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AVAILABILITY BASED TARIFF

AVAILABILITY BASED TARIFF. HIGHLIGHTS OF CERC ORDER DATED 4.1.2000 ON ABT. 1. ORDER APPLICABLE TO J&K ALSO. 2. THE ORDER WAS MAINLY ON NTPC STATIONS. 3. ABT NOT APPLICABLE TO BBMB AND CHUKHA PROJECTS. 4. ABT WAS TO BE IMPLEMENTED IN ALL THE REGIONS AS UNDER : SREB 1.4.2000

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AVAILABILITY BASED TARIFF

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  1. AVAILABILITY BASED TARIFF

  2. HIGHLIGHTS OF CERC ORDER DATED 4.1.2000 ON ABT 1. ORDER APPLICABLE TO J&K ALSO. 2. THE ORDER WAS MAINLY ON NTPC STATIONS.. 3. ABT NOT APPLICABLE TO BBMB AND CHUKHA PROJECTS. 4. ABT WAS TO BE IMPLEMENTED IN ALL THE REGIONS AS UNDER : SREB 1.4.2000 EREB 1.6.2000 NREB 1.8.2000 WREB 1.10.2000

  3. Session outline - Concept of electricity pricing - Tariff component - Two part tariff structure - Concept of ABT - ABT tariff structure - What next ?

  4. PRINCIPAL CONCEPT OF TARIFF SETTING

  5. Rate of Return (ROR)/ Cost of Service Requires determination of Allowable costs Rate base which represents the historic cost of the assets employed. Accumulated depreciation Rate of return on the rate base

  6. Rate of Return (ROR)/ Cost of Service Advantages Traditional approach and familiar to utilities, users and regulatory agencies Simple, unambiguous and fair. Provides predictable, steady returns to the utilities and hence conducive for further investments.

  7. Rate of Return (ROR)/ Cost of Service Disadvantages Tendency to over invest for higher return to the investor. Since the net return is fixed and any reduction in costs or increase in revenue is passed through to consumer, there is little motivation to reduce the cost and make efficiency gains. Inflexibility of tariffs over the tariff period and the time lag for tariff revision

  8. A cost plus electricity pricing mechanism RR = [RB X RoR] + ED + EO&M + T Where: RR = the total annual revenue requirement of the utility RB = the rate base (required investment) of the utility RoR = the allowed rate of return (debt and equity) on investment. ED = annual depreciation expense EO&M = annual operation & maintenance (O&M) expense T = annual taxes paid by the utility

  9. b) Performance Based Regulation (PBR) In this method the utilities are given A set of operational performance criteria A set of financial performance criteria Targets are set using time series data, trends of system costs and operational performance. Over achievement can increase return while under achievement will decrease the same

  10. b) Performance Based Regulation (PBR) Advantages More stable tariffs More predictable regulatory environment Disadvantage Unearned gains can boost the returns.

  11. c) Retail Price Inflation (RPI) - X This method Imposes a price cap Can be crossed only to the extent of retail price inflation X factor indicates the decrease in tariff on account of operational deficiencies. Inflation would allow for price changes due to uncontrollable costs. Determination of X factor done on actual costs and efficiencies of a range of power stations and transmission lines.

  12. Competitive Bidding This is basically a market-based approach and hence requires less transaction cost relative to other methods of tariff determination.

  13. Tariff Structure • Flat Rate- single part (p/kWh) -prior to 1991 • Two part Tariff ( K.P.Rao) - 1991 to till date • Fixed Charges • Variable Charges • Availability Based -2001/ 2004 • Capacity charge • Energy charge • Unscheduled interchange

  14. 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.

  15. 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

  16. 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%

  17. 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

  18. 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%)

  19. 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)

  20. 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)

  21. 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

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

  23. 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

  24. AVAILABILITY BASED TARIFF

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

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

  27. 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;

  28. TERMINOLOGY ‘Declared Capacity’ or ‘DC' means 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;

  29. TERMINOLOGY Plant Load Factor' or 'PLF' for a given period, means 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 ΣSGi / {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;

  30. TERMINOLOGY Unscheduled Interchange (UI) Charges: (1) 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 and the following rates shall apply with effect from 1.4.2004 :

  31. CAPACITY CHARGE Capacity charge will be related to ‘availability’ of the generating station and the percentage capacity allocated to the state. ‘Availability’ for this purpose means the readiness of the generating station to deliver ex-bus output expressed as a percentage of its rated ex-bus output capability.

  32. ENERGY CHARGE Energy charges shall be worked out on the basis of a paise per kwh rate on ex-bus energy scheduled to be sent out from the generating station as per the following formula Energy charges = Rate of energy charges (paise/kwh) x ScheduledGeneration (ex-bus MWh)

  33. UNSCHEDULED INTERCHANGE (U I) : • Variation in actual generation / drawal with respect to scheduled generation / drawal shall be accounted for through Unscheduled Interchange (UI). • UI for generating station shall be equal to its total actual generation minus its scheduled generation. • UI for beneficiary shall be equal to its total actual drawal minus its total scheduled drawal.

  34. UNSCHEDULED INTERCHANGE (UI) : • 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 shall be frequency dependent and uniform throughout the country.

  35. TARIFF COMPONENT Components of Tariff: (1) Tariff for sale of electricity from a thermal power generating station shall comprise of two parts, namely, the recovery of annual capacity (fixed) charges and energy (variable) charges. (2) The annual capacity (fixed) charges shall consist of: (a) Interest on loan capital; (b) Depreciation, including Advance Against Depreciation; (c) Return on equity; (d) Operation and maintenance expenses; and (e) Interest on working capital. (3) The energy (variable) charges shall cover fuel cost.

  36. TARIFF COMPARISON

  37. TARIFF COMPARISON

  38. TARIFF COMPARISON

  39. TARIFF COMPARISON

  40. TARIFF COMPARISON • a) Fuel cost for one month and fuel stock of 15 days for pit head stations & 30 days stock for non pit head stations calculated on normative PLF basis. • b) 60 days stock of Secondary fuel oil calculated on normative PLF basis. • c)  Operation & Maintenance expenses (Cash) for one month.

  41. TARIFF COMPARISON

  42. TARIFF COMPARISON

  43. TARIFF COMPARISON

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