1. System Operators’ Course CERC Terms & Conditions of Tariff 2009-14

2. Background Till March 2001, Tariff of ISGS was fixed by GoI through a notification. First Tariff regulations issued by CERC on 31-03-01 for the control period April’2001- March’2004 Tariff regulations for April2004-March 2009 issued in March 2004 Tariff regulations for April2009-March 2014 issued in Jan 2009

3. What are Terms and Conditions of Tariff? Rules for determining the Tariff of ISGS and Transmission licensees. Applicable to –a) Generating Stations supplying to more than one beneficiary (Thermal, Hydro, CCGT) –(NTPC, NLC, NHPC, DVC, NEEPCO) b) Inter State Transmission System Tariff of Nuclear power stations is fixed by DAE.

4. Some Imp Definitions and terminology Control Period : Period for which tariff is specified (April 2009- March 2014) MYT : Multi Year Tariff: The tariff spread over useful life of the equipment Beneficiary : Person purchasing power from the ISGS Cut off date :Last day of FY after 2 years from the CoD. Date of Commercial Operation: date from which Tariff recovery starts ‘Infirm power’ : Power injected before CoD. ‘Inter-State generating station’ or ‘ISGS’ : Gen Stns supplying power to more than one state. ‘Useful life’: Life of the system from CoD used for computing Depreciation and determination of Tariff norms. ( Coal/Gas based/ Substation=25 yrs, Hydro/Line 35 yrs) ‘Design energy' means the quantum of energy which can be generated in a 90% dependable year with 95% installed capacity of the hydro generating station;

5. Steps in Tariff and Collection Apply for Tariff fixation (6 months before) Tariff fixation Bench mark norms of Project Cost Billing by the ISGS/ ISTS Filing of AddCap+ deferred Liabilities +actual Expenditure Accounting in REA Truing up by CERC CoD Cut off Date Audited Costs Adjustment of Excess or Deficit collection Audited Costs Interest Rates Beneficiaries Audited Costs

6. High lights Regulation 39 Income from UI, Incentive & non-core business –Not a pass through Regulation 26 (ii)B Min Boiler efficiency, Max. Design unit Heat Rate etc. are defined for different type of boilers and coals defined for new Thermal Gen stations to discourage procurement of inefficient Boilers.

7. Project Exp. IDC FERV Initial Spares Addl Cap Rehab & Resettle (hydro) RGGYY (hydro) Asstets not in Use Profit in Sale of Infirm power Debt:Equity Ratio Capital Cost Loan Equity Total Project Cost considered for Tariff fixation Rs.

8. Tariff Capacity Charges Energy Charges Interest on Loan Return on Equity Depreciation O&M expenses Maint. Spares Normative Seconday Oil Cost Primary Fuel Lime Stone (if applicable) Components of Tariff R&M Allowence

9. EquityReturn Equity Rate of RoE LoanInterest on Loan Rate of Interest Loan +Equity Depreciation Rate of Depreciation Type/Size of Unit/ / Tr. system O&M Exp Normative O&M Exp Normative % Spares Maint. spares O&M Exp Working CapitalInterest on Working Capital Interest rates Sec OilSeondary Oil rate Sec. Oil rates

10. O&M Exp Cost of 1.5* month primary fuel Stock O&M Exp for 1 month Cost of 2 months Sec oil Stock 2 months receivables Cost of Maint. Spares (as a % of O&M ch.) Working Capital Interest rates Interest on Working Capital * 2 months for non-pit head stns.

11. Time Lines in Tariff Period Project Start date (2- 4 years) 1 st Trial synchronisation CoD Cut-Off Date for addl. CapitalisationApply for True I Up of Tarriff End of Loan repayment End of Useful Life Drawl of Start up power (2-3 months) Depreciation in straight Line method (12 years) 2-4 years 2-3 months 10-12 yrs 2-3 months 2+ years Project schedule to determine addl. RoE Control Period 1 Control Period 2 Control Period 4 Control Period 5 Eligibility for R&M Tariff after Renovation and Modernisation Construction Period

12. Bench marking Model for Generating Stations Benchmarking by CERC Fuel /Technology Green Field/ Exisitng Size of Unit No. of Units Evacuation Voltage Level Fuel Linkage Plant Location (Pit Head/ Non Pit Head) Month/Year of Award Boiler Configuration Bill of Quantities Boiler Efficiency Steam Generator Turbine Generator Island Turbine Heat Rate Fuel Oil Handling & Storage system Coal Handling System Chimney Ash Handling System C & I Package Civil Works Cooling Tower Switchyard Package Initial Spares Mode of Unloading Fuel Oil Total Unit cost Source: CERC Explanatory Memorandum ( 8 th Dec.’09) Indeces for Steel, Cement, Labour Generous set of assumptions Distance of Water Source (River) Calorific Value Ash Content Moisture Content in Coal Developed as per National Tariff policy, for facilitatting prudence checks in line with Clause 7(2) of the TCT regulations

13. Bench marking Model for Transmission lines Benchmarking by CERC Voltage class No. of circuits Conductor type No. of Conductors Insulator type Line length Wind zones & Terrain No. of Towers Types of Terrains No. of River crossings Bill of Quantities Conductor length Earthwire length No. of insulators Qty. of Hardware Tower Weights Foundation Volume Total cost / Cost per ckm Source: CERC Explanatory Memorandum ( 8 th Dec.’09) Generous set of assumptions Unit cost based on historical data and Application of PV Formula and indices

14. Plant Availability Factor DCi = Average declared capacity (in ex-bus MW), N= No. of Days in the period IC = Installed Capacity Aux = Normative auxiliary energy consumption in percentage. For Thermal Plants, DCi is the Max Pk hour MW schedule given by RLDC For Hydro Plants DCi is the MW delivered for atleast 3 hours certified by RLDC

15. Availability Calculation of Transmission System Availability = (100-100*NAFM) Where NAFM= Non-availability factor in per unit for the month 1) For AC system [ Σ ( OH L x Cktkm L x NSC L ) + Σ ( OH T x MVA T x 2.5 ) +Σ ( OH R x MVAR R x 4 ) ] THM x [ Σ (Cktkm l xNSC L ) + Σ (MVA T x 2.5 ) + Σ (MVAR R x 4 ) ] Where OH L, OH T & OH R = Outage hours for Line or Transformer or Reactor Cktkm = Length of a transmission line circuit in km NSC = Number of sub-conductors per phase MVA = MVA rating of a transformer / ICT MVAR = MVAR rating of a bus reactor, THM = Total hours in the month 2) NAFM for each HVDC system NAFM = [ Σ (TCR x hours) ] ÷ [ THM x RC ] TCR = Transmission capability reduction of the system in MW RC = Rated capacity of the system in MW.

16. Computation of monthly Capacity charges payable AFC = Annual fixed cost specified for the year, in Rupees. NAPAF = Normative annual plant availability factor in percentage NDM = Number of days in the month NDY = Number of days in the year PAFM = Plant availability factor achieved during the month, in percent: PAFY = Plant availability factor achieved during the year, in percent For Thermal Gen. Stns. less than ten (10) years old: Monthly capacity Charges = AFC x ( NDM / NDY ) x ( 0.5 + 0.5 x PAFM / NAPAF ) For Thermal Gen. Stns. Older than ten (10) years: Monthly capacity Charges = AFC x ( NDM / NDY ) x ( PAFM / NAPAF ) For Hydel Plants Monthly capacity Charges = AFC x 0.5 x NDM / NDY x ( PAFM / NAPAF ) For Transmission charges of ISTS : Monthly transmission Charges = AFC x ( NDM / NDY ) x ( TAFM / NATAF )

17. Energy Charges Rate Aux = Normative auxiliary energy consumption in percentage. CVPF = Gross calorific value of primary fuel as fired, in kCal per unit CVSF = Calorific value of secondary fuel, in kCal per ml. ECR = Energy charge rate, in Rupees per kWh sent out. GHR = Gross station heat rate, in kCal per kWh. LC = Normative limestone consumption in kg per kWh. LPL = Weighted average landed price of limestone in Rupees per kg. LPPF = Weighted average landed price of primary fuel, in Rupees per unit SFC = Specific fuel oil consumption, in ml per kWh. For Coal based and Lignite fired stations ECR = { (GHR – SFC x CVSF) x LPPF / CVPF + LC x LPL } x 100 / (100 – Aux) For gas and Liquid fuel based stations ECR = GHR x LPPF x 100 / {CVPF x (100 – Aux) } For Hydel Plants ECR = AFC x 0.5 x 10 / { DE x ( 100 – Aux ) x ( 100 – FEHS )}

18. Secondary Oil Regulation 20 Secondary fuel charges de-linked from Energy Charges and put in Fixed charges Sec Oil Exp.= SFC x LPSFi x NAPAF x 24 x NDY x IC x 10 Secondary oil consumption halved to 1ml/u Actual Expenses based on landed cost to be adjusted at the FY end. Savings in Sec. oil consumption to be shared with Beneficiaries 50:50

19. Depreciation Regulation 17 Allowed up to maximum of 90% of the capital cost and salvage value is 10% 5.28% for 1 st 12 years Balance depreciable value spread over the balance useful life IT eqpt.=15% ; PLCC=6.33 ; Motor vehicles=9.5% ; AC=9.5% Bldgs= 3.34% Land under lease=3.34% Temp erections=100% Advance Against Depreciation removed

20. Sample Calculation of Tariff – CERC Norms 2009-14 Case Study : A Project Consisting 1 No. 400KV D/C Transmission Line of 75 km line length and 4 Nos of 400KV Bays. Capital Cost of the Project : Rs 100 Cr Adopting Debt : Equity Ratio of 70 : 30 Loan (Debt) Amount : Rs 70 Cr Equity Amount : Rs 30 Cr CALCULATION OF TARIFF for 2009-10 (For illustration purpose only) Interest on Loan : 70 x 0.095 = 6.65 Cr ( IOL @ 9.5%) Return on Equity : 30 x 0.17481 = 5.24 Cr (ROE @ 17.481% {15.5%/ 16% before MAT}) Depreciation : 100 x 0.0528 = 5.28 Cr (Depreciation @ 5.28% {Building : 3.34%, TL/SS : 5.28%, PLCC : 6.33 % and balance spread over after 12 Years}) O&M Expenses = 2.57 Cr 4 No * 52.40 Lakh/Bay (400KV) 75 Km * 0.627 Lakh/Km (400KV D/c Twin) Interest on Working Capital @ 12.25% = 0.41 Cr ( WC=2 Month Receivables + 1 Month O&M + 15% O&M for spares) TOTAL TARIFF = Rs. 20.15 Cr / year

21. Will Tariff be paid after ‘Useful life’?  Yes. Tariff is receivable by the Owner  ‘Depreciation’ component will not be receivable  Eligible for Renovation and Moderation  Asset can be written off and new project can be constructed or R&M can be taken up  Allowance for R&M Rs.5Lac/MW/yr as Fixed Ch.  R&M as a separate project ‘useful life’ in relation to a unit of a generating station and transmission system from the COD shall mean the following, namely:- (a) Coal/Lignite based station :25 years (b) Gas/Liquid fuel based station :25 years (c) AC and DC sub-station: 25 years (d) Hydro generating station : 35 years (e) Transmission line : 35 years

22. Some TCT clauses relevant to System Operation

23. Commercial Declaration ‘Date of commercial operation’ or ‘COD’ means (a)in relation to a unit or block of the thermal generating station, the date declared by the generating company after demonstrating the maximum continuous rating (MCR) or the installed capacity (IC) through a successful trial run after notice to the beneficiaries, from 0000 hour of which scheduling process as per the Indian Electricity Grid Code (IEGC) is fully implemented, and in relation to thegenerating station as a whole, the date of commercial operation of the last unit or block of the generating station; (b) in relation to a unit of hydro generating station, the date declared by the generating company from 0000 hour of which, after notice to the beneficiaries, scheduling process in accordance with the Indian Electricity Grid Code is fully implemented, and in relation to the generating station as a whole, the date declared by the generating company after demonstrating peaking capability corresponding to installed capacity of the generating station through a successful trial run, after notice to the beneficiaries: hydro generating station with pondage : If insufficient reservoir or pond level -demonstrate peaking capability equivalent to installed capacity run-of-river hydro generating station - demonstrate peaking capability as and when sufficient inflow is available. c) element of the transmission system : first day of a calendar month

24. Infirm power ‘Infirm power’ means electricity injected into the grid prior to the commercial operation of a unit or block of the generating station; 11. Sale of Infirm Power. Supply of infirm power shall be accounted as Unscheduled Interchange (UI) and paid for from the regional or State UI pool account at the applicable frequency-linked UI rate: Provided that any revenue earned by the generating company from sale of infirm power after accounting for the fuel expenses shall be applied for reduction in capital cost:

25. Maintaining Fuel Stock 18 1(a) Coal-based/lignite-fired thermal generating stations (i) Cost of coal or lignite and limestone, if applicable, for 1½ months for pithead generating stations and two months for non-pit-head generating stations, for generation corresponding to the normative annual plant availability factor; Open-cycle Gas Turbine/Combined Cycle thermal generating stations Fuel cost for one month corresponding to the normative annual plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel; Liquid fuel stock for ½ month corresponding to the normative annual plant availability factor, and in case of use of more than one liquid fuel, cost of main liquid fuel.

26. Declared Capability in Fuel Shortage Conditions 21(4) In case of fuel shortage in a thermal generating station, the generating company may propose to deliver a higher MW during peak- load hours by saving fuel during off-peak hours. The concerned Load Despatch Centre may then specify a pragmatic day-ahead schedule for the generating station to optimally utilize its MW and energy capability, in consultation with the beneficiaries. DCi in such an event shall be taken to be equal to the maximum peak-hour expower plant MW schedule specified by the concerned Load Despatch Centre for that day.

27. Declared Capability in Fuel Shortage Conditions Pk hours to be specified in RPC forum DC not to be revised during Pk hours DC can not be reduced Unless Unit trips If unit trips, maximum possible DC to be given in other units In such case max DC during pk hrs to be specified as DC for the day To Check Gaming by Generator DC can not be increased

28. For Hydro Stations DCi = Declared capacity (in ex-bus MW) for the ith day of the month which the station can deliver for at least three (3) hours, as certified by the nodal load dispatch centre after the day is over. (8) The concerned Load Despatch Centre shall finalise the schedules for the hydro generating stations, in consultation with the beneficiaries, for optimal utilization of all the energy declared to be available, which shall be scheduled for all beneficiaries in proportion to their respective allocations in the generating station.

29. Sharing of ISTS charges (1) Regional Tr. Ch of a Beneficiary =(Agreed Pooled Assets+ Associated Tr. System+ IR link) Total ISGS capacity X (Wt. Avg. Entitlement from all ISGS+LTA+ MTOA) (2) IR link sharing : SR-WR, NR-WR, ER-NER = 50:50 NR-ER by NR, SR-ER by SR, WR-ER by WR (3) ICT and Down Stream N/W charges by Respective Beneficiary (4) Unpooled ATS : by respective Beneficiaries

30. Transmission charges in absence of a Beneficiary Regulation 33 (7) A new clause is added with regard payment of Tr. Charges by the generator incase of non-identification of beneficiary for its capacity. “Transmission charges corresponding to any plant capacity for which a beneficiary has not been identified and contracted shall be paid by the concerned generating company”.

31.  Notified on 15.06.2010 and shall come into force from 01.01.2011  Transmission charges for the Assets of POWERGRID shall continue to be determined by CERC  Existing methodology for Sharing of Transmission Charges is replaced (Regulation 33 of Terms & Conditions of Tariff, 2009 : Repealed )  Sharing based on Point of Connection (PoC) Tariffs based on load flow analysis  PoC are identified against all the USERS of the ISTS network known as Designated ISTS Customers (DICs) Salient features of PoC Regulations 1)Generating Stations 2)SEBs/STUs 3)Bulk consumer directly connected with ISTS 4)Any designated entity representing aforementioned physically connected entity Effect of PoC Regualtions (Sharing of Inter state Transmission charges and losses)

32. Proposed Changes in Fixed Charge Recovery For incentivising Peak Availability Annual Fixed charge for the peak hours Annual Fixed charge for the off-peak hours in (1): (2.4) ratio Different Norms for Fixed charges specified based on classification of  Peaking Stations  Other than Peaking Stations For Thermal, Hydro and CCGT Norms for Pumped Storage Hydro Generating Stations introduced

33. Tariff Policy 2006  Provisions of “Tariff Policy” of Jan 2006 state:  “Even for the Public Sector Projects, tariff of all new generation and transmission projects should also be decided on the basis of competitive bidding after a period of five years or when Regulatory Commission is satisfied that the situation is ripe to introduce such competition.”  “Tariff of the projects to be developed by CTU/STU after the period of five years or when the Regulatory Commission is satisfied that the situation is right to introduce such competition would also be determined on the basis of Competitive Bidding.” Competitive Bidding in :  Power plant setup  Transmission system construction

34. Tariff Competitive Bidding For Old projects, tariff will be continued to be fixed. For New projects awarded under Competitive Bidding, Quoted Tariff as per final award will be used got payment of charges

35. References : Terms and Conditions for Renewable Energy RLDC fee and Charges Statement of Objects and Reasons for Terms and Conditions of Tariff regulations Indian Electricity Grid Code 2010 CERC order dt Benchmarking of Thermal projects CERC order dt Benchmarking of Transmission projects CERC (Terms and Conditions for Tariff determination from Renewable Energy Sources) Regulations, 2009. Tariff Notification for Generating Companies – Govt. of India