Draft regulations on tariff for renewable energy Non-fossil fuel - PowerPoint PPT Presentation

Draft regulations on tariff for renewable energy Non-fossil fuel based cogeneration – typical case of sugar industry 22 nd July 2009

PLF • Sugar industry operating days vary from state to state depending on the availability of cane – hence the PLF would be different for different states – The variation is wide enough to be considered significant : from around 110 days in Bihar to 180 days in Tamil Nadu – Depending on the design of the cogeneration plant typically boiler Depending on the design of the cogeneration plant, typically boiler pressures, the amount of surplus bagasse for off season operation of cogen plant changes – hence off season operating days are dependent on the season days – Fixed cost component is inversely proportional to the PLF. Hence 50% lower operating days would result in 50% higher fixed cost. PLF has a significant impact on total generation cost & may be segregated based on regions/ states instead of one value for the whole country Op. days Impact

Station Heat Rate • Unlike a conventional thermal power plant or even a biomass based Unlike a conventional thermal power plant or even a biomass based power generation plant, the station heat rates in a bagasse based cogeneration plants are higher, especially during the season – HP Boiler efficiencies are ~ 72% HP Boiler efficiencies are ~ 72% – Most cogeneration plants operate at 45 ata steam pressure. New ones are at around 64 ata, 87 ata or even 110 ata. – Around 70% of the steam is extracted for sugar process requirement – For a cogen plant with ~ 87 ata pressure steam (515 deg. C), the net station heat rate would be ~ 5,900 kcal/ kWh, assuming a boiler efficiency of 72% • SHR of 4000 kcal/ kWh considered in draft tariff regulations is much lower than actual, closer to operation during off season – much lower than season operation Distribution of fuel component among power and steam would have a large impact on variable cost component of generated power and a large impact on variable cost component of generated power and needs to be factually evaluated S OS

CDM benefits • • The two major conditions for project registration under CDM are The two major conditions for project registration under CDM are Financial barriers & Technical barriers • In this case, unless higher boiler pressure opportunities are considered, the main issue is financial barrier id d th i i i fi i l b i – Project capex, D:E, PLF, price of fuel and power are the major value drivers. Those considered in the draft tariff regulations may not be actually achievable. t ll hi bl – If returns become attractive based on tariff fixation, most likely CDM benefits would not be granted – If tariff fixation done such that returns are not attractive, then CDM certification may be awarded but in this case, sharing of benefits would be a burden on the project developer • Expenses are also incurred during the CDM registration process and also subsequent verifications CDM b CDM benefits sharing doesn’t appear to be a practically viable option fit h i d ’t t b ti ll i bl ti

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Operating days - states PLF

Impact of PLF on Fixed cost PLF Indicative only Power generation capacity g p y MWhr 1.00 1.00 Power consumption in cogen plant % 8.5% 8.5% Net power generation MW 0.915 0.915 Operating days days/ year 180 120 Project cost Rs. Crores/ MW 4.45 4.45 Project cost P j t t R Rs. Crores C 4 45 4.45 4 45 4.45 Debt component 70% 70% ROE % 17.5% 17.5% O & M % 3.0% 3.0% Rates Rates Term loan interest % 12.25% 12.25% Working capital interest % 12.25% 12.25% Depreciation % 7.00% 7.00% Fixed Cost ROE Cr/Annum 0.2336 0.2336 Depriciation Cr/Annum 0.2804 0.2804 Interest on Term Loan Cr/Annum 0.3816 0.3816 O & M Cr/Annum 0.1335 0.1335 Interest on working capital Interest on working capital Cr/Annum Cr/Annum 0.1150 0 1150 0 1428 0.1428 Total Fixed costs + ROE Cr/Annum 1.1441 1.1719 Availability factor 49% 33% Load factor 90% 90% PLF % 44% 30% Power generation MWh/Annum 3,888 2,592 Net power export MWh/Annum 3,558 2,372 Fixed Cost Rs./kWh 3.22 4.94

Net station heat rate – season SHR Indicative only Bagasse calorific value kcal/ kg 2,250 Boiler efficiency 72% Energy output/ kg bagasse kcal/ kg bagasse 1,620 Steam pressure Steam pressure ata ata 87 87 Steam temperature deg. C 515 Steam enthalpy kcal/ kg 820 Extraction steam % for process % steam to turbine 70% Extraction steam enthalpy (the actual enthalpy is higher due kcal/ kg Extraction steam enthalpy (the actual enthalpy is higher due kcal/ kg to substantial superheat in extraction steam) 651 Extraction steam % for cogen captive consumption 20% % steam to turbine Steam to condenser % steam to turbine 10% Enthalpy of exhaust steam Enthalpy of exhaust steam kcal/ kg kcal/ kg 540 540 Net energy input for power (with extraction) kcal/ kg 180 Energy to power conversion kcal/ kWh 860 Steam consumption (assuming 100% turbine efficiency) * kgs./ kWh 4.78 Turbine heat rate Turbine heat rate kcal/ kWh kcal/ kWh 3 916 3,916 Station heat rate kcal/ kWh 5,438 Auxiliary power consuption 8.50% Net station heat rate kcal/ kWh 5,944

Net station heat rate – off-season SHR Indicative only Bagasse calorific value kcal/ kg 2,250 Boiler efficiency 72% Energy output/ kg bagasse kcal/ kg bagasse 1,620 Steam pressure Steam pressure ata ata 87 87 Steam temperature deg. C 515 Steam enthalpy kcal/ kg 820 Extraction steam % for process % steam to turbine 0% Extraction steam enthalpy (the actual enthalpy is higher Extraction steam enthalpy (the actual enthalpy is higher kcal/ kg kcal/ kg 651 651 due to substantial superheat in extraction steam) Steam to condenser % steam to turbine 100% E th l Enthalpy of exhaust steam f h t t k kcal/ kg l/ k 540 540 Net energy input for power (No extraction) kcal/ kg 280 Energy to power conversion kcal/ kWh 860 Steam consumption (assuming 100% turbine efficiency) * kgs./ kWh 3.07 Turbine heat rate kcal/ kWh 2,519 Station heat rate kcal/ kWh 3,498 Auxiliary power consuption 8.50% Net station heat rate kcal/ kWh 3,823