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1 Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized Energy and Infrastructure ector Unit outh Asia Region Document of The World Bank FOR OFFICIAL UE ONLY IMPLEMENTATION COMPLETION REPORT (TF CPL CL-4014A) ON A LOAN IN THE AMOUNT OF U$350.0 MILLION TO THE GOVERNMENT OF INDIA FOR AN ORIA POWER ECTOR RETRUCTURING PROJECT December 9, 2004 Report No: 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.

2 CURRENCY EQUIVALENT (Exchange Rate Effective June 30, 2004) Currency Unit = Rupee (Rs) Rs 1.00 = U$ 0.02 U$ 1.00 = Rs FICAL YEAR April 1 - March 31 Measures and Equivalents 1 kilovolt (kv) = 1,000 volts 1 kilovolt-ampere (kva) = 1,000 volts-amperes 1 megawatt (MW) = 1,000 kilowatts = 1 million watts 1 kilowatt-hour (kwh) = 1,000 watt-hours 1 megawatt-hour (MWh) = 1,000 kilowatt-hours 1 gigawatt-hour (GWh) = 1,000,000 kilowatt-hours ABBREVIATION AND ACRONYM AE AE Transpower Incorporation BE Bombay uburban Electricity upply CA Country Assistance trategy CEC Calcutta Electric upply Corporation DM Demand-ide Management ERR Economic Rate of Return GOI Government of India GOO Government of Orissa GRIDCO Grid Corporation of Orissa HE Health, afety and Environment NTPC National Thermal Power Corporation OERC Orissa Electricity Regulatory Commission OHPC Orissa Hydro Power Corporation OPGC Orissa Power Generation Corporation OEB Orissa tate Electricity Board PLF Power Load Factor AR taff Appraisal Report CF tandard Conversion Factor WTP Willingness-to-Pay Vice President: Country Director ector Manager Task Team Leader/ICR Task Team Leader: Praful C. Patel Michael F. Carter Penelope J. Brook Judith K. Plummer/Alan F. Townsend

3 INDIA Orissa Power ector Restructuring Project CONTENT Page No. 1. Project Data 1 2. Principal Performance Ratings 1 3. Assessment of Development Objective and Design, and of Quality at Entry 2 4. Achievement of Objective and Outputs 4 5. Major Factors Affecting Implementation and Outcome ustainability Bank and Borrower Performance Lessons Learned Partner Comments Additional Information 18 Annex 1. Key Performance Indicators/Log Frame Matrix 19 Annex 2. Project Costs and Financing 20 Annex 3. Economic Costs and Benefits 22 Annex 4. Bank Inputs 31 Annex 5. Ratings for Achievement of Objectives/Outputs of Components 36 Annex 6. Ratings of Bank and Borrower Performance 37 Annex 7. List of upporting Documents 38 Annex 8. Map IBRD Annex 9. Financial Performance 40

4 Project ID: P Team Leader: Judith K. Plummer Project Name: Orissa Power ector Restructuring Project TL Unit: AEI ICR Type: Core ICR Report Date: December 29, Project Data Name: Orissa Power ector Restructuring Project L/C/TF Number: TF-20006; CPL-40140; CL-4014A Country/Department: INDIA Region: outh Asia Regional Office ector/subsector: Power (99%); ub-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 (); tate enterprise/bank restructuring and privatization () KEY DATE Original Revised/Actual PCD: 06/06/1994 Effective: 09/24/ /24/1996 Appraisal: 00/00/0000 MTR: 05/14/ /14/1999 Approval: 05/14/1996 Closing: 12/31/ /30/2004 Borrower/Implementing Agency: Other Partners: GOVERNMENT OF INDIA/GOVERNMENT OF ORIA TAFF Current At Appraisal Vice President: Praful C. Patel D. Joseph Wood Country Director: Michael F. Carter Heinz Vergin ector Manager: Penelope J. Brook Jean-Francois Bauer Team Leader at ICR: Judith K. Plummer Kari J. Nyman ICR Primary Author: Alan Townsend 2. Principal Performance Ratings (H=Highly atisfactory, =atisfactory, U=Unsatisfactory, HL=Highly Likely, L=Likely, UN=Unlikely, HUN=Highly Unlikely, HU=Highly Unsatisfactory, H=High, U=ubstantial, M=Modest, N=Negligible) Outcome: ustainability: Institutional Development Impact: Bank Performance: Borrower Performance: U UN M U U QAG (if available) Quality at Entry: Project at Risk at Any Time: Yes ICR * The loan was suspended from July 9, 2001 until January 23, 2002.

5 The Orissa Power ector 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. ervice quality has improved. But one private distribution company (CECO) 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 Assessment: The Project Development Objectives were highly relevant in the Orissa context at that time. In 1993, the Orissa tate Electricity Board (OEB) was the worst performing EB 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 - 2 -

6 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. OEB 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. tate-level power sector interventions were an essential component of the Bank s country assistance strategy (CA) 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 FY 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: Reinforcing and Rehabilitating the Transmission and Distribution ystems and Developing Private Power Distribution (U$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. ub-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 Demand-ide Management (U$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,

7 three phase meters for other large customers, and 600,000 single phase meters for small consumers Institutional Development, Training, and Technical Assistance (U$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 DM management, and staff rationalization and training 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 The weak institutional capacity of OEB might have argued for greater selectivity in sub-project selection this is especially true of the non-metering parts of the DM 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 DM 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: atisfactory. Reform aspects in particular were very well prepared the Orissa - 4 -

8 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 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 OEB, including Grid Corporation of Orissa (Gridco, upon formation including transmission and distribution assets) and Orissa Hydropower Corporation (OHPC). Capacity at Gridco and in the tate 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 DM 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. ince privatization of distribution, no direct subsidy has been paid to the sector. ales 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. FY Table 1: Financial Performance of the Power ector (T&D only) EBID Net Profit Rs Billion Rs Billion - 5 -

9 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 On the institutional side, the project: a) unbundled the Orissa tate 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, AE of the United tates. All of the above was accomplished by These are very significant accomplishments. Indeed, the sales of the distribution companies actually happened well ahead of plan because of the failure, in , 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 ector (%) Financial Year Collection efficiency Transmission and distribution (T&D) loss Aggregate technical & commercial (AT&C) loss 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. ince then, household tariffs have not been - 6 -

10 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. ales 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. o 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 Objective 2: upporting 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 tate 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 OEB, 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 - 7 -

11 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) 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 OEB, 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 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 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) 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. imilarly, Gridco had initiated Health, afety and Environment (HE) audits of substations and transmission lines, but this too was discontinued by Gridco after August

12 4.2 Outputs by components: The overall rating is Unsatisfactory, based on the following assessments of the components: Reinforcing and Rehabilitating the Transmission and Distribution ystems 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 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 AE pulled out of CECO. Only at the end of the project have BE (now Reliance Energy) and, possibly, AE, 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 Demand-ide 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 Institutional Development, Training, and Technical Assistance. atisfactory. 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). upport 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 - 9 -

13 stakeholders

14 4.3 Net Present Value/Economic rate of return: 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 AR indicated robustness to the main uncertainties, with ERR in the range of 12.5% to 16.8%. No financial return was estimated in the taff Appraisal Report (AR) 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.] Nominal Rs/kWh Constant 96 Rs Nominal Rs Constant 96Rs FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY 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 FY ). 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

15 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 FY 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. ince 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: 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 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 (WECO); 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 WECO. 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

16 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: The super-cyclone of late 1999 was a serious blow to the project. This major storm made a direct hit on the CECO territory only months after AE 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. AE, in a sense, never really recovered from the effects of the cyclone on CECO s business, and subsequently withdrew from CECO 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 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 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: 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 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

17 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 tate 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 BE 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 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. ustainability 6.1 Rationale for sustainability rating: ustainability is unlikely without significant operational, policy, and regulatory changes. There are threats to both the reform and investment programs Reform program: While it is substantially unlikely that the de jure unbundling of OEB will be reversed, de facto re-integration may well occur if private distribution operators are

18 unviable. Already, the major distributor in the state, CECO, operates under an administrator appointed by OERC since 2001 when the private operator left. It is possible that AE will return to manage CECO anew, but there is much uncertainty surrounding this prospect. imilarly, 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 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. ervice 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 AR 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. taff Appraisal Report 1996: Projections (GWh) ^ 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) ^ 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 AR; 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

19 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 Bank 7.1 Lending: atisfactory. 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. econd, 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 DM 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 upervision: Unsatisfactory. upervision 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. upervision 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 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

20 7.3 Overall Bank performance: Unsatisfactory. Borrower 7.4 Preparation: atisfactory. Political commitment in particular was decisive in seeing this project get off the ground in the first place. OEB/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 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: 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 BE 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 CECO, due to management walkout, appointment of an administrator by GOO and dissension between the two faction in the board, the

21 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 U$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 ocial and Environmental afeguards: 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. ubsequently, 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 trong ownership of a reform program is essential for success, but the program must be grounded 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

22 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, financeable 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 operating 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 should 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 financial 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 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 as 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

23 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 will 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 regulatory approaches; private tolerance for losses is quite limited. AE and BE/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. ecuritization 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 expectations. 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. BE/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 BE/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 which a healthy sector could yet emerge. The state's power sector is at an important

24 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 tate 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 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: CECO Benefits of the project: Power interruption has been drastically reduced from some days to some hours; transformer failure has been reduced from 19% ( ) to 10% ( ); 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

25 on-going reform process of Gridco there was delay in handing over project activities to CECO, and as CECO was not fully organized, implementation was delayed at the outset; AE took over management of CECO and investment of fund stood in the way of implementation of the project; the super cyclone damaged the economic backbone of CECO and delayed implementation. uspension of the World Bank loan further delayed implementation. Uncertainty of funds and management changes were the main causes of implementation delays. OUTHCO 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 upplier/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. outhco also suffers from theft of conductors and tower components in completed works. NECO Benefits: Overall distribution loss has been reduced from 65% to 60% from to 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

26 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 tate Electricity Board improve its management through an institutional support programme. hortly 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. ome 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): AE, encouraged by World Bank s involvement in the power-sector reform of Orissa, took the majority control of CECO 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 CECO; (3) GoO would pay the past arrears as well as current dues to CECO for the energy consumed by various Government departments; (4) GRIDCO and GoO would cooperate and provide support, including police support, for CECO s efforts to reduce theft. Each and every legitimate expectation was thwarted by GRIDCO and GoO. At every turn, GRIDCO and GoO made CECO s job nearly impossible by interfering in the management of CECO s operations, including forced transfer and redeployment of employees (even for political activities unrelated to CECO) and preventing necessary commercial practices like the disconnection of defaulting customers, and finally agitating a multiple number of

27 litigations against AE before multiple fora i.e. Arbitrator, Courts and OERC on a single frivolous issue that CECO s dues to GRIDCO to be assumed by AE as an investor in CECO. Unfortunately, World Bank could not make GoO accountable for the reform. Despite World Bank continuing to provide tructural Adjustment Loan ( AL ) 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 GoO dues to CECO on account of energy bill have been piling up as before. AE believes that World Bank can play a constructive role to make reform a success by linking release of AL to GoO s accountability to and demonstration of successful power-sector reform. Recently, AE committed additional funding for CECO s future operations subject to all stakeholders acceptance of a sustainable business plan to insure CECO s financial viability. AE 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 ee Annex

28 Annex 1. Key Performance Indicators/Log Frame Matrix Outcome / Impact Indicators: Indicator/Matrix Projected in last PR 1 Actual/Latest Estimate (a) Establishment of GRIDCO, OHPC and the Regulatory Commission. (b) Enactment of legislation and regulations. (c) Licensing of GRIDCO and the distribution companies. (d) Privatization of GRIDCO's distribution system. (e) Listing and disinvestment of GRIDCO's and OHPC's shares December Given on time. eptember No financial case for this at present. Output Indicators: Indicator/Matrix Projected in last PR 1 Actual/Latest Estimate (a) Finalization of GRIDCO's and ODHPC's personnel policies and establishment of their own staff cadres. April 1997 (b) atisfactory financial performance of GRIDCO and OHPC. Targets not met (c) Budgeting of the Regulatory Commission. Target met in all years (d) taffing 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 DM activities, metering has made steady progress (h) Integration of environmental considerations into the implementation of GRIDCO's investments. Not yet sufficient 1 (i) Rehabilitation of Orissa's existing old thermal power station. (j) Environmental/ watershed management by OHPC. End of project Targets improvement have been met and continues to be met. tudy carried out and implemented by OHPC

29 Annex 2. Project Costs and Financing Project Cost by Component (in U$ million equivalent) Appraisal Estimate Actual/Latest Estimate Percentage of Appraisal Component U$ million U$ million Transmission and Distribution ystems Demand-sideManagement Institutional Development, Technical Assistance and Training Total Baseline Cost Physical Contingencies Price Contingencies Total Project Costs Interest during construction Total Financing Required Note: 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 ($225.5-million). Project Costs by Procurement Arrangements (Appraisal Estimate) (U$ million equivalent) Expenditure Category ICB Procurement Method 1 NCB Other 2 N.B.F. Total Cost 1. Works (75.00) (5.00) (0.00) (0.00) (80.00) 2. Goods (235.00) (20.00) (5.00) (0.00) (260.00) 3. ervices Implementation upport (0.00) (0.00) (4.50) (0.00) (4.50) 4. Policy upport (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) (0.00) (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 (310.00) (25.00) (15.00) (0.00) (350.00)

30 Project Costs by Procurement Arrangements (Actual/Latest Estimate) (U$ million equivalent) Expenditure Category ICB Procurement Method 1 NCB Other 2 N.B.F. Total Cost 1. Works (28.30) (0.00) (0.00) (0.00) (28.30) 2. Goods (181.60) (1.49) (0.15) (0.00) (183.24) 3. ervices Implementation upport (0.00) (0.00) (3.04) (5.52) (8.56) 4. Policy upport (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 (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

31 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 taff Appraisal Report (AR) 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 FY 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 (DM) 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 (CF) 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 CF. 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 AR 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 AR economic analysis (Table 1). The ERR was estimated at 14.5%. Table 1: AR Economic Analysis (Million Rs) NPV Investment Program Thermal Hydro T&D Operating Costs O&M Fuel Power Purchases Total Costs Total revenue Net benefits ERR 14.4% Note: Calculations extend to FY2022; for clarity we show only to FY

32 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. uch 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 AR, 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 DICOMs. 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 (ummary, in Rs million) FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04 F05 Total NA NA Total IBRD as % 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 AR 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

33 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 AR economic analysis, i.e. by evaluating the incremental streams of financial costs and benefits attributable to the FY 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 DICOM (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 ale of Power 1 Power sold 2 to DICOM/[customers] GWh Inter-state sales GWh Total GWh to DICOM Rs Million to Consumers/Inter-state sales Rs Million Total revenue from sale of power Rs Million Incremental Revenue Rs Million Tariffs 10 to DICOM Rs/kWh to Consumers/Inter-state sales Rs/kWh Overall Rs/kWh Power Purchase Costs 15 Purchased power GWh Purchase of power Rs Million Rs/kWh Incremental purchase costs Rs Million O&M Costs 21 Repairs and maintenance Rs Million alaries and wages Rs Million Admin. & general expenses Rs Million Total costs Rs Million Rs/kWh Incremental O&M costs Rs Million Investment 29 Investment programme Rs Million Total (incremental) costs Rs Million Net flows Rs Million Financial rate of return, nominal Rs 20% 35 Deflator Net flows, constant 1996 Rs Rs Million 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 DICOMs and interstate customers. The incremental operating costs [rows

34 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 DICOM, 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 AR), 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 FY

35 3 2.8 Nominal 2.6 Rs/kWh Constant 96 Rs FY97 FY98 FY99 FY00 FY01 FY02 FY03 FY04 Nominal Rs Constant 96Rs 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 AR methodology of taking economic benefits at the tariff. Table 4: Orissa Tariffs Units/Month (FY99) (FY00) (FY01) (FY02) (FY03) (FY04) Effective From 1-Dec-98 1-Feb-00 1-Feb-01 1-May-02 1-Dec-03 Domestic < = > 100 and < = > Commercial < = > 100 and 360 < = > 200 and < = 300 > Irrigation -- LT LT -- mall Industry LT -- Medium/Large Industry HT -- Industry

36 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 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 FY inflation rates Deflator Revenue from sale of power 5 to DICOM Rs Million to Consumers/Inter-state sales Rs Million Total revenue from sale of power Rs Million In constant Rs Rs Million Incremental revenue, constant Rs Rs Million Power sold GWh Average selling price Rs/kWh In constant Rs Rs/kWh O&M Costs 15 Ppower purchased GWh Economic cost of power Rs/kWh Cost of power purchases (constant Rs) Rs Million Incremental power purchase costs Rs Million Repairs and maintenance Rs Million alaries and wages Rs Million Admin. & general expenses Rs Million Total costs Rs Million CF 25 Adjusted for CF Rs Million Incremental O&M costs Rs Million In constant Rs Rs Million Investment 30 Investment programme Rs Million Adjusted for CF Rs Million In constant Rs Rs Million Total costs (time-slice) Rs Million Net flows Rs Million Economic rate of return, ERR negative

37 17. In the case of the AR, 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 AR-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 Actual tariff, constant Rs Rs/kWh Assumed price elasticity Adjusted sales at constant tariff GWh Constant tariff Rs/kWh Revenue Rs Million Incremental revenue, constant Rs Rs Million Energy not sold GWh Average technical T&D losses Change in power purchase requirement GWh Actual power purchases GWh Power purchases at adjusted tariff GWh Economic cost of power Rs/kWh Cost of power purchases Rs Million Incremental power purchase costs Rs Million Repairs and maintenance Rs Million alaries and wages Rs Million Admin. & general expenses Rs Million Total costs Rs Million CF 22 Adjusted for CF Rs Million In constant Rs Rs Million Incremental O&M costs Rs Million Investment 27 Investment programme Rs Million Adjusted for CF Rs Million In constant Rs Rs Million Totalcosts (time-slice) Rs Million Net flows Rs Million Economic rate of return, ERR 2.2%

38 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 AR (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% (AR 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%

39 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 Incremental power sold GWh WTP Rs/kWh Incremental economic benefit Rs Million Incremental costs Rs Million Net flows Rs Million Economic rate of return, ERR 11.0% Memo items: WTP in current Rs Economic cost of purchased power at current prices

40 Annex 4. Bank Inputs (a) Missions: tage of Project Cycle No. of Persons and pecialty (e.g. 2 Economists, 1 FM, etc.) Month/Year Count pecialty Identification/Preparation Performance Rating Implementation Progress Development Objective November 1-17, r. Energy Economist (1); Financial Analyst (1); R&R pecialist (1); Consultants (2) April 9-27, r. Energy Economist/Task Manager (1); Financial Analyst (1); R&R pecialist (1); R&R Consultant (1); Restructuring Consultant (1); Power Engineer (1); r. Counsel (1); Regulatory pecialist (1) eptember/october 1994 November/ December r. Energy Economist/Task Manager (1); R&R pecialist (1); R&R Consultant (1); Environment Consultant (1); Power Engineer (1); Restructuring Consultant (1); DM Planner (1) 10 r. Energy Economist/Task Manager (1); Environment Consultant (1); Restructuring Consultant (1); Energy Economist (1); Financial Analyst (1); r. Counsel (1); Counsel (1); Regulatory pecialist (1); Chief, Energy Opers Div (1); Pr. Financial Analyst (1)

41 Appraisal/Negotiation February 13-28, r. Energy Economist/Task Manager (1); Energy Economist (1); r. Financial Analyst (1); Financial Analyst (2); Environment Consultant (1); Pvt. Power Consultant (1); Restructuring Consultant (1); r. Water Resrc Engr (1); Hydro Power Consultant (1); Environment pecialist (1); r. Operations Officer (1); DM Planner (1); Consultants (5) upervision June 1-8, r. Energy Economist/Task Manager (1); Financial Analyst (1) eptember 9-19, r. Energy Economist/Task Manager (1); r. Financial Analyst (2); Consultant (1); DM Planner (1) December r. Energy Economist/Task Manager (1); r. Financial Analyst (1); Financial Analyst (1) March 12-15, r. Energy Economist/Task Manager (1); r. Power Engineer (1); Consultant (1) June r. Energy Economist/Task Manager (1); r. Power Engineer (1); Consultant (1); Financial Analyst (1) eptember r. Energy Economist/Task Manager (1); Consultant (1); r. Financial Analyst (1); Financial Analyst (1)

42 December r. Financial Analyst/Co-Team Leader (1); Consultant (1); Financial Analyst (1); DM Expert (1) March 4-6, r. Financial Analyst/Co-Team Leader (1); Consultant (1); Financial Analyst (1) June 17-21, r. Energy Economist/Task Team Leader (1); Consultant (1); Financial Analyst (1); Power Engineer (1) October 26-31, Principal Energy pecialist/task Team Leader (1); r. Financial Analyst (1); r. Power Engineer (1) April 29 -May 1, r. Financial Analyst/Co-Team Leader (1); Financial Analyst (1); GRIDCO's Advisor (1) December Lead pecialist/task Team Leader (1); Financial Analyst (1); ector Director (1) March Lead pecialist/task Team Leader (1); Financial Analyst (1); Power Engineer (1) June Financial Analyst/Task Team Leader (1); Lead pecialist (1) eptember 7-14, Financial Analyst/Task Team Leader (1); r. Financial Analyst (1) November 29 - December 14, Financial Analyst/Task Team Leader (1); r. Energy pecialist (1); Consultant Engineer (1)

43 March 13-17, Financial Analyst/Task Team Leader (1); Lead pecialist (1); Consultant (1) June 21-26, Financial Analyst/Task Team Leader (1); Lead pecialist (1); r. Financial Mgnt pecialist (1); Consultant Engineer (1) eptember r. Financial Analyst/Task Team Leader (1); r. Energy Economist (1); r. Energy pecialist (1); r. Financial Mgnt pecialist (1); Procurement Analyst (1); r. ocial Dev pecialist (1) U U U U November 11-13, r. Financial Analyst/Task Team Leader (1); Financial Mgnt pecialist (1); r. Energy pecialist (1); r. Energy Economist (1); r. ocial Dev pecialist (1); Procurement Analyst (1); ector Director (1); r. Economist (1); Environment pecialist (2); Financial Analyst (1) U U January 28-30, r. Financial Analyst/Task Team Leader (1); Financial Analyst (1); Research Analyst (1); r. Energy pecialist (1); Environment pecialist (1); r. ocial Dev pecialist (1) U U August 19-21, r. Financial Analyst (1); Research Analyst (1); r. Energy pecialist (1); Environment pecialist (1); r. ocial Dev pecialist (1); r. Financial Mgnt pecialist (1); Consultant Engineer (1) U U

44 March 24-27, r. Financial Analyst/Task Team Leader (1); r. Financial Analyst (1); Research Analyst (1); Consultant Engineer (1); Environment pecialist (1); r. ocial Dev pecialist (1); r. Financial Mgnt pecialist (1) U U ICR August 2-11, r. Energy pecialist/ ICR Team Leader (1); Research Analyst (1); Consultant Engineer (1); Environment pecialist (1); r. ocial Dev peclst (1); r. Fincl Mgnt peclst (1); Program Assistant (1) DM Planner = Demand-ide Management Planner Note: Between formal missions in June 2001 and eptember 2002, there were numerous meetings between GOO officials and Bank taff in Orissa and in Delhi. (b) taff: tage of Project Cycle Actual/Latest Estimate No. taff weeks U$ ('000) Identification/Preparation Appraisal/Negotiation upervision ,181.7 ICR Total ,

45 Annex 5. Ratings for Achievement of Objectives/Outputs of Components (H=High, U=ubstantial, M=Modest, N=Negligible, NA=Not Applicable) Rating Macro policies H U M N NA ector Policies H U M N NA Physical H U M N NA Financial H U M N NA Institutional Development H U M N NA Environmental H U M N NA ocial Poverty Reduction H U M N NA Gender H U M N NA Other (Please specify) H U M N NA Private sector development H U M N NA Public sector management H U M N NA Other (Please specify) H U M N NA

46 Annex 6. Ratings of Bank and Borrower Performance (H=Highly atisfactory, =atisfactory, U=Unsatisfactory, HU=Highly Unsatisfactory) 6.1 Bank performance Rating Lending H U HU upervision H U HU Overall H U HU 6.2 Borrower performance Rating Preparation H U HU Government implementation performance H U HU Implementation agency performance H U HU Overall H U HU

47 Annex 7. List of upporting Documents 1. OERC orders (available on 2. Report of the Committee on Power ector Reform of Orissa, October Progress reports from Gridco Project Management Unit 4. All Aide Memoires. 5. taff Appraisl Report: Orissa Power ector Restructuring Project, April 19, Orissa Power ector Restructuring Project: Mid-Term Review Report, Economic Analysis: ICR (Peter Meier), December tatistical Reports from NECO, OUTHCO, WECO, CECO, GRIDCO, and OHPC 9. Progress Report from Orissa Electricity Regulatory Commission, August tate Power ector Reform -- A Review of the Orissa Experience, by Frontier Economics, July Orissa: Revitalizing Power Reform. World Bank Presentation to Orissa's High-Powered Review Committee, June

48 Additional Annex 8. Map Map IBRD ind26751.pdf

49 Additional Annex 9. Financial Performance ORIA---Financial Performance of Transmission & Distribution Business (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Revenue from ale of Power to Discoms Revenue from ale of Power to Consumers/ Inter-tate etc Non-Operational/ Other Income I Total Revenue Purchase of Power Repairs and Maintenance alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges 0 (118) (41) (1319) Less: Expenses Capitalized (171) (243) (273) (296) (198) (84) (67) (141) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] (821) (708) (2071) (1542) 6981 IV Provision for bad and doubtful debts V Depreciation VI Interest and Financial Charges VII Less: Interest & Finance charges capitalised (365) (534) (361) (833) (644) (749) (772) (692) VIII Taxation IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (3064) (3244) (5210) (5259) (5799) (5019) (11194) (1589) Revenue ubsidies & Grants Profit on sale of investments Loss of 4 discoms transferred 0 0 (629) tatutory appropriations (B) Balance heet Financial Year Ending March 31 (Rs in million) Assets Gross Fixed Assets Less: Accumulated Depreciation (1330) (2746) (4245) (5245) (6330) (7572) (8841) (10173) Net Fixed Assets Capital Work in Progress Other Fixed Assets I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus - incl. ubsidies & Grants Profit and Loss Account (2950) (6141) (11927) (16015) (21022) (25538) (36060) (37004) Capital Contributions from Consumers VI Total hareholders Funds (1637) (4138) (9144) (11351) (20917) (20874) VII Loans (ecured and Unsecured) Accounts Payables towards towards Power Purchase Consumers' ecurity Deposits Other Current Liabilities Working Capital (hort Term) Borrowings Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII] (C) Transmission & Distribution Loss Financial Year Ending March 31 (Rs in million) Power Purchased (MU) Transmission Loss (MU) Distribution Loss (MU) Power old (MU) o/w Inter tate/ Other sales (MU) Transmission & Distribution Loss (%) 47.3% 47.3% 51.0% 46.8% 47.1% 50.4% 43.8% 43.3%

50 Financial Performance of Distribution Business DICOM---Page 1 of 2 (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Revenue from ale of Power Non-Operational/ Other Income I Total Revenue Purchase of Power Repairs and Maintenance alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges Less: Expenses Capitalized (161) (75) (31) (30) (24) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] (2227) (1006) (1878) (879) (1501) IV Provision for bad and doubtful debts V Depreciation VI Interest and Financial Charges VII Less: Interest & Finance charges capitalised (236) (138) (213) (230) (153) VIII Taxation IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (5256) (5069) (6359) (5766) (5725) Revenue ubsidies & Grants tatutory appropriations (B) Balance heet Financial Year Ending March 31 (Rs in million) Assets Gross Fixed Assets Less: Accumulated Depreciation (2539) (2871) (3237) (3632) (4054) Net Fixed Assets Capital Work in Progress Other Fixed Assets I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus - incl. ubsidies & Grants Retained Earnings (P&L A/c) (4225) (8379) (13640) (18182) (22827) Capital Contributions from Consumers VI Total hareholders Funds 532 (3721) (8314) (12429) (16458) VII Loans (ecured and Unsecured) Accounts Payables towards towards Power Purchase Consumers' ecurity Deposits Other Current Liabilities Working Capital (hort Term) Borrowings Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII]

51 Financial Performance of Distribution Business (C) Energy Balance DICOM---Page 2 of 2 Financial Year Ending March 31 (Million Units) I Power Purchase by Distribution Company II Distribution Loss III Total Power old to Retail Consumers Breakdown of Retail ales Low Tension (LT) Agriculture/ Irrigation Domestic Commercial Industrial Others LT Total High Tension (HT) Commercial Industrial Bulk upply Others HT Total Extra High Tension (EHT) Industrial Railway Traction Others EHT Total IV Grand Total (LT + HT + EHT) V Number of consumers Domestic Commercial Agricultural Industrial Others (D) Commercial Performance Financial Year Ending March 31 (Rs in million) I Power Purchase Cost II Average Bulk upply Tariff (Rs/kWh) IV Total Collections from Retail Consumers (E) Aggregate Technical & Commercial Loss (AT&C) Financial Year Ending March I Distribution Loss 44% 44% 47% 41% 40% II Collection Efficiency 77% 77% 74% 80% 84% III AT&C 57% 57% 61% 52% 50%

52 Financial Performance of GRIDCO Page 1 of 2 (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Revenue from ale of Power to Discoms Revenue from ale of Power to Consumers/ Inter-tate etc Non-Operational/ Other Income I Total Revenue Purchase of Power Repairs and Maintenance alaries and Wages Administrative & General Expenses Net 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 III urplus after cash operating exp. (EBITDA) [I-II] (821) (708) (2071) (658) 8494 IV Provision for bad and doubtful debts V Depreciation VI Interest and Financial Charges VII Less: Interest & Finance charges capitalised (365) (534) (361) (597) (506) (536) (543) (539) VIII Taxation IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (3064) (3244) (5210) (356) (852) 932 (5882) 3842 Revenue ubsidies & Grants Profit on sale of investments Loss of 4 discoms transferred 0 0 (629) tatutory appropriations (B) Balance heet Financial Year Ending March 31 (Rs in million) Assets Gross Fixed Assets Less: Accumulated Depreciation (1330) (2746) (1968) (2706) (3458) (4336) (5209) (6119) Net Fixed Assets Capital Work in Progress Other Fixed Assets I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus - incl. ubsidies & Grants Profit and Loss Account (2950) (6141) (11927) (11790) (12642) (11897) (17878) (14177) Capital Contributions from Consumers VI Total hareholders Funds (5896) (4669) (5423) (3037) (8488) (4416) VII Loans (ecured and Unsecured) Accounts Payables towards towards Power Purchase Consumers' ecurity Deposits Other Current Liabilities Working Capital (hort Term) Borrowings Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII]

53 Financial Performance of GRIDCO (C) Energy Balance Page 2 of 2 Financial Year Ending March 31 (Million Units) 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, III Total Power old Breakdown of ales Retail Consumers 5,088 5,440 3,385 Inter-tate ales/ Trading ,558 WECO 2,691 2,872 2,981 3,355 3,782 NECO 2,260 2,440 2,303 2,396 2,637 3,442 OUTHCO 1,435 1,524 1,522 1,557 1,609 CECO 3,611 4,028 4,187 4,056 3,900 Unscheduled Interchange (UI) CPP ale IV Grand Total ales 5,088 5,440 6,827 10,646 11,758 11,822 11,411 15,156 (D) Commercial Performance Financial Year Ending March 31 (Rs in million) 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) III Total Revenue Billed 11,534 13,999 13,689 14,782 16,667 17,744 15,406 23,386 IV Total Collections

54 Financial Performance of CECO (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Revenue from ale of Power Non-Operational/ Other Income I Total Revenue Purchase of Power Repairs and Maintenance alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges Less: Expenses Capitalized (78) (32) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] (1359) (143) (554) (1146) (1287) IV Provision for bad and doubtful debts V Depreciation VI Interest and Financial Charges VII Less: Interest & Finance charges capitalised 0 0 (39) (48) (62) VIII Taxation IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (1815) (1052) (1493) (2167) (2357) Revenue ubsidies & Grants tatutory appropriations (B) Balance heet Financial Year Ending March 31 (Rs in million) Assets Gross Fixed Assets Less: Accumulated Depreciation (939) (1272) (1637) (2032) (2455) Net Fixed Assets Capital Work in Progress Other Fixed Assets I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus - incl. ubsidies & Grants Retained Earnings (P&L A/c) (1815) (2868) (4361) (6528) (8886) Capital Contributions from Consumers VI Total hareholders Funds (222) (1476) (2964) (5124) (7474) VII Loans (ecured and Unsecured) Accounts Payables towards towards Power Purchase Consumers' ecurity Deposits Other Current Liabilities Working Capital (hort Term) Borrowings Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII]

55 Financial Performance of NECO (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Revenue from ale of Power Non-Operational/ Other Income I Total Revenue Purchase of Power Repairs and Maintenance alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges Less: Expenses Capitalized (27) (19) (14) (12) (13) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] (469) (285) (949) (351) (629) IV Provision for bad and doubtful debts V Depreciation VI Interest and Financial Charges VII Less: Interest & Finance charges capitalised (70) (41) (42) (55) (11) VIII Taxation IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (1143) (1264) (1904) (1502) (1477) Revenue ubsidies & Grants tatutory appropriations (B) Balance heet Financial Year Ending March 31 (Rs in million) Assets Gross Fixed Assets Less: Accumulated Depreciation (538) (538) (538) (538) (538) Net Fixed Assets Capital Work in Progress Other Fixed Assets I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets 0 0 IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus - incl. ubsidies & Grants Profit and Loss Account (967) (2023) (3700) (4952) (6155) Capital Contributions from Consumers VI Total hareholders Funds 213 (807) (2239) (3331) (4355) VII Loans (ecured and Unsecured) ,472 3,903 4,157 Accounts Payables towards towards Power Purchase ,375 3,119 3,160 Consumers' ecurity Deposits Other Current Liabilities ,009 1,185 1,700 Working Capital (hort Term) Borrowings Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII]

56 Financial Performance of WECO (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Revenue from ale of Power Non-Operational/ Other Income I Total Revenue Purchase of Power Repairs and Maintenance alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges (13) 0 Less: Expenses Capitalized (33) (15) (10) (13) (11) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] 25 (249) (246) IV Provision for bad and doubtful debts V Depreciation VI Interest and Financial Charges VII Less: Interest & Finance charges capitalised (87) (54) (63) (72) (23) VIII Taxation IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (801) (1331) (1532) (770) (729) Revenue ubsidies & Grants tatutory appropriations (B) Balance heet Financial Year Ending March 31 (Rs in million) Assets Gross Fixed Assets Less: Accumulated Depreciation (563) (563) (563) (563) (563) Net Fixed Assets Capital Work in Progress Other Fixed Assets I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus - incl. ubsidies & Grants Profit and Loss Account (613) (1716) (3007) (3523) (3983) Capital Contributions from Consumers VI Total hareholders Funds 473 (595) (1675) (2061) (2301) VII Loans (ecured and Unsecured) Accounts Payables towards towards Power Purchase Consumers' ecurity Deposits Other Current Liabilities Working Capital (hort Term) Borrowings Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII]

57 Financial Performance of OUTHCO (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Revenue from ale of Power Non-Operational/ Other Income I Total Revenue Purchase of Power Repairs and Maintenance alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges Less: Expenses Capitalized (22) (9) (7) (5) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] (424) (329) (129) (13) (287) IV Provision for bad and doubtful debts V Depreciation VI Interest and Financial Charges VII Less: Interest & Finance charges capitalised (79) (42) (69) (55) (57) VIII Taxation IX Profit/(Loss) after tax [III-IV-V-VI+VII-VIII] (1025) (1146) (1003) (867) (857) Revenue ubsidies & Grants tatutory appropriations (B) Balance heet Financial Year Ending March 31 (Rs in million) Assets Gross Fixed Assets Less: Accumulated Depreciation (499) (499) (499) (499) (499) Net Fixed Assets Capital Work in Progress Other Fixed Assets I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus - incl. ubsidies & Grants Profit and Loss Account (830) (1773) (2573) (3178) (3802) Capital Contributions from Consumers VI Total hareholders Funds 68 (843) (1437) (1914) (2328) VII Loans (ecured and Unsecured) Accounts Payables towards towards Power Purchase Consumers' ecurity Deposits Other Current Liabilities Working Capital (hort Term) Borrowings Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII]

58 Financial Performance of OHPC (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Prov Revenue from ale of Power Non-Operational/ Other Income I Total Revenue Operational expenses Repairs and Maintenance alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges (9) (3) Less: Expenses Capitalized (172) (244) (258) (127) (20) (8) (16) (17) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] IV Depreciation V Interest and Financial Charges VI Less: Interest & Finance charges capitalised (237) (1645) (924) (568) (108) (45) (51) (56) VII Taxation VIII Profit/(Loss) after tax [III-IV-V+VI-VII] (274) (39) (419) 57 Revenue ubsidies & Grants (B) Balance heet Financial Year Ending March 31 (Rs in million) Prov Assets Gross Fixed Assets Less: Accumulated Depreciation (444) (887) (1335) (1833) (2766) (3733) (4742) (5858) Net Fixed Assets Capital Work in Progress I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus Profit and Loss Account VI Total hareholders Funds VII Loans (ecured and Unsecured) Current Liabilities Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII] (C) Energy Balance Financial Year Ending March I Installed Capacity (MW) II Net ales (MU)

59 Financial Performance of OPGC (A) Profit and Loss Account Financial Year Ending March 31 (Rs in million) Prov Revenue from ale of Power Non-Operational/ Other Income I Total Revenue Raw Materials consumption Production expenses Power & Electricity Duty Rebate to GRIDCO alaries and Wages Administrative & General Expenses Net Prior Period Credit/ Charges (17.3) 111 (5) (11) Less: Expenses Capitalized (98) 7 (2) (4) (1) II Total Cash Operating Expenditure III urplus after cash operating exp. (EBITDA) [I-II] IV Depreciation V Interest and Financial Charges VI Less: Interest & Finance charges capitalised (2) (1) VII Taxation VIII Profit/(Loss) after tax [III-IV-V+VI-VII] Dividend (B) Balance heet Financial Year Ending March 31 (Rs in million) Prov Assets Gross Fixed Assets Less: Accumulated Depreciation (825) (1637) (2465) (3349) (4196) (5024) (5856) (6423) Net Fixed Assets Capital Work in Progress I Total Fixed Assets II Miscellaneous expenses not w/o III Investments undry Debtors Inventory Cash & Bank Balances Loans & Advances Other Current Assets IV Total Current Assets V Total Assets [I+II+III+IV] Liabilities hare Capital Reserves & urplus Profit and Loss Account VI Total hareholders Funds VII Loans (ecured and Unsecured) Current Liabilities Provisions VIII Total Current Liabilities & Provisions IX Total Liabilities [VI+VII+VIII] (C) Energy Balance Financial Year Ending March Prov I Installed Capacity (MW) PLF 55% 63% 76% 86% 82% 71% 71% 82% Gross Generation (MU) Auxiliary Consumption (MU) II Net ales (MU)

60 Additional Annex 10. Consolidated comments from the tate Govt. and power sector entities in Orissa Consolidated Comments received from tate 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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