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AVAILABILITY BASED TARIFF

AVAILABILITY BASED TARIFF. Session outline. - Tariff structures - Two part tariff - Concept of ABT - ABT structure - Expectations from OEMs/Utilities. TARIFF STRUCTURES. 1910. 1948. 1975. 1992. 1998. 2003. The current tariff approach has gradually developed over the many decades….

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AVAILABILITY BASED TARIFF

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  1. AVAILABILITY BASED TARIFF

  2. Session outline - Tariff structures - Two part tariff - Concept of ABT - ABT structure - Expectations from OEMs/Utilities

  3. TARIFF STRUCTURES

  4. 1910 1948 1975 1992 1998 2003 The current tariff approach has gradually developed over the many decades… Tariff Milestones ES Act ES Act Central Utilities 2 Part tariff ES Act Country Status British India- agglomeration of provinces Indian Union Isolated SEBs Regional System Sectoral Makeup Central Utilities Central Utilities, IPPs, CTU, SEBs Isolated Private Licensees Institutional Structure Early British Model Central Govt Regulator State Govt

  5. Under MOP: NTPC, NEEPCO Other Ministries: NLC, Central Generation Generation Generation Generation CTU-Power Grid Central Transmission Transmission Transmission Transmission Distribution Distribution Distribution Distribution The sectoral set up has evolved from monolithic inceptive SEBs and certain private licensees and is transiting to independent Generation, Transmission & Distribution… SEBs State /State GenCos DVC, Joint Licensees , IPPs Private State STUs- SEBs /State TransCos Transmission State STUs- SEBs /State DisComs Private Licensees , Pvt DisComs Power Trading: PTC, NVVVNL Financing: PFC, REC

  6. Fuel Generators Transmission Agencies Distribution Agencies The norms for tariff determination need to comply to basics of economics along the full electricity value chain. … • Cost of Debt • Cost of equity • Debt : Equity • Tax on returns • Additional capitalization • R&M capitalization • Capital costs basis • Working capital • O&M expenses • Depreciation • Operating norms • Target Availability • Utilization Incentive • Efficiency Incentive • Development Fund • Technology Compensations • Fuel Compensations

  7. Indian Tariff approach has developed as a response to industry evolution… 1992 2001 1910 Cost of Supply Cost of Supply Cost of Supply Energy Charge Energy Charge Capacity Charge Capacity Charge UI Charge Bundled Charges Single Part Tariff Two Part Tariff Availability Based Tariff • Carry over of early isolated licensees utility centric electricity luxury era • Practically all costs were pass on without any performance linkage • First capacity utilization linkage came in 1975 with entry of central utilities @ 55% • Response to excess capacity charge accruals on performance exceeding industry average • First systematic effort to lay tariff determination principles • Fixed charges pegged to 62.8% capacity utilization and incentive beyond 68% • Regulators response to contemporary sectoral situation to enhance performance and instill grid discipline. • Applicable only to Central utilities • Concept and Systems for UI charges established While the evolution has been logical there are a number of issues in the Indian Power Sector which the tariff approach need to consider in future

  8. Tariff Structure - Two part tariff Worldly most accepted structure It has inbuilt efficiency Capacity charge component based upon the customer capacity utilization. Energy charge to cover the cost of energy It encourage economic dispatch and the financing of generation resources It improves the optimization of consumption patterns.

  9. Two part tariffComponents of Fixed Charges • Return on Equity • capital cost for tariff is the cost as approved by CEA • Debt equity ratio 70:30 for investments approved after March 1992 • ROE - 16% allowed • Interest on Loan capital • weighted average of the interest rate applicable on the outstanding project loans

  10. Two part tariffComponents of Fixed Charges • Depreciation • Notified by the GoI • 7.84 % Coal based , 8.24% Gas based • O&M Expenses Normative • 2.5 % of the current capital cost • or 2% of current capital cost + Insurance total not exceeding 3%

  11. Two part tariffComponents of Fixed Charges • Interest on working capital • Rate of interest is the current cash credit interest charged by the bankers • Working capital Norms • Two months receivables • spares for 1- year • Coal stock- 15days/1 month for pit-head/others • Oil Stock for 1 month • Fuel expenses and O& M expenses for 1 month • Taxes on income

  12. Variable Charges • Normative and based on operational performance • The Norms • Plant Load factor • 4500 Hours /kW/year during stabilisation period and 6000 hours/kW/year there after ( corresponds to a PLF of 68.49%)

  13. Variable Charges • Sp.Oil Consumption • 5 ml/ kwh for 1st year after commercial operation and 3.5 ml/kwh there after • Heat Rate • 2600kcal/kwh for 1st year after commercial operation and 2500kcal/kwh there after( 40kcal/kwh reduced for electrically driven BFPs)

  14. Variable Charges • Aux. Power consumption • For 200MW units - 9.5% for 1st year after commercial operation and 9% there after (additional 0.5% with cooling towers) • For 500MW units(steam driven BFPs) - 8.5 % for 1st year after commercial operation and 8.0 % there after(additional 0.5% with cooling towers) • For 500MW units(elec. driven BFPs) - 9.5 % for 1st year after commercial operation and 9.0 % there after(additional 0.5% with cooling towers)

  15. Variable Charges • Norms for gas based power stations • Heat rate • 3150 kcal/kwh for open cycle operation and 2100 kcal/kwh for combined cycle operation on GCV basis • Aux. Power Consumption • 1% for open cycle and 3% for combined cycle

  16. Variable Charges • Variable cost calculated thus would be subject to fuel price adjustment

  17. Variable Charges • Fuel price adjustment. -On price variation of fuel. -On quality variation of fuel. FPA = 10*Hc/(100-AC)*{[Pcm/Kcm - Pcs/Kcs] +10*Ho/(100-AC) [Pom/Kom - Pos/Kos]} Pcm / Pcs = Price of coal PSL/ Base tariff. Kcm / Kcs = GCV of coal PSL/ Base tariff Pom / Pos = Price of oil PSL/ Base tariff Kom / Kos = GCV of oil PSL/ Base tariff

  18. Tariff Structure - Two Part Tariff Worldly most accepted structure Capacity charge component based upon the customer capacity utilization. Energy charge to cover the cost of energy

  19. THE GRID CONDITIONS PRIOR TO ABT • Wide frequency variations causing serious damages at generation & load ends. • Low frequency during peak hours, with frequency going down to 48.0 – 48.5 Hz. • High frequency during off peak hours, with frequency going up to 50.5 to 52.0 Hz. • Rapid changes in frequency – 1 Hz change in 5 to 10 minutes, for many times every day. • Very frequent grid disturbances, causing tripping of generating stations.

  20. WHY THIS GRID INDISPLINE ? • The TWO PART tariff mechanism was not providing any incentive for either backing down the generation during off-peak hours or for reducing the consumer load by the beneficiaries and/or enhancing the generation during peak hours. • In fact, there was financial incentive in continuing with generation at higher level, even when, the load (consumer demand) had come down. This was due to the fact that incentives were linked with actual generation.

  21. AVAILABILITY BASED TARIFF

  22. BACKGROUND Two Part Tariff had no mechanism to impose - Grid discipline. - Market Competition - Breaking monopoly 1994 - M/s ECC engaged by GOI for rationalisation. Formation of NTF and RTF M/s ECC report Market Mechanism Recommendation for ABT

  23. Frequency Profile (Pre-ABT and Post ABT)

  24. 2004 2003 2002

  25. APPLICABILITY ABT is applicable to:- • All central sector generating stations (whether inter-state or intra-state) , viz, the power plants of NTPC, NLC, NHPC, THDC etc. • All the beneficiaries, who draw power from central sector generating stations, viz, SEBs, Bulk Consumers having entitlements in CGS.

  26. ABT IMPLEMENTATION STATUS IN INDIA • WR – 01.07.02 • NR – 01.12.02 • SR – 01.01.03 • ER – 01.04.03 • NER – 01.11.03

  27. CONCEPT Performance criteria shifted from PLF to Availability. Introducing the concept of Re-trading Introduction of Frequency linked component Introduction of Merit order despatch

  28. Availability Tariff Rational tariff structure for power supply from generating stations on a contracted basis.

  29. The payment of fixed cost to the generating company is linked to availability of the plant. Amount payable to the generating company over a year towards the fixed cost depends on the average availability (MW delivering capability) of the plant over the year. Hence the name ‘Availability Tariff ’

  30. Primary objectives of ABTa) To encourage maximisation of generation b) Deviate from the schedules and take advantage of the UI mechanism. c) Mandatory FGMO for all generating units. d) Generators are expected to operate and maintain their stations with high plant availability in a sustained manner. e) Positive deviation through the UI mechanism ensures extra power for consumers and/or enhanced optimisation / conservation of resources. e) Natural Merit order

  31. COMPONENTS OF ABT Availability Based Tariff Mechanism has following three components: • Capacity Charge for Sent Out Availability • Energy Charge for Scheduled Generation / Drawl • Unscheduled Interchange (UI) Charge: • The Variation from generation schedules, i.e., Actual Generation (AG) - Scheduled Generation (SG) • The Variation from drawal schedules, i.e., Actual Drawal (AD) - Scheduled Drawal (SD)

  32. AVAILABILITY BASED TARIFF The fixed cost elements relates to Capacity Charges are • Return on equity • Interest on loan • Depreciation including AAD • O&M expenses • Interest on working capital • FERV on capital cost

  33. VARIABLE COST ELEMENTS • Energy (variable) charges cover the fuel costs and are worked out on the basis of ex-bus energy scheduled to be sent out from the generating station as per the following formula; • Energy Charges (Rs.)=Rate of Energy Charges in Rs/kWh X Scheduled Energy (ex-bus) in kWh corresponding to scheduled generation. • The components of energy charges are • Primary Fuel Cost, i.e., coal for thermal units. • Secondary Fuel Cost , i.e., oil for thermal units.

  34. UI MECHANISM TOOL FOR INDUCING GRID DISCIPLINE ? UI TARIFF BEING LINKED WITH FREQUENCY, SENDS AN APPROPRIATE COMMERCIAL SIGNAL TO GENERATORS & STATES DEPENDING UPON THE GRID FREQUENCY ALLOWS THEM TO TAKE CORRECTIVE ACTION AND BRING THE FREQUENCY NEAR THE NOMINAL LEVEL.

  35. FEATURESOF ABT • Capacity Charge and Energy Charge do not depend on PLF of the station and actual generation/drawal respectively. • No complications w.r.t deemed generation. • No year end commercial adjustments. • Perpetual Incentive for maximizing generation and reducing drawal during peak load conditions. • No incentive to over generate during off-peak conditions.

  36. TERMINOLOGY Availability : in relation to a thermal generating station for any period means the average of the daily average declared capacities (DCs) for all the days during that period expressed as a percentage of the installed capacity of the generating station minus normative auxiliary consumption in MW, and shall be computed in accordance with the following formula: N Availability = 10000 x ΣDCi / { N x IC x (100-AUXn) }% i=1 where, IC = Installed Capacity of the generating station in MW, DCi = Average declared capacity for the ith day of the period in MW, N = Number of days during the period, and AUXn = Normative Auxiliary Energy Consumption as a percentage of gross generation;

  37. TERMINOLOGY Declared Capacity (DC): The capability of the generating station to deliver ex-bus electricity in MW declared by such generating station in relation to any period of the day or whole of the day, duly taking into account the availability of fuel

  38. TERMINOLOGY Plant Load Factor(PLF): The total sent out energy corresponding to scheduled generation during the period, expressed as a percentage of sent out energy corresponding to installed capacity in that period and shall be computed in accordance with the following formula: N PLF = 10000 x Σ SGi / {N x IC x (100-AUXn) }% i=1 where, IC = Installed Capacity of the generating station in MW, SGi = Scheduled Generation in MW for the ith time block of the period, N = Number of time blocks during the period, and AUXn = Normative Auxiliary Energy Consumption as a percentage of gross generation;

  39. TERMINOLOGY Unscheduled Interchange (UI) Charges: Variation between actual generation or actual drawal and scheduled generation or scheduled drawal shall be accounted for through Unscheduled Interchange (UI) Charges. UI for a generating station shall be equal to its actual generation minus its scheduled generation. UI for a beneficiary shall be equal to its total actual drawal minus its total scheduled drawal. UI shall be worked out for each 15 minute time block. Charges for all UI transactions shall be based on average frequency of the time block UI rates are frequency dependent and uniform throughout the country.

  40. AVAILABILITY BASED TARIFF - UI UI SHALL BE BASED ON THE AVERAGE FREQUENCY OF THE RELEVANT TIME BLOCK.

  41. Unscheduled Interchange(UI) Charges : (contd..) (i)Any generation up to 105% of the declared capacity in any time block of 15 minutes and averaging up to 101% of the average declared capacity over a day shall not be construed as gaming, and the generator shall be entitled to UI charges for such excess generation above the scheduled generation (SG). (ii) For any generation beyond the prescribed limits, the Regional Load Dispatch Centre shall investigate so as to ensure that there is no gaming, and if gaming is found by the Regional Load Dispatch Centre, the corresponding UI charges due to the generating station on account of such extra generation shall be reduced to zero and the amount shall be credited adjusted towards in UI account of beneficiaries in the ratio of their capacity share in the generating station.

  42. AVAILABILITY BASED TARIFF - UI • if a power plant delivers 1934 MWs, while it was scheduled to supply only 1800 MW, the energy charge payment would be for 1800 MW only, i.e., for scheduled generation only. • The excess generation, i.e., 134 MW in above example would be paid for at a certain rate known as Unscheduled Interchange (UI) Charge, which would depend upon the system conditions prevailing at that time. • If the grid has surplus power at a particular time and frequency is above 50.5 Hz, the energy rate (for extra power) would be nil. If the system frequency is between 50.5 – 49.8, the rate would be small, i.e., varying from 6 paise per unit to Rs. 2.10 per unit depending upon the system frequency. However, if the system frequency is between 49.8 – 49.0, the rate would be high, i.e., varying from Rs. 2.10 per unit to Rs. 5.70 per unit.

  43. FGMO in ABT regime • All generating units, which are synchronized with the grid, irrespective of their ownership, type and size, shall have their governors in normal operation at all times . • If any generating unit of over fifty (50) MW size is required to be operated without its governor in normal operation,the RLDC shall be immediately advised about the reason and duration of such operation. All governors shall have a droop of between 3% and 6%.

  44. FGMO in ABT regime • No dead bands and/or time delays shall be deliberately introduced. • The generating units operating at/ above 100% of their MCR shall be capable of (and shall not be prevented from) going at least up to 105% of their MCR when frequency falls suddenly. • After an increase in generation as above, a generating unit may ramp back to the original level at a rate of about one percent (1%) per minute, in case continued operation at the increased level is not sustainable.

  45. FGMO in ABT regime • Any generating unit of over fifty (50) MW size (10 MW for NER) not complying with the above requirements, shall be kept in operation (synchronized with the Regional grid) only after obtaining the permission of RLDC. However, a constituent can make up the corresponding short fall in spinning reserve by maintaining an extra spinning reserve on the other generating units of the constituent.

  46. FGMO in ABT regime • The recommended rate for changing the governor setting, i.e., supplementary control for increasing or decreasing the output (generation level) for all generating units, irrespective of their type and size, would be one (1.0) per cent per minute or as per manufacturer’s limits. • If frequency falls below 49.5 Hz, all partly loaded generating units shall pick up additional load at a faster rate, according to their capability. • All Regional constituents shall make all possible efforts to ensure that the grid frequency always remains within the 49.0 – 50.5 Hz band.

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