IC R A R a ti n g F
NEW CERC REGULATIONS TO ENCOURAGE INVESTMENT, EFFICIENCY IN POWER SECTOR
Contact Anjan Ghosh Head, Corporate Ratings
[email protected] +91-22-30470006 Sabyasachi Majumdar
[email protected] +91-124-4545304 Anil Gupta
[email protected] +91-124-4545314
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Summary Opinion The new tariff norms for power utilities announced by the Central Electricity Regulatory Commission (CERC) for the period FY2009-14 will have an overall positive impact on the profitability of the power sector in ICRA’s opinion. While some of the measures such as a higher return on equity (RoE) will attract more investments into the sector, the tightened norms for operations should lead to an overall increase in efficiency in the system. The abolition of Advance Against Depreciation (AAD) is however a credit negative for projects funded through a shorter debt repayment tenure (post-commissioning). While the regulations have provided for higher RoE, for thermal power projects, the regulations have tightened the operational norms such as reduction in heat rate for existing bigger units, linking of allowable heat rate to design heat rate, tightening of working capital norms, reduction in Secondary Fuel Oil (SFO) consumption norms, tightening of normative Operation & Maintenance (O&M) Norms for plants with multiple units and reduction in auxiliary consumption for bigger units. On the positive side, the regulations have provided for a higher normative O&M expenses in view of significant increase in employee expenses. For Hydro Power projects, the regulations have suggested a partial sharing of Hydrological risks by the project developer (though projects will be protected during initial ten years of operation against hydrological risks). Further the regulations have attempted to incentivise the project developers to meet peak load requirements by linking the recovery of Annual Fixed Charges (AFC) and incentive income with their ability to operate near to their installed capacities for at least three hours a day. While these will pose operational challenges for hydro power projects, on the positive side, the regulations have provided for a significant increase in O&M expenses apart from a higher RoE. The regulations are positive for transmission projects, as apart from higher RoE, the normative O&M expenses for these projects are linked to the voltage levels, as against the previous practice of similar normative O&M expenses across the voltage levels.
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Industry Outlook: Impact of new CERC Norms on Power Sector
Background The Electricity Act 2003 has empowered the CERC to specify the terms and conditions for the determination of tariff in respect of the generating companies that are either owned by the Central Government or supply power to more than one State. The CERC is also empowered to determine the tariff that can be levied by transmission licensees for inter-State transmission of electricity. After the enactment of the Electricity Act 2003, the CERC had come out with tariff regulations for the period 200409 in March 2004. With these regulations set to expire on March 31, 2009, the CERC has notified new tariff regulations for the next regulatory period 2009-14. The new regulations will apply to all generating stations (excluding stations based on non-conventional energy sources) and transmission licensees, provided that the tariffs for these entities have not been determined through bidding process in accordance with the guidelines issued by the Central Government. Further, the grace period of three years for government utilities to competitively bid the projects will come to an end by 2011, and hence these norms will be applicable to projects set up by PSUs as well that will either be existing on that date or the agreement for such projects have been executed. The new regulations are also important for the various State Electricity Regulatory Commissions (SERCs) as they are guided by these regulations while framing their own tariff principles for the State sector utilities concerned. The following discussion pertains to the key changes that have been brought about in the regulations for the period 2009-14 as compared with those for the period 2004-09, and the likely impact of the same on power utilities.
Regulatory Norms for Computation of Tariff This section discusses the regulatory norms for the computation of tariff for thermal power stations, hydro power stations, and transmission licensees.
Thermal Power Stations For thermal power generating stations (coal, lignite and gas based), the CERC has been adopting a two-part tariff: 1) Capacity Charges (for recovery of Annual Fixed Costs) 2) Energy Charges (for recovery of Primary Fuel Costs)
1. Components of Capacity Charges/Annual Fixed Charge (AFC) Table 1: Annual Fixed Charges for Thermal Pow er Projects Component of AFC Return on Equity Interest on Loan Capital Depreciation
2009-14 2004-09 a 15.5% 14% b As per Actual As per Actual c 5.28% 3.6% + AAD* Based on Normative Based on Normative d Interest on Working Capital Parameters Parameters Based on Normative Based on Normative e Operations & Maintenance Costs Parameters Parameters Based on Normative f Cost of Secondary Oil Not Applicable Parameters # g Special Allowance in lieu of R&M Based on Plant Life Not Applicable # * AAD: Advance Against Depreciation; R&M: Renovation and Modernisation
Remarks Significantly Positive Marginally Positive Negative No Impact Moderately negative for plants with multiple units Moderately negative as operational norms are tightened Marginally Positive
(a) Return on Equity The CERC has specified a Pre-Tax RoE of 15.5% for the tariff period 2009-14 as against a Post-Tax RoE of 14% in the previous tariff period. Further, it has allowed an additional RoE of 0.5% for projects commissioned after April 2009 within specific timelines. The regulator has specified a 33-month of time schedule for greenfield projects up to 330 MW and 44 months for greenfield units of 500/600 MW. In ICRA’s opinion, the additional RoE will act as an incentive for a project developer to achieve time-bound milestones, which appears reasonable. On the other hand, ICRA Rating Services
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Industry Outlook: Impact of new CERC Norms on Power Sector the revised norms will not allow utilities to recover tax on income such as unscheduled interchange (UI) and incentive income from beneficiaries. (b) Interest on Loan Capital The CERC has specified a debt-equity ratio of 70:30 as the funding mix for the capital cost of a project. The interest rate as per actuals on these loan funds will be recoverable as part of the tariff, which is similar as in the case of the regulations notified for the earlier tariff period. One of the positives of the new regulations is the provision that allows retention of 1/3rd of the benefits, if any, arising out of re-financing of loans; earlier such benefits were required to be passed on entirely to the beneficiaries. (c) Depreciation In the regulations for the earlier tariff periods, the CERC followed the concept of AAD in case where the normal depreciation rates (notified by the regulator) were not sufficient to meet the debt repayment obligation of the utility. While in the new regulations for the tariff period 2009-14 the CERC has removed the concept of AAD, it has at the same time increased the depreciation rates applicable for projects. The same depreciation rates will now be applicable both for tariff purposes and for accounting purposes. As against a deprecation rate of 3.6% for thermal power projects (based on a 25-year project life and 90% of the capital cost) and 2.57% for hydro power projects (based on a 35-year project life and 90% of the capital cost), the CERC has increased the depreciation rate to 5.28% for most components of the project. While ICRA believes this will result in the lowering of tariff of a project during the initial years and moderate the impact of the higher RoE on tariff, based on the funding mix in a debt:equity of 70:30 and the depreciation rate, there will a slight mismatch in cash flows from depreciation compared to the debt repayment obligations , in case the projects are not funded with sufficiently long-tenure debt with a repayment period of 13~14 years. The prevailing practice in the sector is to fund the project with debt carrying a 10-year repayment period after the initial moratorium. While the depreciation rate at 5.28% will require a debt repayment period of 13-14 years, the higher return on equity will partly offset the impact of the abolition of AAD. (d) Interest on Working Capital The working capital for a thermal power station will have the following components: Table 2: Components of Working Capital for Thermal Power Projects Components 1
Coal Stock
2
Secondary Fuel Oil Stock
3
Maintenance Spares
4 5
Sales Receivables O&M expense
2009-14 1½ Months for Pit Head 2 Months for Non-Pit Head 2 Months 20% of O&M Costs – Coal Based 30% of O&M Cost – Gas Based 2 Months 1 Month
2004-09 1½ Months for Pit Head 2 Months for Non-Pit Head 2 Months 1% of Historical Capital Cost escalated @ 6% p.a. 2 Months 1 Month
Remarks No Impact No Impact Negative No Impact No Impact
Considering the above normative parameters, a utility can recover an interest @ Short Term Prime Lending Rate (PLR) of State Bank of India. ICRA expects no significant impact arising out of the new regulations on the recoverability of Interest on Working Capital. (e) Operations & Maintenance Costs The CERC has specified O&M costs for thermal power stations on the normative parameters (Rs. lakh/MW), depending on the class of the machine installed by the power station. The normative O&M expenses allowed are:
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Industry Outlook: Impact of new CERC Norms on Power Sector Table 3: Normative O&M costs for Thermal Power Projects Rs. Lakh/MW 200/210/250 MW 300/330/350 MW Last year of tariff period 2004-09 2008-09 12.17 O&M Expenses applicable for the new tariff period 2009-10 18.20 16.00 2010-11 19.24 16.92 2011-12 20.34 17.88 2012-13 21.51 18.91 2013-14 22.74 19.99
500 MW and Above
600 MW and above
10.95
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13.00 13.75 14.53 15.36 16.24
11.70 12.37 13.08 13.82 14.62
For thermal power stations with multiple units of the above sizes, the CERC has introduced the concept of reduction factor, which will apply to units commissioned after April 2009. The normative O&M expenses for the new units will be determined by multiplying these factors with the normative O&M expenses detailed a bove. Table 4: Reduction Factor in O&M costs for Thermal Power Projects with Multiple Units Unit Specification 200/210/250 MW Additional 5th & 6th unit 300/330/350 MW Additional 4th & 5th Unit 500 MW & Above Additional 3rd & 4th Unit
Reduction Factor 0.9 Additional 7th & more unit 0.9 Additional 6th Unit & more 0.9 Additional 5th & above unit
Reduction Factor 0.85 0.85 0.85
As the preceding table 3 shows, the regulator has allowed a significant increase in O&M expenses for the tariff period 2009-14, permitting an escalation rate of 5.72%, as against the 4% earlier. While the increase in O&M expense over the previous tariff period is a positive for utilities, there has also been a significant rise in actual O&M expenses, especially manpower expenses following the implementation of the Sixth Pay Commission. On the negative side, the bigger power plants with multiple units will see a reduction in their normative O&M expenses. However, in ICRA’s opinion, the bigger power projects would be able to offset the nega tive impact of the reduction in normative O&M expenses on the strength of their superior scale economies. Table 5: Separate Compensation Allowance for Coal based Thermal Power Projects Years of Operation 0-10 11-15 16-20 21-25
Rs. Lakh/MW Nil 0.15 0.35 0.65
In addition to the Normative O&M costs, the regulator has also allowed a separate compensation allowance (as mentioned in table 5) for meeting the expenses on new capital assets, which will be based on year of completion of the project. (f) Cost of Secondary Fuel Oil & Limestone While conventionally, the cost of Secondary Fuel Oil (SFO) is included in energy charges, in the regulations for the period 2009-14, the CERC has included the cost as part of AFC. Projects will be able to recover the cost of SFO on the basis of normative consumption norms (discussed later) specified by the regulator and the Plant Availability Factor during the year. (g) Special Allowance In Lieu of R&M The CERC in its previous regulations followed the policy of additional capitalisation arising out of any major renovation and modernisation (R&M) expenditure, whereby such capital expenditure was added to the previously approved gross block of the plant to determine the future tariffs. In its new regulations for the period 2009-14, the CERC has given an option to a coal based thermal power plants to avail of a special allowance as a part of AFC for meeting R&M expenses beyond the useful life of the power project. However in case the utility opts for this allowance as a part of AFC, there will be no increase in capital costs on account of capital expenditure incurred on R&M of power plant during the subsequent periods and no relaxed operational norms will be allowed for such
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Industry Outlook: Impact of new CERC Norms on Power Sector projects. The allowance is available to the coal/lignite based thermal power project @ Rs 5 lakh/MW/Year from 2009-10 and is escalated @ 5.72% p.a.
2. Energy Charges (for recovery of primary fuel costs) Energy charges for thermal power stations are linked to the normative operational parameters as specified by the regulator. The normative parameters include the following: Table 6: Normative Operational Parameters for Coal based Thermal Power Projects Norms for Operations 2009-14 2004-09 Remarks Plant Availability Factor * (%) 85% 80% Negative – Will result in lower Incentive Income Gross Station Heat Rate * For Existing Stations 200/210/250 MW Sets 2500 2600/2500 Negative - Higher heat rate for stabilisation period has also been removed 500 MW and above 2425 2550/2450 New TPS with COD after April 09 # Coal Based 1.065 x DHR DHR limited between 2079 – 2300 Kcal/Kwh Gas Based 1.050 x DHR Negative - Benefits of better equipments will be passed to users, lower efficiency gain for utilities Liquid Fuel based 1.071 x DHR c Secondary Fuel Oil Consumption * Coal Based 1.0 ml/Kwh 2.0 ml/kwh Marginal Negative impact. d Auxiliary Energy Consumption * 200 MW Series 9.0%/8.5% 9.0%/8.5% Higher of the auxiliary consumption (for 2009-14) is 500 MW series (Steam driven BFP) 6.5%/6.0% 7.5%/7.0% applicable to projects with induced draft cooling tower. 500 MW series (Power driven BFP) 9.0%/8.5% 9.0%/8.5% Reduction in 500 MW is marginally negative for utilities * CERC has relaxed operational norms for some coal based and lignite based Thermal Power Stations # DHR: Design Heat Rate A B
Incentives linked to Plant Availability rather than Plant Load Factor While in its earlier regulations, the CERC had linked the incentives for a generating station to the plant load factor (PLF), under the new regulations for 2009-14, it has linked the payment of incentive to the plant availability factor (PAF). This is a positive for plants that are complelled to operate at lower PLFs compared to their Availability for extraneous reasons. The incentives will be recoverable as a part of the AFC and will be computed on monthly basis. The AFC inclusive of the incentive payable will be calculated as follows: AFC (including incentive) = AFC x (Actual Plant Availability Factor/Normative Plant Availability Factor) For the new power plants that are in operation for less than 10 years and generally witness higher availability, only 50% of the benefits arising out of the higher PAF will be allowed.
Hydro Power Stations For hydro power generating stations, much of the costs are fixed in nature. The revisions in the norms for capacity charges are as follows:
Components of Capacity Charges/Annual Fixed Costs Table 7: Annual Fixed Charges for Hydro Power Projects a b c
Component of AFC Return on Equity Interest on Loan Capital Depreciation
d
Interest on Working Capital
e
Operation & Maintenance Costs
2009-14 2004-09 15.5% 14% As per Actual As per Actual 5.28% 2.57% + AAD* Based on Normative Based on Normative Parameters Parameters Based on Normative Based on Normative Parameters Parameters
Remarks Significantly Positive Marginally Positive Negative No Impact Positive
* AAD: Advance Against Depreciation ICRA Rating Services
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Industry Outlook: Impact of new CERC Norms on Power Sector
Points a,b,c for hydro power stations will be similar to thos e discussed in the case of thermal power stations (d) Interest on Working Capital Working capital for a hydro power station will have the following components: Table 8: Components of Working Capital for Hydro Power Projects Components 1
Maintenance Spares
2 3
Sales Receivables O&M expense
2009-14 15% of O&M Costs 2 Months 1 Month
2004-09 1.5% of Historical Capital Cost escalated @ 6% p.a. 2 Months 1 Month
Remarks Negative No Impact No Impact
Considering the above normative parameters, a utility can recover an interest @ prevailing Short Term Prime Lending Rate (PLR) of State Bank of India. ICRA expects no significant impact arising out of new regulations on the recoverability of Interest on Working Capital. (e) Operations & Maintenance Costs Since various factors such as location, topography, and project layout determine the nature of a particular hydro power station, the O&M costs for two hydro plants can vary and hence no normative parameters for O&M expenses have been defined by the CERC. As a result, the actual O&M expenses (excluding abnormal expenses) for the period 2003-04 to 2007-08 will form the basis for O&M expenses for the tariff period 2009-14. For practical purposes, the normalised O&M expenses for the period 2003-04 to 2007-08 will be escalated at 5.17% p.a. to arrive at the 2007-08 price levels and the average of these expenses at the 2007-08 price levels will be escalated at 5.72% p.a. to arrive at the O&M expenses for the year 2009-10. To account for the increase in employee cost on account of pay revision, O&M expenses for 2009-10 will be increased by 50% (positive), which will form the base for the next years in the tariff period. For new plants commissioned after 2009 April, 2% of the project cost (excluding R&R expenses) will form the base O&M expense, which will be escalated @ 5.72% p.a. The new norms provide for better coverage of O&M expenses, as the regulations for the period 2004-09 allowed an O&M cost of 1.5% of the capital cost escalated @ 4% p.a.
Recovery of Annual Fixed Costs Shift from Capacity Index based Fixed Charge Recovery to Availability Based Fixed Charge Recovery 1
The CERC norms for the period 2001-04 and 2004-09 followed the concept of Capacity Index (CI ) for recovery of AFC, whereby irrespective of actual water availability, a plant would have been in a position to declare a high capacity index and hence becomes eligible for recovery of AFC as well as incentives. As a result, these plants were protected against hydrological risks. The CI on which the AFC could be recovered varied from 85% to 90%, depending on the type of the hydro project. However there were certain drawbacks in recovering AFC based on CI, as during years of low water availability, the beneficiaries of the project had to pay AFC despite power not being available from the project. On the other hand, in years of excess water availability, the generating company became eligible for secondary energy charges (which was the lowest variable cost of a thermal power station in its grid). Hence the benefits in a scenario of adequate water availability were accruing to the generator, even as it was insulated against any hydrological risks. Given this backdrop, the CERC has divided the recovery of AFC into two components: Capacity Charge, and Energy Charge, whereby 1
CI = Declared Capacity (DC) (MW) / Maximum Available Capacity (MAC) (MW) x 100 where DC is the power that is expected to be generated next day based on availability of water & machine; and MAC is the maximum power that a station can generate with all units running, under the prevailing water levels and flows over the peaking hours next day. ICRA Rating Services
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Industry Outlook: Impact of new CERC Norms on Power Sector
Capacity Charge (Rs. lakh) = AFC x 0.5 x (Actual Plant Availability Factor/Normative Plant Availability Factor) Energy Charge (Rs/Kwh) = AFC x 0.5/Design Energy (adjusted for Auxiliary consumption and free power sale) Total Energy Charge (Rs. Lakh) = Energy Charge (Rs/Kwh) x Actual Generation The regulator has capped the energy charges at Re. 0.80 paisa per KWh. (for all the hydro projects) Following the division of AFC into Capacity Charge and Energy Charge, the benefits and losses arising out of variation in water availability will be shared as follows: Table 9: Impact of Deviation in Actual Power Generation Vs Design Energy on Recovery of AFC Parameter Impact on AFC 1 Actual Generation = Design Energy Complete Recovery of AFC 2 Actual Generation > Design Energy Partial sharing of benefits of secondary energy with beneficiaries 3 Actual Generation < Design Energy * Partial sharing of losses on account of lower generation by generator * for new stations with less than 10 years of operation, in case Actual Generation < Design Generation, Actual Generation will be assumed to be Design Energy, thereby protecting the new project from hydrological risks
Till the tariff period 2004-09, the energy generated over and above the design energy was sold to beneficiaries at the lowest variable cost of generation of a thermal plant in their grid. However, according to the formula for energy charge under the new regulations, a hydro power plant that has been in operation for many years and has largely paid off its debt thereby resulting in lower AFC and hence a lower energy charge thereby loosing on the power generated over the design energy. On the other hand, a new power plant will benefit from its higher AFC by virtue of debt repayments and hence benefitting from a higher energy charge (although capped at Re. 0.80). Effort to Incentivise Peaking Load Generation The CERC has emphasised the need for hydro power plants to meet the peaking load requirements, and has stated the norms of operation for hydro power plants by specifying the Normative Annual Plant Availability Factors (NAPAF). These NAPAF are based on actual hydrological data for the period 2003-04 to 2007-08 for the existing stations. Table 10: Parameter for recovery of AFC 2009-14 2004-09 Normative Plant Availability Factor (NPAF) Capacity Index Purely Run-on-the-River (RoR) Stations 90% New Regulation specifies NPAF based on actual hydrological data for past 5 years Storage Type Station or RoR Station with Pondage 85%
Parameter for recovery of AFC
1 2
For complete recovery of Capacity Charges (as discussed above), a plant has to achieve at least a PAF equal to the NAPAF. In case the actual PAF is higher than the NAPAF, the generating company will be eligible for incentives, which hitherto were linked to the Actual Capacity Index (under the earlier regulations). PAF = Declared Capacity/Installed Capacity (Adjusted for Auxiliary Consumption) where Declared Capacity is the ex-bus power that the station can deliver for at least three hours as certified by the load dispatch centre after the day is over As a result, for achieving a high PAF, the generator will have to operate closer to installed capacity for at least three hours and earn incentives instead of operating at a steady load for longer periods. On the negative side, the linking of recovery of AFC to NAPAF will negatively impact such hydro power plants whose design energy during the lean season is not sufficient to generate three hours of peaking energy, thereby resulting in lower PAF and under-recovery of AFC.
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Industry Outlook: Impact of new CERC Norms on Power Sector
Transmission Licensees As in the case of hydro power stations, much of the costs of transmission companies are also fixed in nature. The components of AFC for transmission companies also include the five components discussed under AFC for hydro Power Projects.
Components of Capacity Charges/Annual Fixed Costs Table 11: Annual Fixed Charges for Transmission Licensee
a b c
Component of AFC Return on Equity Interest on Loan Capital Depreciation
d
Interest on Working Capital
e
Operation & Maintenance Costs
2009-14 2004-09 15.5% 14% As per Actual As per Actual 5.28% 3.6% + AAD* Based on Normative Based on Normative Parameters Parameters Based on Normative Based on Normative Parameters Parameters
Remarks Significantly Positive Marginally Positive Negative No Impact Positive
* AAD: Advance Against Depreciation
Except for normative O&M costs, the other components of AFC are similar for transmission companies and hydro power stations (these have been discussed earlier in this report). (e) Operation & Maintenance Costs Normative O&M expenses for a transmission licence under the 2004-09 regulations were allowed on the basis of the length of the transmission line in circuit kilometres (CKm) and the number of substation-wise. These normative O&M expenses were constant across voltages levels of the transmission lines and substations. However, under the new regulations, the CERC has not only defined O&M expenses on the basis of the voltage levels (higher O&M expenses for higher voltages), but also allowed a considerable increase in these O&M expenses over the previous regulatory period.
Operational Norms for Recovery of AFC Table 12: Normative Operational Parameters for Transmission Licensee
a b c
Transmission System AC System HVDC bi-pole links HVDC Back to Back Station
2009-14 98% 92% 95%
2004-09 98% 95% 95%
Remarks No Impact Marginally Positive No Impact
As the table 12 shows, the operating norms remain largely remain similar to what were prevailing in the earlier regulatory period, except for a marginal reduction in the operating norms for HVDC bi-pole links, which will have a marginally positive impact on the profitability of transmission licence by way of higher incentive income in case of higher than normative availability.
Other Key Highlights Billing and Payment The regulator has maintained the rebates of 2% for timely payment and billings supported by letter of credit (LC) and 1% for payment within one month. Late payment surcharge for payment beyond 60 days has also been retained at 1.25%.
Sharing of CDM Benefits The regulator has clarified the mechanism for sharing of benefits arising of the adoption of Clean Development Mechanism (CDM). The CDM benefits for the first year after Commercial Operation can be retained by the project
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Industry Outlook: Impact of new CERC Norms on Power Sector developer. During the second year, the developer would have to share 10% of the CDM benefits with the beneficiaries; the figure will progressively increase by 10% every year till it reaches 50%.
Recovery of Hedging Costs and Foreign Exchange Rate Variation The CERC has retained the policy of recovery of hedging cost and foreign exchange rate variation from the beneficiaries.
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Industry Outlook: Impact of new CERC Norms on Power Sector
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