state sales, and on Gridco’s contractual right to that power. The latter will eventually change, given

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India-wide trends toward open access, but is dependent on distribution companies becoming credit-worthy buyers. Demand growth might well reduce availability for interstate sales in the near term, though, in all but wet years. Countering that trend would be loss reduction in Orissa – if it happens. Bringing aggregate losses down to 25% in five years, from 2004’s 52%, would produce high returns indeed, but loss reduction of that magnitude is unlikely without sector financial restructuring and a renewed public and private commitment to new investment.

4.4 Financial rate of return:

The financial rate of return is estimated by evaluating the incremental streams of financial costs and benefits attributable to the FY97-2003 time slice of the investment program. In the interest of making conservative assumptions, a two-year lag is assumed between the year of the investment outlay, and the year in which the incremental returns become available. Thus benefits of FY97 outlays are assumed only starting FY99, a conservative assumption for T&D investments. The FIRR calculates to 17% in constant Rs (see Annex 3 for details). This is an incremental calculation of benefits to an investment program, not a calculation of the average financial rate of return to equity (or to total assets). The T&D investments undertaken in the time-slice were generally to rehabilitate the weakest and most congested parts of the system at the start of the reform program, following years of neglect and lack of adequate T&D maintenance and investment. Since the benefits of the reform and restructuring program coincide with the investment time slice evaluated, the calculated financial returns include not just the benefits of the investment program per se, but also the benefits of the reform program. Finally, the average costs of purchased power are quite low (Rs 1-1.3/kWh) compared to the economic cost of power and therefore involve considerable subsidy (a large part of which is captured by pilferers). This subsidy therefore raises the financial returns in the T&D business (and is one of the main reasons why the economic returns are substantially smaller).

4.5 Institutional development impact:

4.5.1 The project has had significant impact on the various institutions involved; the question is whether the positive impacts will be sustainable. Most importantly, institutional development of the OPHC, Gridco, and the distribution companies will continue to be severely constrained if they remain financially weak. OERC development would be helped by more (and more autonomous) financing.

4.5.2 At the community level, thousands of village committees have been established and laid the foundation for pilot franchising programs in one of the distribution companies (WESCO); initial results from franchise operations indicated that losses could be reduced, and collections and connections increased. However, flaws in regulatory design and market structure are preventing any significant expansion of the franchising program. During the pilot phase, the franchisee was rewarded for collection improvement by splitting the incremental revenue generated with WESCO. The distribution companies have tried to advance an alternative model, dubbed the “input-based” approach. Under this scheme, franchisees would pay for the discoms for bulk power and then sell it on to the customers. Obviously, this could only work if retail rates were higher than the bulk rate offered by the discoms, which they are not (Rs 1.3 per kWh is the household rate for the first block, compared to Rs 2.3 per kWh that the distribution company can

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offer to franchisees). As a result, the franchise program in rural Orissa has stalled, as no private company would agree to such terms. In turn, this development makes the further strengthening of village committees problematic.

5. Major Factors Affecting Implementation and Outcome

5.1 Factors outside the control of government or implementing agency:

5.1.1 The super-cyclone of late 1999 was a serious blow to the project. This major storm made a direct hit on the CESCO territory only months after AES had taken control of the entity. Major damage was also sustained by the other discoms and by Gridco. While GOO was able to mobilize funds for emergency repairs, including from the World Bank, the super-cyclone set back the program of operational and financial improvement. AES, in a sense, never really recovered from the effects of the cyclone on CESCO’s business, and subsequently withdrew from CESCO in 2001 when its license was suspended. Another critical factor in shaping project outcomes was the unexpected recession in India in the 1990s; this hit the industrial sector particularly hard, with predictable impacts in Orissa, with its heavy industry-dependent economy.

5.1.2 Drought in FY2003 was also a major factor in the financial performance of the sector. Low reservoir levels curtailed availability of OHPC power by 1,400 GWh (compared to the “normal” year of FY2001), pushing OHPC into a loss of Rs 419 million. Gridco’s purchased power costs in FY2003 were Rs 2 billion higher than in the normal year of 2001 and Rs 4 billion higher than in the wet year of 2002. The result in 2003 was a loss of Rs 658 million, as Gridco increased purchases from more expensive thermal generators, and lost inter-state sales.

5.2 Factors generally subject to government control:

5.2.1 Natural disasters are outside of government control but Orissa’s regulatory approach makes the entities more vulnerable to acts of nature than they need to be. Gridco can apply for an automatic pass-through of purchased power costs, but this does not automatically flow through to retail tariffs. For its part, OHPC sells all of its power to Gridco under fixed price contracts – there is a mechanism to protect its revenue in low water years but again this does not flow through automatically into retail tariff increases. The Orissa approaches protect consumers from potentially volatile retail prices but, unfortunately, leave the power sector entities vulnerable. There are ways that consumers could still be protected (at least for a time) from volatility, but this would require a levy added to a tariff which is under upward pressure anyway because of the need to service debt and fund new investment.

5.2.2 Fund Flows in the project, were a perennial problem for the project right from the inception. Delays in fund flow from the state government (finance department) to the power sector companies, along with adjustment of principal and interest of the project, were among the major factors that affected the implementation of the investment project. Government fund flow practices for much of the project were in direct contravention of the legal agreements between GOO and the World Bank and led to loan suspension for about 6 months. The suspension was lifted after a release of funds to the entities, but the problems came back as soon after. These problems only eased late in the project, in part because by then Government and the World Bank

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were in the advanced stages of discussion about a possible state adjustment loan (which was subsequently approved by the Bank).

5.3 Factors generally subject to implementing agency control:

Counterpart funding under the project was a major problem for discoms, as they were not able to make arrangements for it till the end of the project, affecting the implementation of the project. In the initial part of the project, they used the advances received out of special account (Rs 63 crore was released as advance by the State Government to 4 discoms out of the special account advance) to meet their share of costs but later on as this ran short of the requirement of funds, there were large build-ups of unpaid bills in the discoms. GOO also started to adjust the advance from the companies in the last few months, which made the situation difficult in the latter part of the project. The BSES group of companies managed to partially salvage the situation in the end by bringing some small amounts as counterpart funds.

5.4 Costs and financing:

Estimated project cost at appraisal was $997 million, of which the Bank was to have financed $350 million. Actual project cost is estimated at about $407 million of which IBRD financed 225.5 million, and DFID $109.5 million in technical assistance and financing support. ADB/PFC and REC also financed parts fo the project (see annex 2). The financing plan assumed $233 million in local currency financing from IDBI, PFC, and insurance companies, and $221 million in internal cash generation (of which $188 million was to finance foreign currency cost elements). Almost none of this total of $454 million actually materialized, a direct casualty of the combination of inadequate tariff increases and inadequate loss reduction. $95 million of the Bank loan was cancelled at government’s request, as the entities were unable to use it given the contractual, funds flow, and counterpart funding problem that they experienced. Major delays were experienced in almost every significant investment sub-project, from initial delays in appointing contractors to subsequent delays caused by funds flow issues and/or environmental clearance concerns. By project close, a host of subprojects had not been completed, including the biggest single subproject, the Ib-Merramundali 400 kV transmission line. Additionally, theft of newly installed equipment and material has been a problem; Gridco has had to fund, out of own resources, replacement parts and material that were originally financed by the Bank. Theft has been a special concern along partially built transmission lines, as these assets have been particularly vulnerable to stripping.

6. Sustainability

6.1 Rationale for sustainability rating:

Sustainability is unlikely – without significant operational, policy, and regulatory changes. There are threats to both the reform and investment programs.

6.1.1 Reform program: While it is substantially unlikely that the de jure unbundling of OSEB will be reversed, de facto re-integration may well occur if private distribution operators are

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unviable. Already, the major distributor in the state, CESCO, operates under an administrator appointed by OERC since 2001 when the private operator left. It is possible that AES will return to manage CESCO anew, but there is much uncertainty surrounding this prospect. Similarly, it is unlikely that Orissa would legislate OERC out of existence. But retail tariffs have not been increased for three years, in effect subjecting the distribution companies to a form of cash-needs regulation which leaves nothing for debt service or new investment. Current tariff levels might be manageable if losses were at acceptable levels, but aggregate losses (the sum of technical and non-technical losses, plus non-payments) remain stubbornly high at over 50% of total marketable generation.

6.1.2 Investment program: The absence of full commerciality imperils the sustainability of the investment program. Theft of power, and theft of and damage to equipment remain problems. Service has greatly improved since the early 1990s in most parts of Orissa, but part of this improvement is because expected load did not materialize – actual sales of power in Orissa FY2003 were about 6,800 GWh, compared to the SAR projected estimated load of almost 13,000 GWh. The greater availability of power, from Talcher, Upper Indravati, and OPGC in particular, combined with greatly expanded capacity at key substations and reinforcement and expansion of the T&D network, has resulted in good quality of supply in this slow-growth environment. For the near term, the strengthened network will be able to handle additional power flows. But without adequate financial flows to the transmission and distribution companies, Orissa could find itself back in the situation of the early 1990s, when service quality was very poor due to the lack of investment and maintenance in the network.

Staff Appraisal Report 1996: Projections (GWh)

1997 1998 1999 2000 2001 2002 2003 2004^

Energy available for sale* 9,785 10,902 12,726 13,902 14,809 15,560 16,342 17,159 T&D Losses 3,861 3,798 3,721 3,374 3,367 3,373 3,366 3,432

T&D Losses (%) 39.5% 34.8% 29.2% 24.3% 22.7% 21.7% 20.6% 20.0% Electricity sales 5,924 7,103 9,004 10,528 11,442 12,187 12,976 13,727

Actuals (GWh)

1997 1998 1999 2000 2001 2002 2003 2004^ Energy available for sale* 9,651 10,324 10,571 10,548 11,506 11,637 11,978 12,545 T&D Losses 4,563 4,884 5,396 4,936 5,421 5,862 5,244 5,435

T&D Losses (%) 47.3% 47.3% 51.0% 46.8% 47.1% 50.4% 43.8% 43.3% Electricity sales 5,088 5,440 5,175 5,612 6,085 5,775 6,734 7,110

* Net generation less interstate sales, all losses attributable to Orissa sales only. ^ 2004 projection not included in SAR; figures shown here are based on 5% annual growth in available energy and 20% losses.

6.2 Transition arrangement to regular operations:

With aggregate losses at 52% there is no easy transition to regular operations. In spite of significant improvements in operations and maintenance practices, the addition of an effective training center, and the professionalization of management in the various entities, the power sector business environment remains extraordinarily challenging. Losses (not counting non-collections) of 43% of available generation can be brought down somewhat without major

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new investment (based on experience in other countries) but only if there is very strong political commitment to help the power sector companies enforce anti-theft measures. Here, the effectiveness of the new special police stations will be put to an early test. But even if some loss reduction not requiring major new investment is successful, funding will be needed to bring losses down to best practice levels, and attracting new debt will be very difficult without a major financial overhaul. Ultimately, making the transition to regular and sustainable operations will require strong political commitment, effective regulation, and financially healthy operators, all of which are in doubt in the current environment.

7. Bank and Borrower Performance

Bank7.1 Lending:

Satisfactory. The rating might have been higher but for two factors. First, the load forecast turned out to be very optimistic, in part because of flawed input data (particularly related to losses). More diligence in working through load growth scenarios might have helped. Second, the capacity of Gridco to implement a relatively complex investment program was over-estimated. In hindsight, one measure that might have helped would have been to drop DSM as a separate component, while retaining the robust metering program. Nonetheless this second issue should be seen as a minor mis-step – the project team set the bar high, but recognized the risk and provided adequate technical assistance (much of it financed by DFID) to enhance capacity at Gridco.

7.2 Supervision:

Unsatisfactory. Supervision was uneven. Bank management and staff support to Orissa was critical in the early years in adapting the project to the faster-than-expected privatization of distribution. The task team was less effective in addressing the funds flow problems that were evident early in the project. Another major defect was the lack of effective supervision on environmental and social safeguard issues, particularly in the first half of the project, which was a contributing factor to the lack of implementation of the safeguard framework which had been developed as an integral part of preparation. Supervision was effective on reform and privatization issues – Bank staff diligence and responsiveness on OERC issues, and on assisting GOO with acceleration of distribution privatization after the unsuccessful management contract experience, is particularly noteworthy. Bank supervision of the investment program was less successful – problems were evident early, as contractor selection and award got off to a slow start, as did initial implementation once the contractors were mobilized. These delays might have provided Bank staff with an opportunity to re-visit aspects of the sector development plan, but in practice the Bank tried to get better performance on implementing the program as planned, rather than on making mid-course changes. It is also noteworthy that GOO performance on funds flow issues did not really improve until the very end of the project, notwithstanding Bank suspension of the loan for six months in late 2001. Bank ratings of the project were probably too generous up to the point of the suspension. As supervision improved toward the end of the project, the number of problem flags increased, ultimately reaching five – safeguards, financial performance, financial management, legal covenants, and management problems – by the time of the last supervision mission.

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7.3 Overall Bank performance:

Unsatisfactory.

Borrower7.4 Preparation:

Satisfactory. Political commitment in particular was decisive in seeing this project get off the ground in the first place. OSEB/Gridco capacity to contribute to preparation was limited, yet the company did establish an effective project unit and provided adequate staffing and institutional support. The lack of detailed and reliable information wound up being the most problematic aspect of Gridco’s contribution to preparation of the project, particularly as regards losses. Poor information, coupled with a culture of over-optimistic planning forecasting, also contributed to the defective load forecast.

7.5 Government implementation performance:

Highly unsatisfactory. First, GOO management of funds flow to the implementing agencies was consistently problematic; GOO routinely delayed transfers by six to nine months over most of the project, showing some improvement in this measure only toward the very end of the project. It is apparent that, given the very strained nature of state finances, GOO was using the power sector project funds as a kind of float. Government also routinely deducted interest-owed, in violation of the loan agreements, from the late transfers to the implementing agencies. This put incredible pressure on companies and contractors alike and was, at a minimum, a contributing factor to the financial distress experienced by two of the major contractors over the course of the project. A second major area of performance deficiency relates to OERC. While GOO is to be properly commended for its support in creating and strengthening OERC in the mid-1990s, it damaged OERC’s effectiveness and independence by not appointing commissioners to open seats in 1999-2000. While eventually those positions were filled, since the reappointment the OERC, has been conducting reviews and hearings, but has never raised retail tariffs even though the Government didnt make timely implementation of all the actions under which tariffs would be held down.

7.6 Implementing Agency:

7.6.1 Financial Management and Procurement: The funds flow and counterpart funds issues have been mentioned previously. Overall, the limited progress that has been made on financial management has been long overdue, and all entities have much more to do. On specific issues: There were no major accountability issues in the project audit reports. However, entity audits have been hugely delayed; audits for the BSES companies up to FY2003 have only just been finalized. One lesson of the project is that a longer period of time may be needed for newly privatized entities to finalize audits. In case of CESCO, due to management walkout, appointment of an administrator by GOO and dissension between the two faction in the board, the

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entity audits for the past three years are yet to be finalized. The issue related to the transfer of opening balances still remains unresolved between Gridco and the discoms. This is the difference between the transfer scheme, as formulated by GOO, and the balances as per the discoms, in respect of the provision of terminal benefits and provision against gross debtors. This has given rise to a total aggregate difference of over 1,000 crores (over US$200 million) between the balance sheets of Gridco and the Discoms. The process of resolution in this respect seems unclear, and no progress has been made in the last three years. Procurement delays were a major problem in the project in the beginning, and it is likely that having fewer, larger packages would have helped. In the overall context of the project, however, procurement was not a major issue other than at the very beginning.

7.6.2 Social and Environmental Safeguards: Overall, social and environmental impacts have been relatively minor, with small numbers of project affected persons. Yet overall safeguards management was disappointing. A safeguards management plan was prepared as part of project preparation, approved only in March 1999, but essentially not implemented. This plan provided guidelines for environmental assessment; project environmental and social assessment; and environmental and social policy procedures. Subsequently, in the later stages of the project, a reputable NGO was employed to develop a new plan that reflected current safeguard standards. This Rehabilitation Action Plan (RAP) identified 248 project-affected persons eligible to receive nearly Rs 800,000. Gridco has compensated private land-owners according to India’s Land Acquisition Act, or had land transferred directly from GOO. Over the course of the project, about 3,000 private land owners were paid “crop compensation” of Rs 6.4 million for laying of transmission lines and associated activities. The major environmental issue relates to deforestation. Gridco, after many delays, eventually obtained all necessary forestry clearances. A total of about 30,000 trees were to be cut, and Gridco has in turn paid the Forestry department more than Rs 10 million for compensatory afforestation. Unfortunately, the Forestry department has been unwilling to give any guarantee that these funds will be actually used for tree planting and maintenance. An additional difficulty is that most of these 30,000 trees were cut in the Ib-Merramundali right-of-way, for the 400 kV line that will not be used for at least four years because there has been no new capacity added in the Ib Valley. Finally, the private distribution companies do not appear to have implemented any form of safeguards framework; though social and environmental impacts of the distribution program would have been limited, the companies have not provided any information as to what those impacts were and how they were dealt with.

7.7 Overall Borrower performance:

Unsatisfactory.

8. Lessons Learned

Strong ownership of a reform program is essential for success, but the program must be lgrounded in reality and expectations need to incorporate the difficult political economy circumstances in which reform is implemented. Orissa had very strong ownership early in the project, and so was able to implement major reforms; but commitment, especially to sector

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financial health, waned as the project went on, and resulted in an incomplete reform program.

Tariff reform must recognize political economy realities, and must incorporate a sensible, lfinanceable transition subsidy scheme so that full cost recovery, and therefore sustainability of restructuring, can be achieved. The abrupt halt of subsidy in Orissa, at the point of discom privatization, must now be seen as a major defect of the reform program. All stakeholders must share in the burdens of restructuring, and an effective communications strategy needs to be in place to ensure that all stakeholders understand (and hopefully buy into) the way in which these burdens have been allocated. Discussion on appropriate tariff and subsidy levels and mechanisms might have been conducted accordingly.

Reforms need to be institutionalized, putting a burden on capacity building for successor loperating entities, and new agencies like the regulatory commission. Regulatory effectiveness is critical and independence – in analysis, funding, decision-making – is important in building legitimacy among stakeholders. Regulatory credibility has been damaged, though not irreparably, by four years without a retail tariff adjustment, by attempts to re-open power purchase contracts, and by retention of unrealistic loss allowances.

Power sector reforms have important links to broader state fiscal policy initiatives and each lshould support the other. Orissa's fiscal situation has improved for the time being, from the end of annual outlays for subsidies and the one-off impact of privatization proceeds. But the state may well find itself with large and increasing liabilities unless a power sector financial recovery plan is decisively designed and implemented. The plan, though, will have to be broadly acceptable to all stakeholders, including the private investors.

Investment programs need to be well prepared and implemented in a way that integrates good lfinancial and contractor management with social and environmental safeguards. Flexibility is essential so investment programs can adapt to evolving demand, thereby avoiding unproductive investments. In Orissa's case, the load forecast deviated so significantly from reality that the forecast should have been rigorously updated and, as appropriate, the investment program modified. This is especially true of the 400 kV Ib-Merramundali transmission line. The Ib valley power plant to which this project was tied was beginning to look doubtful (at least in its timing) in 1999, was known to be significantly delayed in 2000, and was formally cancelled in 2001. Yet there is no evidence that there was ever any serious re-consideration of the decision to construct the line.

Distinctions should be made between investments integral to the development of the network las a whole, and dedicated investments that are tied directly to a specific supplier or consumer. Had such a distinction been made, most of the investments in expanding capacity at key substations would still have been made, and the fact that load did not always materialize as expected would have fewer economic consequences because of the strong economies of scale exhibited in network strengthening investments. Dedicated investments should only be made when suppliers and/or consumers have properly indemnified the asset provider against the risk that the new facilities will not be used because supply (and/or consumption) is not there as expected. Cross-indemnification (meaning that both parties involved in parallel, dependent

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investments indemnify each other against the risk that the other investment may not materialize) is now standard for transmission projects in India, so this lesson (also learned from other projects in India) has already been taken to heart.

Flexibility is important for the Bank as well. On the Bank side, the disciplines described above lwill challenge historically inflexible procedures to be more adaptable to changing circumstances – without causing lengthy delays. The Bank should also explore ways in which Bank-financed projects can be more demand driven, and should work with all clients to ensure a proper allocation of risk to the public sector when public investments are dependent on privately financed assets coming on line when they should. The Bank should not accept “build it and they will come” (i.e. supply-driven) arguments in power sector development.

Private participation in the distribution business does not overcome flawed policy and lregulatory approaches; private tolerance for losses is quite limited. AES and BSES/Reliance Energy could not have turned around the distribution companies even if they had been better prepared to make the attempt at the point in 1999 when they took over the companies, because of the extremely negative business environment. What really matters in a distribution business is actual cash flowing from customer to operator. For this to happen the legitimacy of the operator must be there, and credibly and consistently backed by policy and regulatory (and law and order) institutions. Balance sheet engineering, such as asset re-valuation, might then be appropriate, but asset up-valuation, as was done in Orissa, may have the effect only of putting upward pressure on rates and does not in and of itself promote enhanced commerciality. A better approach may be to recognize and appropriately value the old, degraded assets, and design projects to rely less on internally generated cash for investment in the early years. Securitization of debt, as has been done in respect of amounts owed to NTPC, is an appropriate technique for restructuring debt, but needs to be complemented by adequate tariff levels and sustained collection efforts.

Private sector performance in the distribution business fell far short of public sector lexpectations. This may have been partly due to GOO inexperience with private participation in power, but the private firms must take significant responsibility for failing to undertake adequate due diligence. BSES/Reliance in particular singularly failed to put adequate managerial resources on the ground, and also failed to invest risk capital beyond the initial purchase of its 51% stakes in the three companies. Only by the end of the project, nearly five years after operational transfer, did BSES/Reliance Energy make concerted and effective moves to put robust management teams in place. It might also be added that it can take much time to implement good financial management and accounting systems in poorly performing entities, and more time should be given for privatized entities to present audited accounts. Orissa was only one experience in power distribution in emerging markets among many others where the challenges of the business were under-estimated by buyer and seller alike. But if this lesson has been learned in part, the right balance of risk and reward continues to elude policy-makers, and distribution privatization remains profoundly challenging and risk-laden.

Reform must be a continuous process and Orissa has built a foundation, albeit shaky, from lwhich a healthy sector could yet emerge. The state's power sector is at an important

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crossroads. Concerted Government effort in crafting a financial recovery plan for the sector, and addressing policy and regulatory shortcomings, could enable the power sector entities to gain strength and, ultimately, to thrive. Lack of action will result in considerable deterioration of the current, tenuous situation. In this sense, a full telling of the Orissa power sector reform story can only be told in the future.

9. Partner Comments

(a) Borrower/implementing agency:Government of India - Department of Economic Affairs had no comments on the report.

Consolidated comments provided by Government of Orissa which are reproduced in annex 10. In these the State Government notes that it had consciously decided to continue with the Ib to Meramundali transmission line as it can be used to power transmission other than from the Ib expansion, particularly when surplus hydro supplies are available. In the initial stage it can be charged at 220 KV so the surplus power at Budhipadar 220KV bus can be evacuated through this line. This aspect has been lost sight of while preparing the report. Further, the construction of two units having 210 MW each by OPGC is on the anvil. As such, it is needless to say that this line will be fully utilized.

Further the Government explained that the process by which the non-Indravati OHPC hydro station rates noted in para 4.1.4 were reduced was the culmination of a detailed review of the power sector and public inquiry by the Kanungo committee. Thus the rate reduction was well thought out and part of a wider range of detailed recommendations including - reversal of the up-valuation of assets of OHPC and Gridco, moratorium on debt service on Government debt, securitization of outstanding dues to OHPC, temporary removal of OHPC and Gridco requirement to earn return on equity.

With reference to the report in general, the Government states that, the World Bank should also appreciate the point which is being raised oft and on during the public hearing that it is the general public who have backed up the reform in the power sector by way of accepting frequent tariff rise from the beginning. All other stakeholders have dragged their feet and have not fulfilled with commitments. One significant and cardinal point raised by the public is that the distribution companies are unable to reduce distribution losses when the Kanungo committee had fixed realistic loss levels as suggested by the Distribution Companies. However, the report is unobtrusively silent about the tardy and ineffective all round performance of distribution companies.

In addition, the following is summarized from comments provided by specific entities as noted:

CESCO

Benefits of the project: Power interruption has been drastically reduced from some days to some hours; transformer failure has been reduced from 19% (2000-01) to 10% (2003-04); voltage has stabilized; customer satisfaction has increased; revenue has increased; and losses have come down. However, there were hurdles faced during implementation of the project: Due to

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on-going reform process of Gridco there was delay in handing over project activities to CESCO, and as CESCO was not fully organized, implementation was delayed at the outset; AES took over management of CESCO and investment of fund stood in the way of implementation of the project; the super cyclone damaged the economic backbone of CESCO and delayed implementation. Suspension of the World Bank loan further delayed implementation. Uncertainty of funds and management changes were the main causes of implementation delays.

SOUTHCO

Benefits: The works have helped in saving the network to a certain extent. Over-loading of lines has been reduced. Interruptions have been reduced. Customer satisfaction has increased. Voltage has improved. There is adequate reduction of T&D loss. The improvement in supply quality resulted in better revenue collection from more satisfied customers. However, there were problems in completion of works: There have been delays due to release of Supplier/Contractor payments; delays in receipt of payment from Government of Orissa, and suspension of World Bank loan; and initial delays have created further right-of-way problems. Southco also suffers from theft of conductors and tower components in completed works.

NESCO

Benefits: Overall distribution loss has been reduced from 65% to 60% from 1999-2000 to 2003-04. Consumers have increased from 252,000 to 442,000. Voltage has stabilized. Billing and collection has improved.

GRIDCO Project Management Unit

Benefits: Improvement in voltage; reduction in system losses, overloads, and unplanned outages; appropriate resettlement and crop damage compensation; installing and training personnel in safety and fire fighting equipment; benefits to industrial consumer and agriculture sector.

Lessons learned: Hard decisions early in the process will reduce initial difficult period of the reform process; proper packaging should be done for early completion of the project; forest clearance must be obtained prior to bidding; availability of required land and right-of-way has to be ensured before invitation to bid; provision of payment for crop damage must be included in contractor scope of work; procurement of materials and erection of works must be synchronized to minimize inventory pile-up; erection of lines and substations must be synchronized to avoid theft of completed works; projects should be covered by insurance by the turnkey contractor until handing over to the client; technical specification and qualification is to be made as objective as possible to eliminate any ambiguity that may delay bid evaluation; adequate attention has to be given to financial aspects like the availability of funds to pay contractors;initial data required for cost-benefit analysis must be collected from the beginning of the project; accountability must be fixed on the consultants for any delay/error during approval and erection of the work.

(b) Cofinanciers:Department for International Development (DFID), United Kingdom

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The involvement of the World Bank and DFID in Orissa’s power sector has a 12-year history, going back to the early 1990s. At the beginning, the Government of Orissa asked DFID (then known as ODA) to help the Orissa State Electricity Board improve its management through an institutional support programme. Shortly afterwards, the World Bank suggested combining this with a major, sector restructuring project, which became the basis of a long term working partnership between the Bank and DFID. This was the first attempt in India to support the state government to fundamentally reform and restructure the state owned utility. This resulted in private sector investment and participation in the thermal generation and power distribution businesses.

The reform programme was controversial and resisted by those with vested interests in maintaining the status quo. The process was more difficult and more complicated than anyone expected at the outset. While the result so far is imperfect, this was a considerable achievement that, 5 years after privatisation, has proved durable despite severe stresses. Without reform, the sector would likely have been an increasing burden on public finances with services continuing to deteriorate. Instead, the sector has become a net contributor to state finances, with distribution losses falling and the distribution companies now able to meet their power purchase costs and meet some past liabilities. Orissa is one of the very few states in India not paying power sector subsidies. In addition, services have improved and power supply is more reliable. The reform programme in Orissa set the way for sector reforms elsewhere in India, now incorporated in the new Electricity Act and undertaken in several other states, including Delhi, Andhra Pradesh, Haryana, Karnataka, Madhya Pradesh, Rajasthan and Uttar Pradesh. Some of this was done with Bank and DFID support.

The effective working partnership between the Bank and DFID should be recognised. The Bank’s resources provided the incentive to make progress, while the availability of grant supported, specialist technical assistance built the capacity to undertake the task. One would not have worked without the other. This capacity is a legacy of the programme and has been used in India beyond Orissa. Lessons from the Orissa experience include the need for flexibility in the face of new information and changing circumstances, such as on privatisation and the management and delivery of rural services. This is a long-term commitment that should extend through the transition from public to private ownership and control.

(c) Other partners (NGOs/private sector):AES, encouraged by World Bank’s involvement in the power-sector reform of Orissa, took the majority control of CESCO with some legitimate expectations that (1) Orissa Electricity Regulatory Commission (“Regulator”) would rationalize tariffs based on realistic loss level, bring in regulatory certainty and independence from Government of Orissa (“GoO”); (2) World Bank funds would be promptly lent to CESCO; (3) GoO would pay the past arrears as well as current dues to CESCO for the energy consumed by various Government departments; (4) GRIDCO and GoO would cooperate and provide support, including police support, for CESCO’s efforts to reduce theft. Each and every legitimate expectation was thwarted by GRIDCO and GoO. At every turn, GRIDCO and GoO made CESCO’s job nearly impossible by interfering in the management of CESCO’s operations, including forced transfer and redeployment of employees (even for political activities unrelated to CESCO) and preventing necessary commercial practices like the disconnection of defaulting customers, and finally agitating a multiple number of

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litigations against AES before multiple fora i.e. Arbitrator, Courts and OERC on a single frivolous issue that CESCO’s dues to GRIDCO to be assumed by AES as an investor in CESCO. Unfortunately, World Bank could not make GoO accountable for the reform. Despite World Bank continuing to provide Structural Adjustment Loan (“SAL”) to GoO for its fiscal correction, GoO till date failed to setup any special court and adequate number of police stations to deal with theft of electricity as per Electricity Act 2003. GoO dues to CESCO on account of energy bill have been piling up as before. AES believes that World Bank can play a constructive role to make reform a success by linking release of SAL to GoO’s accountability to and demonstration of successful power-sector reform. Recently, AES committed additional funding for CESCO’s future operations subject to all stakeholders’ acceptance of a sustainable business plan to insure CESCO’s financial viability. AES believes that this should be the perfect “pilot” program where World Bank can give its support through direct funding and instruments like Partial Risk Guarantee and can make reform work.

10. Additional Information

See Annex 9.

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Annex 1. Key Performance Indicators/Log Frame Matrix

Outcome / Impact Indicators:

Indicator/Matrix

Projected in last PSR1

Actual/Latest Estimate

(a) Establishment of GRIDCO, OHPC and the Regulatory Commission.

1996

(b) Enactment of legislation and regulations.

December 1996.

(c) Licensing of GRIDCO and the distribution companies.

Given on time.

(d) Privatization of GRIDCO's distribution system.

September 1999.

(e) Listing and disinvestment of GRIDCO's and OHPC's shares.

No financial case for this at present.

Output Indicators:

Indicator/Matrix

Projected in last PSR1

Actual/Latest Estimate

(a) Finalization of GRIDCO's and ODHPC's personnel policies and establishment of their own staff cadres.

April 1997

(b) Satisfactory financial performance of GRIDCO and OHPC.

Targets not met

(c) Budgeting of the Regulatory Commission.

Target met in all years

(d) Staffing of the Regulatory Commission.

Target achieved

(e) Reduction of system losses. Not achieved

(f) Competitive procurement of new generation capacity.

No new capacity procured

(g) Demand-side management. No progress in other DSM activities, metering has made steady progress

(h) Integration of environmental considerations into the implementation of GRIDCO's investments.

Not yet sufficient

(i) Rehabilitation of Orissa's existing old thermal power station.

Targets improvement have been met and continues to be met.

(j) Environmental/ watershed management by OHPC.

Study carried out and implemented by OHPC.

1 End of project

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Annex 2. Project Costs and Financing

Project Cost by Component (in US$ million equivalent)AppraisalEstimate

Actual/Latest Estimate

Percentage of Appraisal

Component US$ million US$ million Transmission and Distribution Systems 599.20 304.30 0.51 Demand-sideManagement 96.80 25.50 0.26 Institutional Development, Technical 44.00 77.40 1.76 Assistance and Training

Total Baseline Cost 740.00 407.20 Physical Contingencies 60.20 Price Contingencies 147.70

Total Project Costs 947.90 407.20Interest during construction 49.20

Total Financing Required 997.10 407.20Note: Actual project costs include financing from DFID ($109.5-million, including $72-million in technical assistance), ADB/PFC ($31.1-million), REC ($41.5-million); and the World Bank ($225.5-million).

Project Costs by Procurement Arrangements (Appraisal Estimate) (US$ million equivalent)

Expenditure Category ICBProcurement

NCB Method

1

Other2 N.B.F. Total Cost

1. Works 143.30 9.60 0.00 31.20 184.10(75.00) (5.00) (0.00) (0.00) (80.00)

2. Goods 492.90 36.00 9.50 174.60 713.00(235.00) (20.00) (5.00) (0.00) (260.00)

3. Services 0.00 0.00 5.90 13.00 18.90Implementation Support (0.00) (0.00) (4.50) (0.00) (4.50)4. Policy Support 0.00 0.00 5.90 6.30 12.20

(0.00) (0.00) (4.50) (0.00) (4.50)5. Capacity-Building 0.00

(0.00)0.00

(0.00)1.30

(1.00)18.90(0.00)

20.20(1.00)

6. Miscellaneous 0.00(0.00)

0.00(0.00)

0.00(0.00)

0.00(0.00)

0.00(0.00)

Total 636.20 45.60 22.60 244.00 948.40(310.00) (25.00) (15.00) (0.00) (350.00)

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Project Costs by Procurement Arrangements (Actual/Latest Estimate) (US$ million equivalent)

Expenditure Category ICBProcurement

NCB Method

1

Other2 N.B.F. Total Cost

1. Works 28.30 0.00 0.00 0.00 28.30(28.30) (0.00) (0.00) (0.00) (28.30)

2. Goods 317.96 1.63 1.27 0.00 320.86(181.60) (1.49) (0.15) (0.00) (183.24)

3. Services 0.00 0.00 2.96 9.39 12.36Implementation Support (0.00) (0.00) (3.04) (5.52) (8.56)4. Policy Support 5.40 0.00 0.00 0.00 5.40

(5.40) (0.00) (0.00) (0.00) (5.40)5. Capacity-Building 0.00

(0.00)0.00

(0.00)0.00

(0.00)0.00

(0.00)0.00

(0.00)6. Miscellaneous 0.00

(0.00)0.00

(0.00)0.00

(0.00)0.00

(0.00)0.00

(0.00) Total 351.66 1.63 4.23 9.39 366.92

(215.30) (1.49) (3.19) (5.52) (225.50)

1/ Figures in parenthesis are the amounts to be financed by the Bank Loan. All costs include contingencies.2/ Includes civil works and goods to be procured through national shopping, consulting services, services of contracted staff

of the project management office, training, technical assistance services, and incremental operating costs related to (i) managing the project, and (ii) re-lending project funds to local government units.

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Annex 3. Economic Costs and Benefits

(This Annex has been summarized from the Economic Analysis Report, which is available in full in the project files)

Economic analysis at appraisal

1. The economic analysis in the Orissa Staff Appraisal Report (SAR) assessed the overall investment program that was supported in part by the Bank Loan. The economic rate of return (ERR) was calculated on the basis of the incremental cost and benefit streams associated with the FY1997-2003 time-slice of the Orissa investment program. The time-slice period covered the construction and first few years of operation of Ib Valley thermal plants (units 1-4); the Upper Indravati hydro plant; the rehabilitation work on Hirakud hydro plant; the expansion and upgrading of the transmission and distribution system; and the implementation of a demand side management (DSM) program.

2. Costs: Projects completed during the time-slice period were taken as the time-slice investment program. Financial costs of that program were converted to economic terms by excluding taxes and duties and by applying a standard conversion factor (SCF) of 0.9 to the residual local costs. Incremental operations and maintenance (O&M) costs were taken from the financial projections and converted into economic terms by applying the SCF. Also included were Orissa’s incremental power purchases from NTPC, taken from GRIDCO’s financial projections. Fuel, power purchases and O&M costs of the last year of the time-slice investment period were kept constant in real terms through FY2022, the operating period of the time-slice investments.

3. Benefits: For the baseline ERR estimate, GRIDCO’s incremental tariff revenue was used as a proxy for economic benefits. Tariff revenue was considered by the SAR to be the minimum measure of the actual benefits as it reflects only a portion of the total benefits of electricity supply. Table 1 reproduces the SAR economic analysis (Table 1). The ERR was estimated at 14.5%.

Table 1: SAR Economic Analysis

(Million Rs)NPV 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Investment ProgramThermal 11323 5520 4474 3111 966Hydro 9974 7643 1045 1381 1286 680 127 146T&D 8171 1791 2549 2564 2191 2245 2032

Operating CostsO&M 4156 215 262 320 473 747 779 779 779 779 779 779 779 779 779Fuel 5224 347 347 346 651 958 958 958 958 958 958 958 958 958 958Power Purchases 23297 992 2124 4184 4123 1897 3973 3973 3973 3973 3973 3973 3973 3973 3973

Total Costs 62145 13163 8864 9774 9666 8118 5974 7888 5710 5710 5710 5710 5710 5710 5710 5710

Total revenue 67963 2445 4062 6630 8645 10290 12893 12893 12893 12893 12893 12893 12893 12893 12893Net benefits 5818 -13163 -6419 -5712 -3036 527 4316 5005 7183 7183 7183 7183 7183 7183 7183 7183ERR 14.4%

Note: Calculations extend to FY2022; for clarity we show only to FY 2010

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Approach for the ICR economic analysis

4. Although Orissa was the first of the Indian World Bank power sector restructuring projects, it is the third for which an ICR is being prepared (the ICR for Haryana was completed in 2001, and the Andhra Pradesh (AP) ICR was completed in January 2004). In the AP ICR, the estimation of project benefits could be precise, because detailed benefit evaluation studies had been done both at appraisal, as well as at the end of the project. Thus, for example, the benefits of transmission system investments were estimated using a detailed load flow model that examined system losses and voltage levels with and without the Aptransco investment program, an assessment conducted both at the time of appraisal as well as at the end of the project. Such benefit assessment studies have not been completed for Orissa. Therefore, it is not possible to evaluate the economic returns of only that part of the investment program specifically supported by the Bank Loan.

5. Consequently, there is little choice but to adopt the same general approach for the ICR as followed in the SAR, namely to assess the incremental cost and benefit streams. Because the tariff has declined in real terms, taking economic benefits at the minimum (tariff) valuation produces an unsatisfactory ERR. But economic benefits are known to be substantially greater than those yielded by a (declining) real tariff, so benefits are also assessed using average willingness to pay. When the economic benefits of pilferage are included (pilferage is not simply an economic loss, because pilferers derive significant economic benefits from their consumption), the ERR is a satisfactory 13.5%. The approach taken in this ICR is to conduct the analysis for the consolidated transmission and distribution businesses.

6. Table 3 shows the capital investment expenditures of GRIDCO and the DISCOMs. The total investment program includes limited contributions from self-financing, and more significantly from external funding sources (DFID, ADB, PFC, and REC). The IBRD contribution is 60% of the total.

Table 2: The Investment Program (Summary, in Rs million)

FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04 F05

Total 14190 NA 1108 636 3299 2265 1914 2307 2661 NATotal IBRD 8470 185 0 236 547 1753 1583 1842 2004 321as % of total 60% 37% 17% 77% 83% 80% 75%

NA = overall investment program derived from balance sheet not available.

7. Finally, we may note that the significant variance between actual growth of the system, and those estimated at the time of appraisal, does not affect substantially effect the ERR calculations. The estimate of the SAR for FY2003 sales to Orissa customers was 12,976 GWh, as opposed to the actually achieved 6,734 GWh. However, the ERR calculations are based on what actually occurred, and on actual incremental cost and benefit streams.

Financial rate of return

- 29 -

8. The financial rate of return can be derived directly from the detailed financial statements prepared by the ICR, following the methodology as used in the SAR economic analysis, i.e. by evaluating the incremental streams of financial costs and benefits attributable to the FY1997-2003 time slice of the investment program. In the following discussion, references to row number refer to Table 3, where data items taken directly from the financials are shaded.

9. As a check on the consistency of the investment program obtained from GRIDCO and the DISCOMS (Table 3), one may compare this to the increase in fixed assets as revealed in the balance sheet of the consolidated T&D business (from an analysis of transfers from construction work in progress, CWIP). In the interest of making conservative assumptions, we assume a two-year lag between the year of the investment outlay, and the year in which the incremental returns become available. Thus benefits of FY1997 outlays are assumed only starting FY1999, a conservative assumption for T&D investments.

Table 3: Financial Rate of Return

NPV FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04 FY05 FY06 FY07

Revenue from Sale of Power1 Power sold2 − to DISCOMS/[customers] GWh 5088 5440 5175 5612 6085 5775 6734 71103 − Inter-state sales GWh 0 0 0 650 894 830 48 6064 Total GWh 5088 5440 5175 6262 6979 6605 6782 77165 − to DISCOMS Rs Million 4402 13838 15868 16801 19037 200426 − to Consumers/Inter-state sales Rs Million 11534 13999 9287 1981 2542 2556 650 18117 Total revenue from sale of power Rs Million 11534 13999 13689 15819 18410 19357 19687 218538 Incremental Revenue Rs Million 0 -310 1820 4411 5358 5688 7854 7854 7854 7854 78549 Tariffs10 − to DISCOMS Rs/kWh 2.5 2.6 2.9 2.8 2.811 − to Consumers/Inter-state sales Rs/kWh 3.0 2.8 3.1 3.012 Overall Rs/kWh 2.3 2.6 2.6 2.5 2.6 2.9 2.9 2.81314 Power Purchase Costs15 Purchased power GWh 9651 10324 10571 11197 12400 12467 12026 1218516 Purchase of power Rs Million 9827 11998 12406 11656 13997 11878 16040 1357517 Rs/kWh 1.0 1.2 1.2 1.0 1.1 1.0 1.3 1.118 Incremental purchase costs Rs Million 0 408 -342 1999 -120 4042 1577 1577 1577 1577 15771920 O&M Costs21 Repairs and maintenance Rs Million 434 585 476 790 578 612 584 187122 Salaries and wages Rs Million 2381 2667 2771 3427 3300 3934 4116 404323 Admin. & general expenses Rs Million 334 336 310 914 913 1125 1698 113224 Total costs Rs Million 3149 3588 3557 5131 4791 5671 6398 704625 Rs/kWh 0.62 0.66 0.69 0.82 0.69 0.86 0.94 0.9126 Incremental O&M costs Rs Million 0 -31 1543 1203 2083 2810 3458 3458 3458 3458 34582728 Investment29 Investment programme Rs Million 6896 185 1108 636 3299 2265 1914 23073031 Total (incremental) costs Rs

Million30615 185 1108 1013 4500 5467 3877 9159 5035 5035 5035 5035 5035

3233 Net flows Rs Million 4278 -185 -1108 -1323 -2680 -1056 1481 -3471 2818 2818 2818 2818 281834 Financial rate of return, nominal Rs 20%35 Deflator 1.00 1.06 1.12 1.17 1.24 1.29 1.33 1.40 1.47 1.47 1.47 1.4736 Net flows, constant 1996 Rs Rs Million 2049 -185 -1049 -1181 -2297 -854 1146 -2603 2010 1920 1920 1920 192037 Financial rate of return, constant Rs 17%

10. The incremental revenue [row 8] is readily calculated from the P/L statement line items for sale of power to DISCOMs and interstate customers. The incremental operating costs [rows

- 30 -

20-24] and incremental power purchase costs [rows 14-18] are calculated from the corresponding line items in the P/L statement. The net flows follow in line [33], which are adjusted by the deflator to convert to constant FY1997 Rs. The FIRR calculates to 20% nominal, 17% in constant Rs.

11. We have adjusted the data for the unusually high out-of-state sales of FY2004, a consequence of a very wet hydro year, and the single buyer model that brings the corresponding benefits into the GRIDCO financials. In place of the FY2004 actual inter-state sales of 3,229 GWh, we take the average of the four previous years (650, 894, 830, and 48 GWh), namely 606 GWh. The corresponding figure for power purchases is also adjusted downward. This makes a considerable difference to the result, especially for the FIRR.

12. In light of the general financial difficulties reported by the Orissa GRIDCO and DISCOMS, this positive financial return may be considered surprising. However, this is an incremental calculation of benefits to an investment program, not a calculation of the average financial rate of return to equity (or to total assets). The T&D investments undertaken in the time-slice were generally to rehabilitate the worst parts of the system at the start of the reform program, following years of neglect and lack of adequate T&D investment. Additionally, the calculated financial returns include not just the benefits of the investment program per se, but also the benefits of the reform program (increased tariffs, reduced commercial losses, greater efficiency of operation etc). Finally, the average costs of purchased power are quite low (Rs 1-1.3/kWh) compared to the economic cost of power (discussed below), and therefore involve considerable subsidy (a large part of which is captured by pilferers). This subsidy therefore raises the financial returns in the T&D business (and is one of the main reasons why the economic returns are substantially smaller).

Economic analysis: benefits at the consumer tariff

13. Economic benefits set to the tariff (as in the SAR), and converted into constant FY1997 Rs. However, as shown in the figure to the right, in real terms the average tariff (including interstate sales, which in FY2003 amounted to 31% of total GRIDCO sales) has decreased since FY1997.

- 31 -

1.8

2

2.2

2.4

2.6

2.8

3

2.27 2.57 2.65 2.53 2.64 2.93 2.90 2.692.27 2.45 2.40 2.18 2.15 2.29 2.20 1.95

Nominal

Constant 96 Rs

Rs/k

Wh

FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04Nominal RsConstant 96Rs

14. As shown in Table 6, while tariffs for domestic and commercial consumers were increased in FY2000 and FY2001, they have stayed unchanged since then. This may have been wise strategy from the perspective of attracting consumers formerly dependent upon self-generation back onto the grid, but it is unhelpful to the SAR methodology of taking economic benefits at the tariff.

Table 4: Orissa Tariffs

Units/Month 1998-99(FY99)

1999-00(FY00)

2000-01(FY01)

2001-02(FY02)

2002-03(FY03)

2003-04(FY04)

Effective From 1-Dec-98 1-Feb-00 1-Feb-01 1-May-02 1-Dec-03

Domestic < = 100 110 110 130 130 130 130> 100 and< = 200 160 180 220 220 220 220> 200 235 270 310 310 310 310

Commercial < = 100 260 270 310 310 310 310> 100 and 360< = 200 350 400 400 400 400> 200 and 400 440 440 440 440< = 300> 300 400

Irrigation -- LT 80 80 100 100 100 100

LT -- Small Industry 235 270 310 310 310 310

LT -- Medium/Large Industry 270 280 320 320 320 320

HT -- Industry 260 260 300 300 300 300

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15. A second critical assumption is the economic cost of purchased power. As noted above, this will be substantially above the financial cost of Rs 1.00-1.30. The best estimate of the avoided cost would be the difference in LRMC derived from a generation capacity expansion planning optimization with and without the T&D investment program. This is not available for Orissa. Other recent World Bank studies for India, including the AP ICR, use a FY2003 value of Rs 2.0/kWh, equivalent to about Rs 1.5 at constant FY1997 price levels as used here.

16. The result, as shown in Table 5, is a negative ERR. This unsatisfactory result follows directly from a comparison of the economic cost of power purchased and the tariff (in real terms). With a falling real tariff and constant cost of power purchase, it cannot surprise that economic returns using this benefit measure are negative.

Table 5: Economic Analysis, Minimum Benefit Valuation (taken at the consumer tariff)

NPV FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04 FY05 FY06 FY07 FY08

1 Calendar year inflation rates 5.2 6.9 3.5 6.2 5.2 2.5 5.3 4.7 4.7 4.7 4.7 4.72 FY inflation rates 5.6 6.1 4.2 6.0 4.5 3.2 5.2 4.73 Deflator 1 1.06 1.12 1.17 1.24 1.29 1.33 1.40 1.47 1.47 1.47 1.474 Revenue from sale of power5 − to DISCOMS Rs Million 0 0 4402 13838 15868 16801 19037 200426 − to Consumers/Inter-state sales Rs Million 11534 13999 9287 1981 2542 2556 650 18117 Total revenue from sale of power Rs Million 11534 13999 13689 15819 18410 19357 19687 218538 In constant Rs Rs Million 11534 13253 12221 13556 14891 14979 14762 155839 Incremental revenue, constant Rs Rs Million 0 -1033 302.7 1637 1725 1508 2330 2330 2330 2330 233010 Power sold GWh 5088 5440 5175 6262 6979 6605 6782 771611 Average selling price Rs/kWh 2.27 2.57 2.65 2.53 2.64 2.93 2.90 2.8312 In constant Rs Rs/kWh 2.27 2.44 2.36 2.16 2.13 2.27 2.18 2.021314 O&M Costs15 Ppower purchased GWh 9651 10324 10571 11197 12400 12467 12026 1218516 Economic cost of power Rs/kWh 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.517 Cost of power purchases (constant Rs) Rs Million 14473 15482 15853 16792 18596 18696 18035 1827318 Incremental power purchase costs Rs Million 0 370.4 1309 3113 3214 2552 2791 2791 2791 2791 27911920 Repairs and maintenance Rs Million 434 585 476 790 578 612 584 187121 Salaries and wages Rs Million 2381 2667 2771 3427 3300 3934 4116 404322 Admin. & general expenses Rs Million 334 336 310 914 913 1125 1698 113223 Total costs Rs Million 3149 3588 3557 5131 4791 5671 6398 704624 SCF25 Adjusted for SCF Rs Million 2834 3229 3201 4618 4312 5104 5758 634126 Incremental O&M costs Rs Million 2834 3057 2858 3957 3488 3949 4318 452227 In constant Rs Rs Million 0 -199 900.1 430.4 892.3 1260 1465 1465 1465 1465 14652829 Investment30 Investment programme Rs Million 6896 185 1108 636 3299 2265 1914 2307 031 Adjusted for SCF Rs Million 167 997 572 2969 2039 1723 2076 032 In constant Rs Rs Million 167 944 511 2544 1649 1333 1557 03334 Total costs (time-slice) Rs Million 26718 167 944 682 4754 5192 5439 5370 4256 4256 4256 4256 4256

3536 Net flows Rs Million -17014 -167 -944 -1715 -4451 -3555 -3714 -3861 -1926 -1926 -1926 -1926 -192637 Economic rate of return, ERR negative

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17. In the case of the SAR, this approach of valuing benefits at the tariff worked because the assumption was made that the tariff would indeed increase at least in line with inflation. But what would have been the ERR if the SAR-expectations on tariff had in fact been achieved? Unfortunately this is not simply a matter of recalculating the revenue at the higher tariff, because the price-elasticity effect will change the quantity consumed: at the margin, a higher real price means reduced consumption, and hence a reduced level of benefits – though this will be partially offset by lower power purchase requirements.

18. Ignoring these complications, the resulting re-estimate is shown in Table 6. We assume an aggregate price elasticity of –0.3, which reduces sales as shown in row [8]; FY2003 sales would be 263 GWh lower than at the actual tariff. This value of aggregate price elasticity is consistent with the estimates in the literature on the sector.

Table 6: ERR at the Constant FY1996 Tariff

NPV FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04 FY05 FY06 FY07 FY08

1 Power sold at actual tariff GWh 5088 5440 5175 6262 6979 6605 6782 77162 Actual tariff, constant Rs Rs/kWh 2.27 2.44 2.36 2.16 2.13 2.27 2.18 2.023 Assumed price elasticity -0.34 Adjusted sales at constant tariff GWh 5088 5559 5239 6176 6853 6606 6700 74535 Constant tariff Rs/kWh 2.27 2.27 2.27 2.27 2.27 2.27 2.27 2.276 Revenue Rs Million 11534 12601 11876 14001 15536 14975 15188 168957 Incremental revenue, constant Rs Rs Million 0 -726 1399 2934 2373 2586 4293 4293 4293 4293 4293

8 Energy not sold GWh -119 -64 86 126 -1 82 2639 Average technical T&D losses 0.300 0.290 0.284 0.282 0.277 0.271 0.26910 Change in power purchase requirement GWh 170 90 -120 -175 1 -113 -35911 Actual power purchases GWh 9651 10324 10571 11197 12400 12467 12026 1218512 Power purchases at adjusted tariff GWh 9651 10494 10661 11077 12225 12468 11913 1182613 Economic cost of power Rs/kWh 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.514 Cost of power purchases Rs Million 14473 15737 15988 16611 18333 18698 17866 1773415 Incremental power purchase costs Rs Million 0 250.6 874 2596 2961 2129 1997 1997 1997 1997 19971617 Repairs and maintenance Rs Million 434 585 476 790 578 612 584 187118 Salaries and wages Rs Million 2381 2667 2771 3427 3300 3934 4116 404319 Admin. & general expenses Rs Million 334 336 310 914 913 1125 1698 113220 Total costs Rs Million 3149 3588 3557 5131 4791 5671 6398 704621 SCF22 Adjusted for SCF Rs Million 2834 3229 3201 4618 4312 5104 5758 634123 In constant Rs Rs Million 2834 3057 2858 3957 3488 3949 4318 452224 Incremental O&M costs Rs Million 0 -199 900 430.4 892.3 1260 1465 1465 1465 1465 14652526 Investment27 Investment programme Rs Million 6896 185 1108 636 3299 2265 1914 2307 028 Adjusted for SCF Rs Million 167 997 572 2969 2039 1723 2076 029 In constant Rs Rs Million 167 944 511 2544 1649 1333 1557 03031 Totalcosts (time-slice) Rs Million 23099 167 944 562 4319 4675 5186 4946 3462 3462 3462 3462 3462

3233 Net flows Rs Million -4384 -167 -944 -1288 -2920 -1741 -2813 -2360 831 831 831 831 83134 Economic rate of return, ERR 2.2%

- 34 -

19. At the (higher) constant tariff, the corresponding power purchase requirement in FY2003 is a further 359 GWh lower (row [10]), because of the additional avoidance of technical (but not non-technical) losses. The resulting ERR computes to 2.2%. While these returns are poor, at least from FY2004 onwards the economic flows are positive (in contrast to those shown in Table 5, which are negative over the entire 20-year lifetime).

Benefits based on consumer surplus/willingness-to-pay

20. It is clear that, for most consumption sectors, willingness to pay is substantially above the tariff. This follows directly from the demand curves. While it is true that demand curves are not known with any precision, given likely values of price elasticity one may reasonably estimate benefits taking into account consumer surplus. The benefit of some level of consumption may be taken as the average willingness to pay (so the net benefit is the difference between this average willingness to pay and the level of the tariff). The sensitivity analysis in the SAR (Annex 5.1) used this approach to define an alternative measure of benefits (as discussed above), for which the baseline ERR increased from 14.7% to 16.8% (SAR sensitivity analysis scenario #1).

21. Table 7 shows the ICR calculations for an average 2003 WTP of Rs 3.5 /kWh (corresponding to an appraisal year value of 2.62 Rs/kWh), and a 2003 economic cost of purchased power of Rs 2.00/kWh (corresponding to a FY1997 value of Rs 1.50/kWh). The ERR at this value of WTP is 11%.

Economic benefits of pilferage

22. The above estimate of economic benefits considers only paying customers. But in a system such as Orissa, a substantial part of “T&D losses” is in fact the consumption of pilferers (and consumption by those with defective meters). Clearly, pilferers derive economic benefit from their consumption, which merits consideration in economic analysis. While it may be true that the economic cost of supplying pilferers exceeds the economic benefits of pilferers’ consumption, to include the former but not the latter results in an underestimate of the net economic benefits. Based on an average pilferer’s WTP of Rs 0.87/kWh, one third of the Rs 2.62/kWh (in FY1997 Rs) assumed for paying customers, the ERR increases to 13.5%.

The Ib-Merramundali line

23. The Ib-Merramundali 400 kV line, and the associated substation at Merramundali, accounted for some Rs 1,406 million, or 10% of the total time-slice investment program of the (consolidated) T&D businesses. The line’s purpose is to evacuate power from a proposed IPP in the Ib Valley. This project was not in fact completed, and therefore the line has provided no economic benefits. When the costs of this line are subtracted from the investment program, the baseline ERR increases from 13.5% to 14.8%.

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Table 7: ERR, Benefits based on Consumer WTP

(Million Rs)FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04 FY05 FY06 FY07 FY08

Power sold GWh 5088 5440 5175 6262 6979 6605 6782 7716Incremental power sold GWh 0 -265 822 1539 1165 1342 2276WTP Rs/kWh 2.62 2.62 2.62 2.62 2.62 2.62 2.62 2.62Incremental economic benefit Rs Million 0 -695 2157 4039 3057 3522 5972 5972 5972 5972 5972

Incremental costs Rs Million 26718 167 944 682 4754 5192 5439 5370 4256 4256 4256 4256 4256

Net flows Rs Million -509 -167 -944 -1378 -2596 -1153 -2381 -1847 1717 1716 1716 1716 1716

Economic rate of return, ERR 11.0%

Memo items:WTP in current Rs 2.62 2.77 2.94 3.06 3.24 3.39 3.50 3.68Economic cost of purchased power at current prices 1.50 1.58 1.68 1.75 1.85 1.94 2.00 2.10

- 36 -

Annex 4. Bank Inputs

(a) Missions:Stage of Project Cycle Performance Rating No. of Persons and Specialty

(e.g. 2 Economists, 1 FMS, etc.)Month/Year Count Specialty

ImplementationProgress

DevelopmentObjective

Identification/Preparation

November 1-17, 1993

5 Sr. Energy Economist (1);Financial Analyst (1);R&R Specialist (1);Consultants (2)

April 9-27, 1994 8 Sr. Energy Economist/Task Manager (1);Financial Analyst (1);R&R Specialist (1);R&R Consultant (1);Restructuring Consultant (1);Power Engineer (1);Sr. Counsel (1);Regulatory Specialist (1)

September/October 1994

7 Sr. Energy Economist/Task Manager (1);R&R Specialist (1);R&R Consultant (1);Environment Consultant (1);Power Engineer (1);Restructuring Consultant (1);DSM Planner (1)

November/December 1994

10 Sr. Energy Economist/Task Manager (1);Environment Consultant (1);Restructuring Consultant (1);Energy Economist (1);Financial Analyst (1);Sr. Counsel (1);Counsel (1);Regulatory Specialist (1);Chief, Energy Opers Div (1);Pr. Financial Analyst (1)

- 37 -

Appraisal/Negotiation

February 13-28, 1995

18 Sr. Energy Economist/Task Manager (1);Energy Economist (1);Sr. Financial Analyst (1);Financial Analyst (2);Environment Consultant (1);Pvt. Power Consultant (1);Restructuring Consultant (1);Sr. Water Resrc Engr (1);Hydro Power Consultant (1);Environment Specialist (1);Sr. Operations Officer (1);DSM Planner (1);Consultants (5)

Supervision

June 1-8, 1996 2 Sr. Energy Economist/Task Manager (1);Financial Analyst (1)

S S

September 9-19, 1996

5 Sr. Energy Economist/Task Manager (1);Sr. Financial Analyst (2);Consultant (1);DSM Planner (1)

S S

December 1996 3 Sr. Energy Economist/Task Manager (1);Sr. Financial Analyst (1);Financial Analyst (1)

S S

March 12-15, 1997 3 Sr. Energy Economist/Task Manager (1);Sr. Power Engineer (1);Consultant (1)

S S

June 1997 4 Sr. Energy Economist/Task Manager (1);Sr. Power Engineer (1);Consultant (1);Financial Analyst (1)

S S

September 1997 4 Sr. Energy Economist/Task Manager (1);Consultant (1);Sr. Financial Analyst (1);Financial Analyst (1)

S S

- 38 -

December 1997 4 Sr. Financial Analyst/Co-Team Leader (1);Consultant (1);Financial Analyst (1);DSM Expert (1)

S S

March 4-6, 1998 3 Sr. Financial Analyst/Co-Team Leader (1);Consultant (1);Financial Analyst (1)

S S

June 17-21, 1998 4 Sr. Energy Economist/Task Team Leader (1);Consultant (1);Financial Analyst (1);Power Engineer (1)

S S

October 26-31, 1998

3 Principal Energy Specialist/Task Team Leader (1);Sr. Financial Analyst (1);Sr. Power Engineer (1)

S S

April 29 -May 1, 1999

3 Sr. Financial Analyst/Co-Team Leader (1);Financial Analyst (1);GRIDCO's Advisor (1)

S S

December 1999 3 Lead Specialist/Task Team Leader (1);Financial Analyst (1);Sector Director (1)

S S

March 2000 3 Lead Specialist/Task Team Leader (1);Financial Analyst (1);Power Engineer (1)

S S

June 2000 2 Financial Analyst/Task Team Leader (1);Lead Specialist (1)

S S

September 7-14, 2000

2 Financial Analyst/Task Team Leader (1);Sr. Financial Analyst (1)

S S

November 29 - December 14, 2000

3 Financial Analyst/Task Team Leader (1);Sr. Energy Specialist (1);Consultant Engineer (1)

S S

- 39 -

March 13-17, 2001 3 Financial Analyst/Task Team Leader (1);Lead Specialist (1);Consultant (1)

S S

June 21 - 26, 2001 4 Financial Analyst/Task Team Leader (1);Lead Specialist (1);Sr. Financial Mgnt Specialist (1);Consultant Engineer (1)

U U

September 2002 6 Sr. Financial Analyst/Task Team Leader (1);Sr. Energy Economist (1);Sr. Energy Specialist (1);Sr. Financial Mgnt Specialist (1);Procurement Analyst (1);Sr. Social Dev Specialist (1)

U U

November 11-13, 2002

11 Sr. Financial Analyst/Task Team Leader (1);Financial Mgnt Specialist (1);Sr. Energy Specialist (1);Sr. Energy Economist (1);Sr. Social Dev Specialist (1);Procurement Analyst (1);Sector Director (1);Sr. Economist (1);Environment Specialist (2);Financial Analyst (1)

U U

January 28 - 30, 2003

6 Sr. Financial Analyst/Task Team Leader (1);Financial Analyst (1);Research Analyst (1);Sr. Energy Specialist (1);Environment Specialist (1);Sr. Social Dev Specialist (1)

U U

August 19 - 21, 2003

7 Sr. Financial Analyst (1);Research Analyst (1);Sr. Energy Specialist (1);Environment Specialist (1);Sr. Social Dev Specialist (1);Sr. Financial Mgnt Specialist (1);Consultant Engineer (1)

U U

- 40 -

March 24 - 27, 2004

7 Sr. Financial Analyst/Task Team Leader (1);Sr. Financial Analyst (1);Research Analyst (1);Consultant Engineer (1);Environment Specialist (1);Sr. Social Dev Specialist (1);Sr. Financial Mgnt Specialist (1)

U U

ICR

August 2-11, 2004

7 Sr. Energy Specialist/ ICR Team Leader (1);Research Analyst (1);Consultant Engineer (1);Environment Specialist (1);Sr. Social Dev Speclst (1);Sr. Fincl Mgnt Speclst (1);Program Assistant (1)

DSM Planner = Demand-Side Management Planner

Note: Between formal missions in June 2001 and September 2002, there were numerous meetings between GOO officials and Bank Staff in Orissa and in Delhi.

(b) Staff:

Stage of Project Cycle Actual/Latest EstimateNo. Staff weeks US$ ('000)

Identification/Preparation 144.0 401.7Appraisal/Negotiation 115.6 329.9Supervision 386.0 1,181.7ICR 14.4 60.6Total 660.0 1,973.9

- 41 -

Annex 5. Ratings for Achievement of Objectives/Outputs of Components(H=High, SU=Substantial, M=Modest, N=Negligible, NA=Not Applicable)

RatingMacro policies H SU M N NASector Policies H SU M N NAPhysical H SU M N NAFinancial H SU M N NAInstitutional Development H SU M N NAEnvironmental H SU M N NA

SocialPoverty Reduction H SU M N NAGender H SU M N NAOther (Please specify) H SU M N NA

Private sector development H SU M N NAPublic sector management H SU M N NAOther (Please specify) H SU M N NA

- 42 -

Annex 6. Ratings of Bank and Borrower Performance

(HS=Highly Satisfactory, S=Satisfactory, U=Unsatisfactory, HU=Highly Unsatisfactory)

6.1 Bank performance Rating

Lending HS S U HUSupervision HS S U HUOverall HS S U HU

6.2 Borrower performance Rating

Preparation HS S U HUGovernment implementation performance HS S U HUImplementation agency performance HS S U HUOverall HS S U HU

- 43 -

Annex 7. List of Supporting Documents

1. OERC orders (available on www.orierc.org)2. Report of the Committee on Power Sector Reform of Orissa, October 20013. Progress reports from Gridco Project Management Unit4. All Aide Memoires.5. Staff Appraisl Report: Orissa Power Sector Restructuring Project, April 19, 19966. Orissa Power Sector Restructuring Project: Mid-Term Review Report, 20007. Economic Analysis: ICR (Peter Meier), December 20048. Statistical Reports from NESCO, SOUTHCO, WESCO, CESCO, GRIDCO, and OHPC9. Progress Report from Orissa Electricity Regulatory Commission, August 200410. State Power Sector Reform -- A Review of the Orissa Experience, by Frontier Economics, July 200011. Orissa: Revitalizing Power Reform. World Bank Presentation to Orissa's High-Powered Review Committee, June 2001

- 44 -

Additional Annex 8. Map

Map IBRD 26751 ind26751.pdf

- 45 -

Additional Annex 9. Financial Performance

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004Revenue from Sale of Power to Discoms 4402 13838 15868 16801 19037 20042Revenue from Sale of Power to Consumers/ Inter-State etc. 11534 13999 9287 1981 2542 2556 650 7815Non-Operational/ Other Income 449 518 564 1756 2158 1855 2185 2176

I Total Revenue 11983 14517 14252 17574 20569 21212 21871 30032Purchase of Power 9827 11998 12406 11656 13997 11878 16040 17466Repairs and Maintenance 434 585 476 790 578 612 584 1871Salaries and Wages 2381 2667 2771 3427 3300 3934 4116 4043Administrative & General Expenses 334 336 310 914 913 1125 1698 1132Net Prior Period Credit/ Charges 0 (118) 633 55 (41) 150 1044 (1319)Less: Expenses Capitalized (171) (243) (273) (296) (198) (84) (67) (141)

II Total Cash Operating Expenditure 12804 15225 16323 16547 18550 17616 23414 23051III Surplus after cash operating exp. (EBITDA) [I-II] (821) (708) (2071) 1027 2019 3596 (1542) 6981IV Provision for bad and doubtful debts 255 395 268 1322 1643 1943 2210 1549V Depreciation 1330 1417 1499 1576 1810 1953 2092 2145VI Interest and Financial Charges 1023 1258 1732 4220 5008 5468 6122 5568VII Less: Interest & Finance charges capitalised (365) (534) (361) (833) (644) (749) (772) (692)VIII Taxation 0 0 0 0 0 0 0 0IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (3064) (3244) (5210) (5259) (5799) (5019) (11194) (1589)

Revenue Subsidies & Grants 114 53 53 50 0 0 0 0Profit on sale of investments 0 0 0 443 0 0 0 0Loss of 4 discoms transferred 0 0 (629) 0 0 0 0 0Statutory appropriations 0 0 0 27 32 221 136 180

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004Assets

Gross Fixed Assets 20650 21758 22394 25693 27958 29872 32179 34840Less: Accumulated Depreciation (1330) (2746) (4245) (5245) (6330) (7572) (8841) (10173)Net Fixed Assets 19320 19012 18149 20449 21629 22300 23338 24667Capital Work in Progress 2147 3356 6570 8232 9531 10268 10767 11753Other Fixed Assets 0 0 0 0 0 0 0 0

I Total Fixed Assets 21467 22368 24719 28681 31160 32568 34104 36420II Miscellaneous expenses not w/o 8 27 89 77 65 52 26 15III Investments 2 2 8475 10987 10328 10538 11329 11517

Sundry Debtors 4032 6466 9230 15289 19867 27283 29665 32758Inventory 708 1231 975 1137 976 832 1071 1029Cash & Bank Balances 642 1252 2385 1202 1234 1078 1653 3381Loans & Advances 25 30 5815 8366 4562 4952 7031 9228Other Current Assets 571 655 890 959 5099 6206 7371 8588

IV Total Current Assets 5978 9634 19295 26953 31739 40350 46790 54984V Total Assets [I+II+III+IV] 27455 32031 52578 66698 73292 83508 92250 102936

LiabilitiesShare Capital 3437 3842 6829 7128 7131 7160 7179 7179Reserves & Surplus - incl. Subsidies & Grants 2244 2933 1453 2465 2592 4780 5564 6213Profit and Loss Account (2950) (6141) (11927) (16015) (21022) (25538) (36060) (37004)

Capital Contributions from Consumers 0 0 2009 2285 2155 2247 2399 2738VI Total Shareholders Funds 2731 634 (1637) (4138) (9144) (11351) (20917) (20874)VII Loans (Secured and Unsecured) 13510 15729 31844 36007 45857 56101 66221 74235

Accounts Payables towards towards Power Purchase 6023 8997 9179 15666 16891 19121 22094 21361Consumers' Security Deposits 950 1178 1302 1456 1971 1882 2245 2673Other Current Liabilities 3642 4847 5857 9082 10686 10032 13254 13548Working Capital (Short Term) Borrowings 0 0 0 1207 1740 1740 1740 1740Provisions 599 647 6034 7418 5289 5984 7613 10254

VIII Total Current Liabilities & Provisions 11214 15668 22371 34829 36578 38759 46946 49576IX Total Liabilities [VI+VII+VIII] 27455 32031 52578 66698 73292 83508 92250 102936

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004Power Purchased (MU) 9651 10324 10571 11197 12400 12467 12026 15774Transmission Loss (MU) 4563 4884 3744 551 642 645 615 617Distribution Loss (MU) 1652 4384 4779 5217 4629 4818Power Sold (MU) 5088 5440 5175 6262 6979 6605 6782 10339

o/w Inter State/ Other sales (MU) 0 0 0 650 894 830 48 3229Transmission & Distribution Loss (%) 47.3% 47.3% 51.0% 46.8% 47.1% 50.4% 43.8% 43.3%

(C) Transmission & Distribution Loss

ORISSA---Financial Performance of Transmission & Distribution Business

(A) Profit and Loss Account

(B) Balance Sheet

- 46 -

DISCOM---Page 1 of 2

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Revenue from Sale of Power 13838 15868 16801 19037 20042Non-Operational/ Other Income 493 584 630 728 698

I Total Revenue 14330 16452 17431 19764 20739Purchase of Power 12682 13972 15172 14751 15559Repairs and Maintenance 695 479 524 500 1784Salaries and Wages 2408 2279 2517 2637 2266Administrative & General Expenses 724 770 978 1547 975Net Prior Period Credit/ Charges 207 35 150 1239 1680Less: Expenses Capitalized (161) (75) (31) (30) (24)

II Total Cash Operating Expenditure 16557 17458 19309 20644 22241III Surplus after cash operating exp. (EBITDA) [I-II] (2227) (1006) (1878) (879) (1501)IV Provision for bad and doubtful debts 1322 1643 1943 2210 1549V Depreciation 845 998 1070 1154 1235VI Interest and Financial Charges 626 1284 1255 1293 1287VII Less: Interest & Finance charges capitalised (236) (138) (213) (230) (153)VIII Taxation 0 0 0 0 0IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (5256) (5069) (6359) (5766) (5725)

Revenue Subsidies & Grants 0 0 0 0 0Statutory appropriations 27 32 34 37 39

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Assets

Gross Fixed Assets 12786 13896 14973 15957 18099Less: Accumulated Depreciation (2539) (2871) (3237) (3632) (4054)Net Fixed Assets 10247 11025 11736 12325 14045Capital Work in Progress 2559 2265 2269 2402 2192Other Fixed Assets 0 0 0 0 0

I Total Fixed Assets 12807 13290 14005 14728 16237II Miscellaneous expenses not w/o 0 0 0 0 0III Investments 0 0 0 0 0

Sundry Debtors 4036 7201 9500 10830 12239Inventory 579 498 376 541 581Cash & Bank Balances 748 676 724 812 509Loans & Advances 8318 4293 4673 6829 9052Other Current Assets 73 2679 2679 2679 2679

IV Total Current Assets 13755 15348 17952 21690 25060V Total Assets [I+II+III+IV] 26561 28637 31957 36418 41297

LiabilitiesShare Capital 2249 2249 2249 2249 2249Reserves & Surplus - incl. Subsidies & Grants 223 255 830 1104 1382Retained Earnings (P&L A/c) (4225) (8379) (13640) (18182) (22827)

Capital Contributions from Consumers 2285 2155 2247 2399 2738VI Total Shareholders Funds 532 (3721) (8314) (12429) (16458)VII Loans (Secured and Unsecured) 8231 13338 14847 16556 20854

Accounts Payables towards towards Power Purchase 5015 6422 11941 13874 14540Consumers' Security Deposits 1456 1971 1882 2245 2673Other Current Liabilities 3753 4636 5246 8349 9520Working Capital (Short Term) Borrowings 1207 1740 1740 1740 1740Provisions 6366 4251 4615 6083 8427

VIII Total Current Liabilities & Provisions 17798 19020 25424 32292 36900IX Total Liabilities [VI+VII+VIII] 26561 28637 31957 36418 41297

Financial Performance of Distribution Business

(B) Balance Sheet

(A) Profit and Loss Account

- 47 -

DISCOM---Page 2 of 2

Financial Year Ending March 31 (Million Units) 2000 2001 2002 2003 2004I Power Purchase by Distribution Company 9987 10859 10990 11361 11937II Distribution Loss 4384 4779 5217 4629 4818III Total Power Sold to Retail Consumers 5603 6080 5773 6733 7119

Breakdown of Retail SalesLow Tension (LT)

Agriculture/ Irrigation 216 190 164 139 126Domestic 2027 2149 2244 2413 2428Commercial 406 430 453 467 475Industrial 201 201 198 199 199Others 167 193 193 192 192LT Total 3017 3163 3252 3410 3420

High Tension (HT)Commercial 0 0 0 0 5Industrial 959 1036 902 941 995Bulk Supply 30 32 42 48 55Others 198 213 242 207 242HT Total 1187 1281 1186 1196 1298

Extra High Tension (EHT)Industrial 1244 1455 1148 1885 2145Railway Traction 156 181 188 241 257Others 0 0 0 0 0EHT Total 1400 1636 1336 2126 2402

IV Grand Total (LT + HT + EHT) 5603 6080 5773 6733 7119V Number of consumers 1577941 1722468 1821994 1973790 2113269

- Domestic 1314843 1449842 1540483 1680997 1813134- Commercial 154308 167079 175215 185156 195769- Agricultural 47929 45803 43580 43618 41388- Industrial 22775 22999 22454 22561 22922- Others 38086 36745 40262 41458 40056

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004I Power Purchase Cost 12764 13972 15172 14751 15559II Average Bulk Supply Tariff (Rs/kWh) 1.28 1.29 1.38 1.30 1.30IV Total Collections from Retail Consumers 10988 12612 12864 15901 17414

Financial Year Ending March 31 2000 2001 2002 2003 2004I Distribution Loss 44% 44% 47% 41% 40%II Collection Efficiency 77% 77% 74% 80% 84%III AT&C 57% 57% 61% 52% 50%

(E) Aggregate Technical & Commercial Loss (AT&C)

(C) Energy Balance

(D) Commercial Performance

Financial Performance of Distribution Business

- 48 -

Page 1 of 2

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004Revenue from Sale of Power to Discoms 4402 12801 14125 15189 14756 15571Revenue from Sale of Power to Consumers/ Inter-State etc. 11534 13999 9287 1981 2542 2556 650 7815Non-Operational/ Other Income 449 518 564 1263 1574 1225 1457 1478

I Total Revenue 11983 14517 14252 16045 18242 18969 16863 24864Purchase of Power 9827 11998 12406 11656 13997 11878 16040 17466Repairs and Maintenance 434 585 476 95 99 88 84 87Salaries and Wages 2381 2667 2771 1019 1021 1417 1479 1777Administrative & General Expenses 334 336 310 190 143 147 151 156Net Prior Period Credit/ Charges 0 (118) 633 (152) (75) 1 (195) (2999)Less: Expenses Capitalized (171) (243) (273) (136) (122) (52) (37) (117)

II Total Cash Operating Expenditure 12804 15225 16323 12672 15063 13478 17521 16370III Surplus after cash operating exp. (EBITDA) [I-II] (821) (708) (2071) 3373 3178 5491 (658) 8494IV Provision for bad and doubtful debts 255 395 268 0 0 0 0 0V Depreciation 1330 1417 1499 731 813 882 938 910VI Interest and Financial Charges 1023 1258 1732 3594 3724 4213 4828 4281VII Less: Interest & Finance charges capitalised (365) (534) (361) (597) (506) (536) (543) (539)VIII Taxation 0 0 0 0 0 0 0 0IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (3064) (3244) (5210) (356) (852) 932 (5882) 3842

Revenue Subsidies & Grants 114 53 53 50 0 0 0 0Profit on sale of investments 0 0 0 443 0 0 0 0Loss of 4 discoms transferred 0 0 (629) 0 0 0 0 0Statutory appropriations 0 0 0 0 0 187 99 141

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004Assets

Gross Fixed Assets 20650 21758 11789 12907 14062 14900 16221 16741Less: Accumulated Depreciation (1330) (2746) (1968) (2706) (3458) (4336) (5209) (6119)Net Fixed Assets 19320 19012 9821 10201 10604 10564 11012 10622Capital Work in Progress 2147 3356 4160 5673 7267 7999 8364 9561Other Fixed Assets 0 0 0 0 0 0 0 0

I Total Fixed Assets 21467 22368 13981 15874 17871 18563 19377 20183II Miscellaneous expenses not w/o 8 27 89 77 65 52 26 15III Investments 2 2 8475 10987 10328 10538 11329 11517

Sundry Debtors 4032 6466 6679 11254 12666 17784 18835 20519Inventory 708 1231 408 558 478 456 530 448Cash & Bank Balances 642 1252 1821 454 557 354 841 2872Loans & Advances 25 30 103 48 270 278 202 176Other Current Assets 571 655 885 885 2420 3527 4692 5909

IV Total Current Assets 5978 9634 9895 13198 16391 22398 25100 29924V Total Assets [I+II+III+IV] 27455 32031 32440 40137 44654 51551 55831 61639

LiabilitiesShare Capital 3437 3842 4579 4879 4882 4910 4930 4930Reserves & Surplus - incl. Subsidies & Grants 2244 2933 1452 2242 2337 3950 4461 4831Profit and Loss Account (2950) (6141) (11927) (11790) (12642) (11897) (17878) (14177)

Capital Contributions from Consumers 0 0 0 0 0 0 0 0VI Total Shareholders Funds 2731 634 (5896) (4669) (5423) (3037) (8488) (4416)VII Loans (Secured and Unsecured) 13510 15729 25850 27776 32519 41254 49665 53380

Accounts Payables towards towards Power Purchase 6023 8997 7594 10651 10469 7180 8219 6821Consumers' Security Deposits 950 1178 0 0 0 0 0 0Other Current Liabilities 3642 4847 3875 5328 6051 4786 4905 4029Working Capital (Short Term) Borrowings 0 0 0Provisions 599 647 1017 1052 1039 1368 1530 1826

VIII Total Current Liabilities & Provisions 11214 15668 12486 17031 17559 13334 14654 12676IX Total Liabilities [VI+VII+VIII] 27455 32031 32440 40137 44654 51551 55831 61639

Financial Performance of GRIDCO

(B) Balance Sheet

(A) Profit and Loss Account

- 49 -

Page 2 of 2

Financial Year Ending March 31 (Million Units) 1997 1998 1999 2000 2001 2002 2003 2004

I Power Purchased 9,651 10,324 10,571 11,197 12,400 12,467 12,026 15,774

o/w Hydro Purchases 3,980 3,507 3,525 4,716 4,759 6,640 3,292 5,993

II Transmission Loss 4,563 4,884 3,744 551 642 645 615 617

III Total Power Sold 5088 5440 6827 10646 11758 11822 11411 15157

Breakdown of Sales

Retail Consumers 5,088 5,440 3,385

Inter-State Sales/ Trading 644 875 779 42 2,558

WESCO 2,691 2,872 2,981 3,355 3,782

NESCO 2,260 2,440 2,303 2,396 2,637

SOUTHCO 1,435 1,524 1,522 1,557 1,609

CESCO 3,611 4,028 4,187 4,056 3,900

Unscheduled Interchange (UI) - - - - - - - 662

CPP Sale - - - 6 19 51 6 9

IV Grand Total Sales 5,088 5,440 6,827 10,646 11,758 11,822 11,411 15,156

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004

I Power Purchase Cost 9,827 11,998 12,406 11,656 13,997 11,878 16,040 17,466

II Average Power Purchase Cost (Rs/kWh) 1.02 1.16 1.17 1.04 1.13 0.95 1.33 1.11

III Total Revenue Billed 11,534 13,999 13,689 14,782 16,667 17,744 15,406 23,386

IV Total Collections 9481 11119 11083 10438 12323 12329 13649 21237

(C) Energy Balance

(D) Commercial Performance

Financial Performance of GRIDCO

3,442

- 50 -

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Revenue from Sale of Power 4623 5844 6381 6669 6916Non-Operational/ Other Income 232 208 227 250 262

I Total Revenue 4855 6051 6608 6919 7178

Purchase of Power 4536 5109 5748 5306 5188Repairs and Maintenance 240 193 260 295 318Salaries and Wages 979 806 954 1059 1092Administrative & General Expenses 403 109 114 177 186Net Prior Period Credit/ Charges 134 10 86 1227 1680Less: Expenses Capitalized (78) (32) 0 0 0

II Total Cash Operating Expenditure 6214 6194 7162 8064 8465III Surplus after cash operating exp. (EBITDA) [I-II] (1359) (143) (554) (1146) (1287)IV Provision for bad and doubtful debts 195 221 278 317 323V Depreciation 261 329 365 395 422VI Interest and Financial Charges 0 360 336 357 387VII Less: Interest & Finance charges capitalised 0 0 (39) (48) (62)VIII Taxation 0 0 0 0 0IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (1815) (1052) (1493) (2167) (2357)

Revenue Subsidies & Grants 0 0 0 0 0Statutory appropriations 0 0 0 0 0

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Assets

Gross Fixed Assets 4299 4804 5199 5550 6235Less: Accumulated Depreciation (939) (1272) (1637) (2032) (2455)Net Fixed Assets 3360 3532 3562 3518 3780Capital Work in Progress 882 207 106 141 335Other Fixed Assets 0 0 0 0 0

I Total Fixed Assets 4242 3739 3668 3659 4116II Miscellaneous expenses not w/o 0 0 0 0 0III Investments 0 0 0 0 0

Sundry Debtors 1772 4352 5959 7075 8188Inventory 501 398 296 235 295Cash & Bank Balances 380 274 116 22 77Loans & Advances 2708 1917 4131 3980 6205Other Current Assets 73 2679 2679 2679 2679

IV Total Current Assets 5434 9619 13180 13991 17444V Total Assets [I+II+III+IV] 9676 13359 16848 17649 21559

LiabilitiesShare Capital 727 727 727 727 727Reserves & Surplus - incl. Subsidies & Grants 0 0 0 0 0Retained Earnings (P&L A/c) (1815) (2868) (4361) (6528) (8886)

Capital Contributions from Consumers 866 664 670 677 685VI Total Shareholders Funds (222) (1476) (2964) (5124) (7474)VII Loans (Secured and Unsecured) 3112 4146 4969 5630 9029

Accounts Payables towards towards Power Purchase 1785 3382 6111 8161 8816Consumers' Security Deposits 354 741 341 460 594Other Current Liabilities 2136 2399 2399 2399 2399Working Capital (Short Term) Borrowings 1207 1740 1740 1740 1740Provisions 1304 2428 4253 4383 6454

VIII Total Current Liabilities & Provisions 6786 10689 14843 17144 20004IX Total Liabilities [VI+VII+VIII] 9676 13359 16848 17649 21559

Financial Performance of CESCO

(B) Balance Sheet

(A) Profit and Loss Account

- 51 -

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Revenue from Sale of Power 3045 3281 3011 3668 3761Non-Operational/ Other Income 55 165 162 186 154

I Total Revenue 3100 3447 3173 3854 3914

Purchase of Power 2865 2950 3196 2983 3261Repairs and Maintenance 162 110 70 56 74Salaries and Wages 446 465 519 520 541Administrative & General Expenses 114 217 319 657 680Net Prior Period Credit/ Charges 9 9 33 1 0Less: Expenses Capitalized (27) (19) (14) (12) (13)

II Total Cash Operating Expenditure 3569 3732 4122 4204 4543III Surplus after cash operating exp. (EBITDA) [I-II] (469) (285) (949) (351) (629)IV Provision for bad and doubtful debts 386 501 457 667 393V Depreciation 186 218 239 263 288VI Interest and Financial Charges 173 301 301 277 179VII Less: Interest & Finance charges capitalised (70) (41) (42) (55) (11)VIII Taxation 0 0 0 0 0IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (1143) (1264) (1904) (1502) (1477)

Revenue Subsidies & Grants 0 0 0 0 0Statutory appropriations 9 11 12 13 14

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Assets

Gross Fixed Assets 2807 3075 3381 3703 4413Less: Accumulated Depreciation (538) (538) (538) (538) (538)Net Fixed Assets 2269 2537 2844 3166 3875Capital Work in Progress 419 565 630 710 324Other Fixed Assets 0 0 0 0 0

I Total Fixed Assets 2688 3103 3473 3875 4200II Miscellaneous expenses not w/o 0 0 0 0 0III Investments 0 0 0 0 0

Sundry Debtors 728 886 1286 1294 1298Inventory 38 34 24 21 32Cash & Bank Balances 121 139 162 271 34Loans & Advances 1822 1864 177 271 281Other Current Assets 0 0

IV Total Current Assets 2709 2924 1648 1857 1644V Total Assets [I+II+III+IV] 5396 6027 5121 5733 5844

LiabilitiesShare Capital 659 659 659 659 659Reserves & Surplus - incl. Subsidies & Grants 44 54 251 363 469Profit and Loss Account (967) (2023) (3700) (4952) (6155)

Capital Contributions from Consumers 477 503 552 599 673VI Total Shareholders Funds 213 (807) (2239) (3331) (4355)VII Loans (Secured and Unsecured) 1413 3160 3,472 3,903 4,157

Accounts Payables towards towards Power Purchase 1373 930 2,375 3,119 3,160Consumers' Security Deposits 292 316 457 472 590Other Current Liabilities 484 784 1,009 1,185 1,700Working Capital (Short Term) BorrowingsProvisions 1622 1643 47 384 592

VIII Total Current Liabilities & Provisions 3771 3674 3888 5160 6041IX Total Liabilities [VI+VII+VIII] 5396 6027 5121 5733 5844

Financial Performance of NESCO

(B) Balance Sheet

(A) Profit and Loss Account

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Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Revenue from Sale of Power 4121 4526 4894 6036 6487Non-Operational/ Other Income 106 120 132 158 165

I Total Revenue 4227 4646 5026 6194 6651

Purchase of Power 3458 4022 4244 4527 5100Repairs and Maintenance 159 103 101 80 119Salaries and Wages 540 552 571 585 634Administrative & General Expenses 77 233 366 399 109Net Prior Period Credit/ Charges 1 1 1 (13) 0Less: Expenses Capitalized (33) (15) (10) (13) (11)

II Total Cash Operating Expenditure 4202 4895 5273 5564 5950III Surplus after cash operating exp. (EBITDA) [I-II] 25 (249) (246) 630 701IV Provision for bad and doubtful debts 480 571 758 798 833V Depreciation 195 237 252 267 282VI Interest and Financial Charges 237 328 338 407 338VII Less: Interest & Finance charges capitalised (87) (54) (63) (72) (23)VIII Taxation 0 0 0 0 0IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (801) (1331) (1532) (770) (729)

Revenue Subsidies & Grants 0 0 0 0 0Statutory appropriations 9 11 12 13 14

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Assets

Gross Fixed Assets 3055 3254 3437 3672 4247Less: Accumulated Depreciation (563) (563) (563) (563) (563)Net Fixed Assets 2492 2691 2874 3110 3685Capital Work in Progress 671 797 782 859 729Other Fixed Assets 0 0 0 0 0

I Total Fixed Assets 3164 3488 3656 3969 4414II Miscellaneous expenses not w/o 0 0 0 0 0III Investments 0 0 0 0 0

Sundry Debtors 870 1278 1548 1688 1688Inventory 24 25 23 25 29Cash & Bank Balances 137 115 251 409 394Loans & Advances 2049 314 264 1419 1409Other Current Assets 0 0 0 0 0

IV Total Current Assets 3079 1731 2087 3541 3520V Total Assets [I+II+III+IV] 6243 5219 5743 7510 7934

LiabilitiesShare Capital 487 487 487 487 487Reserves & Surplus - incl. Subsidies & Grants 109 121 315 404 496Profit and Loss Account (613) (1716) (3007) (3523) (3983)

Capital Contributions from Consumers 490 514 530 572 700VI Total Shareholders Funds 473 (595) (1675) (2061) (2301)VII Loans (Secured and Unsecured) 1933 2939 3147 3573 4019

Accounts Payables towards towards Power Purchase 875 1411 2497 2593 2564Consumers' Security Deposits 560 627 724 920 1056Other Current Liabilities 642 807 928 2484 2596Working Capital (Short Term) BorrowingsProvisions 1760 29 122

VIII Total Current Liabilities & Provisions 3837 2875 4271 5998 6217IX Total Liabilities [VI+VII+VIII] 6243 5219 5743 7510 7934

Financial Performance of WESCO

(B) Balance Sheet

(A) Profit and Loss Account

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Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Revenue from Sale of Power 2048 2217 2514 2663 2878Non-Operational/ Other Income 99 91 109 134 117

I Total Revenue 2148 2308 2623 2798 2996Purchase of Power 1823 1891 1983 1935 2010Repairs and Maintenance 134 73 93 69Salaries and Wages 443 456 473 473Administrative & General Expenses 131 211 180 314Net Prior Period Credit/ Charges 63 15 30 23Less: Expenses Capitalized (22) (9) (7) (5)

II Total Cash Operating Expenditure 2571 2637 2752 2810 3282III Surplus after cash operating exp. (EBITDA) [I-II] (424) (329) (129) (13) (287)IV Provision for bad and doubtful debts 261 351 450 428 0V Depreciation 203 214 214 229 244VI Interest and Financial Charges 216 295 279 253 383VII Less: Interest & Finance charges capitalised (79) (42) (69) (55) (57)VIII Taxation 0 0 0 0 0IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (1025) (1146) (1003) (867) (857)

Revenue Subsidies & Grants 0 0 0 0 0Statutory appropriations 8 10 10 11 11

Financial Year Ending March 31 (Rs in million) 2000 2001 2002 2003 2004Assets

Gross Fixed Assets 2625 2763 2956 3031 3204Less: Accumulated Depreciation (499) (499) (499) (499) (499)Net Fixed Assets 2126 2264 2457 2532 2704Capital Work in Progress 588 695 751 693 803Other Fixed Assets 0 0 0 0 0

I Total Fixed Assets 2714 2959 3208 3225 3508II Miscellaneous expenses not w/o 0 0 0 0 0III Investments 0 0 0 0 0

Sundry Debtors 665 686 707 773 1066Inventory 17 42 33 260 226Cash & Bank Balances 111 149 195 111 3Loans & Advances 1739 197 102 1158 1157Other Current Assets 0 0 0 0 0

IV Total Current Assets 2533 1074 1037 2302 2451V Total Assets [I+II+III+IV] 5246 4033 4245 5527 5959

LiabilitiesShare Capital 377 377 377 377 377Reserves & Surplus - incl. Subsidies & Grants 70 80 264 337 417Profit and Loss Account (830) (1773) (2573) (3178) (3802)

Capital Contributions from Consumers 452 474 495 551 680VI Total Shareholders Funds 68 (843) (1437) (1914) (2328)VII Loans (Secured and Unsecured) 1774 3094 3259 3450 3649

Accounts Payables towards towards Power Purchase 982 699 959Consumers' Security Deposits 249 287 360 393 432Other Current Liabilities 492 645 911 2282 2825Working Capital (Short Term) BorrowingsProvisions 1681 150 193 1316 1382

VIII Total Current Liabilities & Provisions 3404 1782 2422 3990 4638IX Total Liabilities [VI+VII+VIII] 5246 4033 4245 5527 5959

Financial Performance of SOUTHCO

(B) Balance Sheet

(A) Profit and Loss Account

1272

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Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004 ProvRevenue from Sale of Power 1378 1734 1600 2198 2338 2153 1714 2303Non-Operational/ Other Income 76 21 43 128 118 55 44 46

I Total Revenue 1454 1755 1643 2325 2456 2208 1758 2350

Operational expenses 65 80 77 82 79 77 78 79Repairs and Maintenance 63 73 129 126 127 171 119 145Salaries and Wages 280 540 424 555 521 552 544 553Administrative & General Expenses 18 33 50 53 59 51 69 67Net Prior Period Credit/ Charges 0.2 12 87 (9) (3) 7 1 27Less: Expenses Capitalized (172) (244) (258) (127) (20) (8) (16) (17)

II Total Cash Operating Expenditure 254 494 509 680 763 850 795 853III Surplus after cash operating exp. (EBITDA) [I-II] 1200 1260 1134 1645 1693 1358 963 1496IV Depreciation 444 443 447 498 934 966 1010 1123V Interest and Financial Charges 294 1685 1059 1211 1142 476 423 368VI Less: Interest & Finance charges capitalised (237) (1645) (924) (568) (108) (45) (51) (56)VII Taxation 0 0 0 0 0 0 0 5VIII Profit/(Loss) after tax [III-IV-V+VI-VII] 699 778 552 504 (274) (39) (419) 57

Revenue Subsidies & Grants 0 0 0 0 0 0 0 0

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004 ProvAssets

Gross Fixed Assets 11128 11151 12833 24176 25118 26427 26568 26660Less: Accumulated Depreciation (444) (887) (1335) (1833) (2766) (3733) (4742) (5858)Net Fixed Assets 10684 10264 11497 22343 22352 22694 21826 20802Capital Work in Progress 8873 11817 12312 2338 1845 783 991 1526

I Total Fixed Assets 19557 22081 23809 24681 24197 23477 22817 22328II Miscellaneous expenses not w/o 6 5 3 2 0 0 17 14III Investments 0 0 500 500 500 500 500 500

Sundry Debtors 452 977 904 2207 2787 3205 3761 4278Inventory 45 55 96 86 105 195 212 199Cash & Bank Balances 327 360 742 344 341 735 492 694Loans & Advances 62 77 99 452 532 570 581 585Other Current Assets 38 17 30 43 86 83 83 170

IV Total Current Assets 924 1486 1871 3131 3851 4788 5129 5926V Total Assets [I+II+III+IV] 20487 23572 26183 28313 28548 28765 28464 28768

LiabilitiesShare Capital 3208 3208 3208 3208 3208 3208 3208 3208Reserves & Surplus 0 0 0 250 250 440 440 441Profit and Loss Account 699 1476 2029 2532 2258 2219 1800 1857

VI Total Shareholders Funds 3907 4684 5237 5990 5716 5867 5448 5506VII Loans (Secured and Unsecured) 15972 17933 19627 20994 21294 21074 20889 20774

Current Liabilities 585 642 723 729 814 1358 1588 1864Provisions 23 312 597 600 725 466 539 625

VIII Total Current Liabilities & Provisions 608 954 1320 1329 1538 1824 2127 2488IX Total Liabilities [VI+VII+VIII] 20487 23572 26183 28313 28548 28765 28464 28768

Financial Year Ending March 31 1997 1998 1999 2000 2001 2002 2003 2004I Installed Capacity (MW) 1237.5 1237.5 1261.5 1561.5 1711.5 1861.5 1861.5 1861.5II Net Sales (MU) 3626 3538 3280 4373 4441 6311 3025 5796

Financial Performance of OHPC

(B) Balance Sheet

(C) Energy Balance

(A) Profit and Loss Account

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Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004 ProvRevenue from Sale of Power 3253 3767 4057 4154 4010 3866 4515 4100Non-Operational/ Other Income 52 43 247 411 170 250 218 131

I Total Revenue 3305 3810 4304 4565 4180 4116 4733 4231

Raw Materials consumption 784 950 1153 1307 1253 1155 1196 1449Production expenses 95 107 159 154 149 146 92 163Power & Electricity Duty 28 34 23 40 84 59 66 72Rebate to GRIDCO 0 35 41 78 40 0 0 0Salaries and Wages 54 64 77 109 136 111 124 142Administrative & General Expenses 45 42 45 78 59 73 67 122Net Prior Period Credit/ Charges (17.3) 111 (5) 84 30 1 14 (11)Less: Expenses Capitalized (98) 7 (2) (4) (1) 0 0 0

II Total Cash Operating Expenditure 890 1351 1490 1846 1750 1545 1559 1937III Surplus after cash operating exp. (EBITDA) [I-II] 2415 2459 2814 2719 2430 2571 3174 2294IV Depreciation 404 812 829 846 848 837 832 587V Interest and Financial Charges 965 986 857 631 485 412 369 231VI Less: Interest & Finance charges capitalised 0 0 0 (2) (1) 0 0 0VII Taxation 0 0 0 0 116 101 155 113VIII Profit/(Loss) after tax [III-IV-V+VI-VII] 1046 661 1128 1244 983 1221 1817 1362

Dividend 338 0 1471 735 1471 1716 1471 1128

Financial Year Ending March 31 (Rs in million) 1997 1998 1999 2000 2001 2002 2003 2004 ProvAssets

Gross Fixed Assets 10566 10833 11006 11057 11074 11097 11127 11125Less: Accumulated Depreciation (825) (1637) (2465) (3349) (4196) (5024) (5856) (6423)Net Fixed Assets 9740 9196 8541 7708 6877 6073 5270 4702Capital Work in Progress 982 554 476 247 247 245 232 180

I Total Fixed Assets 10722 9750 9016 7955 7124 6319 5502 4882II Miscellaneous expenses not w/o 24 40 35 32 26 19 13 12III Investments 0 0 0 601 600 600 420 0

Sundry Debtors 1716 2336 1160 1521 1741 1977 2337 1374Inventory 244 344 316 495 487 514 510 379Cash & Bank Balances 320 141 3170 894 976 2552 1339 1730Loans & Advances 56 74 54 65 217 318 467 561Other Current Assets 111 10 2 2 8 2 1 3

IV Total Current Assets 2447 2905 4703 2978 3429 5362 4654 4046V Total Assets [I+II+III+IV] 13193 12695 13755 11565 11179 12300 10590 8939

LiabilitiesShare Capital 4500 4510 4902 4902 4902 4902 4902 4902Reserves & Surplus 21 21 722 784 894 1026 1208 1344Profit and Loss Account 969 1630 1013 1379 631 154 130 84

VI Total Shareholders Funds 5489 6161 6638 7065 6427 6083 6241 6331VII Loans (Secured and Unsecured) 6434 5465 4832 3187 2618 2387 1882 1263

Current Liabilities 898 698 653 497 397 427 413 253Provisions 371 371 1632 816 1737 3404 2054 1093

VIII Total Current Liabilities & Provisions 1269 1070 2286 1313 2134 3831 2467 1346IX Total Liabilities [VI+VII+VIII] 13193 12695 13755 11565 11179 12300 10590 8939

Financial Year Ending March 31 1997 1998 1999 2000 2001 2002 2003 2004 ProvI Installed Capacity (MW) 420 420 420 420 420 420 420 420

PLF 55% 63% 76% 86% 82% 71% 71% 82%Gross Generation (MU) 2029 2334 2804 3166 3001 2599 2618 3006Auxiliary Consumption (MU) 230 272 287 325 317 279 289 329

II Net Sales (MU) 1798 2062 2517 2840 2685 2320 2329 2678

Financial Performance of OPGC

(B) Balance Sheet

(C) Energy Balance

(A) Profit and Loss Account

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Additional Annex 10. Consolidated comments from the State Govt. and power sector entities in Orissa

Consolidated Comments received from State Government – Note that the comments which refer to issues which have been accepted and corrected in the document have not been reproduced.

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