Tariff Determination : Generation and Transmission (Case Study)

Transcription

1 Department of Industrial and Management Engineering Indian Institute of Technology Kanpur 3 rd Capacity Building Programme for Officers of Electricity Regulatory Commissions August, 2010 Tariff Determination : Generation and Transmission (Case Study) Forum of Regulators Kulamani Biswal Chief (Finance), CERC 1

2 Functions of the Regulators Regulations framing Licensing Tariff setting Regulate Transmission and Distribution of Electricity Power purchase by Discoms Dispute resolution Levy of fees Promote renewables Specify Grid code Specify and enforce standards 3 Investors Expectation Regulators to ensure: Return on Capital employed Return of Capital Employed Reimbursement prudent operating Expenses Reward to efficient performer Reduction in Regulatory Uncertainties 4

3 Consumer Interest What does it mean? In my view: Access to Electricity Availability of Electricity Assured Quality of Electricity Attentive to Services Affordable Price Regulators to strike a balance between the interest of Consumers and Investors 5 Role of Regulators in setting tariff Regulators to ensure: Transparent Procedure Balance the conflicting interest Reasonableness of the Rate base Recovery of the Capital invested along with reasonable return Normative O & M expenses Good performance is incentivised 6

4 Tariff Determination-Legal Aspects Chapter VII comprising Sec-61 to Sec-66 of the Electricity act, 2003 deals with Tariff matters Appropriate Commission to determine the tariff subject to the provisions of the Act Appropriate Commission to make Tariff Regulations The aggrieved parties can prefer appeal before ATE against the Orders of the commission Similarly, ATE Orders are appealable before the Supreme Court 7 the Electricity Act, 2003 Section 61: Commission to specify the terms & conditions of Tariff and shall be guided by: Principles and methodology specified by CERC Commercial Principles Ensure efficiency, economy and competition Balance the interest of consumers and investors Rewarding efficiency in performance Multi-year tariff principles Tariff to reflect cost of supply Encouraging co-generation and Non-conventional sources of energy The National Electricity Policy and Tariff Policy issued by GOI utilities commission consumers 8

5 Provisions of the Electricity Act, 2003 Section 62: Commission to determine the tariff for: Supply of electricity by a generating company to a distribution licensee Transmission of electricity Wheeling of electricity Retail sale of electricity Provision of parallel distribution license in the same Area Section 63: appropriate commission shall adopt the tariff determined through transparent process of bidding 9 Provisions of the Electricity Act, 2003 Section 64 deals with the procedure for tariff order Application shall be made to the appropriate commission with such fee as may be prescribed Orders shall have to be issued within 120 days of the date of receipt of the application Copies of the orders shall be sent to appropriate Govt., the authority and the licensees within 7 days A tariff order unless amended or revoked shall be in force for such period as may be specified in the tariff order. Section 65 deals with the provision of subsidy by the state Govt. Section 66 deals with the provision of development of market for electricity trading 10

6 Benchmarking 11 Benchmarking Benchmark what? Capital cost Norms of operation Plant availability SHR Auxiliary consumption, etc. O&M norms Financial norms D/E ratio Rate of RoE Interest rate, etc. 12

7 Benchmarking Benchmarking criteria: To be based on: Actual Industry/ national/ international standards Resources (technology/investment/motivation) pumped in Measurable Achievable Controllable Accountable Rewardable 13 Target should be achievable 14

8 Unrealistic Target may lead to System Collapse 15 Benchmarking Tariff Regn, 2009: 7(2) The capital cost admitted by the Commission after prudence check shall form the basis for determination of tariff: Provided that in case of the thermal generating station and the transmission system, prudence check of capital cost may be carried out based on the benchmark norms to be specified by the Commission from time to time: Commission initiated the process in June 2008: Phase-I: Concept & Mathematical Model: Approved Phase-II: Data base creation Model preparation Model validation Consultation: public comments, public hearing Final Benchmark Norms Status: Trasnsmission: Lines: Substations : Approved vide Commission s order dated Thermal Generation: Under testing & validation in progress 16

9 Highlights Of Regulation Highlights: Regulation Tariff fixation procedure rationalized No provisional tariff Upfront tariff fixation No additional capitalization after cut-off date on new assets for thermal power station No AAD No separate calculation of Incentive No separate calculation of Income Tax Repayment linked to depreciation Benchmark norms for prudence check of capital cost of thermal generating station and transmission system Capacity Index concept for hydro stations has been dispensed with. 18

10 Highlights: Regulation New features introduced Tariff fixation on the basis of projected capital cost and additional capital expenditure Secondary fuel oil consumption to be a part of AFC Truing up of capital cost Prudence check of capital cost on the basis of benchmarked norms for thermal and transmission projects IDC, financing charges and FERV during construction period on the equity considered as normative loan Special provision for capital cost of hydro projects Provision for R&M for life extension and Special Allowance for thermal generating projects Pre-tax rate of return on Equity Land for reservoir in case of hydro projects to be depreciable asset 19 Highlights: Regulation New features introduced (Contd.) Sharing net benefits on re-financing of loan and savings on account of secondary fuel oil consumption. Special additional O&M norms for thermal projects more than 10 yrs life Norms of heat rate linked to designed heat rate with a margin of 6.5% De-scaling factor for O&M norms of thermal projects to take care of economy of scale Sharing hydrological risks in hydro projects Inducement to hedging of foreign loans Norms for new technologies (such as supercritical) Sharing CDM benefits Incentive linked to Plant Availability Factor and AFC Special provisions for DVC 20

11 Highlights: Regulation Other major proposals 15.5% base rate for pre-tax rate of ROE Additional 0.5% base rate for pre-tax rate of ROE for timely completion of projects New rate of depreciation averaging to approximately 5.28% Tightened norms of operation Reasonable compensation for pay hikes factored into O&M Norms Auditors to include auditors appointed under section 224 & 233B of the Companies Act, 1956 and any other law for time being in force. Undischarged liabilities not to form a part of the capital cost 21 Vetting of hydro capital cost The Tariff Regulations, 2009 provided that: the Commission may issue guidelines for vetting of capital cost of hydro-electric projects by an independent agency or expert and in that event the capital cost as vetted by such agency or expert may be considered by the Commission while determining the tariff of hydro generating station (Third proviso to clause(2) of Regulation 7 ). The Commission has issued the guidelines for vetting of capital cost of hydro electric projects by Designated Independent Agencies/Experts vide its order No. L- 1/50/2010-CERC dated 2nd August Three Independent agencies have been appointed by the Commission 22

12 Application for tariff DETRMINATION Application for tariff: Regulation Application for tariff determination shall be made as per the appendix-i attached to the notification Projects coming after can apply for provisional tariff with the expenditure as on date of application. Fresh application can be made for final tariff based on actual expenditure incurred and capitalized after COD duly audited and certified by the statutory auditors. Recovery of income tax and FERV shall be done directly without making any application before the Commission. 24

13 Application for tariff: Regulation Application: Application for completed or projected to be completed within 6 months from the date of application No provisional tariff Tariff for capital expenditure and additional capital expenditure actually incurred or projected to be incurred during the tariff period Truing up of capital cost (including ACE) Utilities to apply before To be done along with the tariff for next tariff period Utilities can approach for one more time prior to Under-/over-recovered tariff to be recovered/refunded with a simple interest at the rate equal to short-term PLR of SBI as on 1 st April of respective year in 6 equal monthly installments starting within 3 months from the date of order 25 Tariff determination

14 Elements of Tariff : Regulation Fixed Cost: Annual Fixed Charges Return on Equity Interest on Loan Depreciation & Advance Against Depreciation Interest on Working Capital Operation & Maintenance Expenses Variable Cost: Energy Charges 27 Elements of Tariff: Regulation Fixed Cost: Annual Fixed Charges No AAD New element: Cost of normative secondary fuel oil consumption Special Allowance and Separate Compensation Allowance, wherever applicable Variable Cost: Energy Charges for thermal: cost of secondary fuel shall not be considered. Energy Charges for hydro: linked to AFC with a multiplication factor of

15 Financial Parameters The financial parameters of tariff setting are: (1) Approach for Rate of Return (RoR) (2) Capital Cost (3) Debt/Equity Ratio (4) Return on Equity (ROE) (5) Pre-tax Vs Post-tax Return (6) Interest on Loan (IOL) (7) Depreciation (8) Interest on Working Capital (IOWC) (9) Treatment of FERV 29 (10)Operation and Maintenance Expenses Approach for Rate of Return CERC follows ROE approach in regulations. Reasons for not adopting ROCE approach were: - Lack of benchmarking for D/E mix - Volatile interest rate - Limited tenure debt market As per the Tariff Policy CERC may adopt either ROE or ROCE approach whichever is considered better in the interest of the consumers Regulation: Continue with ROE approach 30

16 Capital Cost As per the regulations: Except for NLC & Badarpur station of NTPC CERC fixes tariff based on GFA approach i.e. Equity does not get depleted once the loans are repaid. There is no benchmark for capital cost. Actual expenditure incurred and capitalized, subject to actual cash outgo, is considered for the purpose of tariff determination. Initial spares subject to a ceiling specified by the commission form a part of the capital cost. IDC on actual loan and IEDC are allowed to be capitalized along with hard cost. No ROE is provided during construction. Additional capital expenditure is allowed subject to prudence check As per Tariff Policy: Appropriate Commission is to ensure that the Total Capital Cost is reasonable Requisite benchmarks should be evolved by the Commission 31 Capital Cost : Regulation Projected capital cost and additional capital expenditure considered IDC, financing charges & FERV during construction period on the equity considered as normative loan shall be allowed Initial spares for transmission: given separately for lines, substations and series compensation devices & HVDC stations Prudence check on the basis of benchmarked norms, to be published by the Commission, for thermal and transmission projects Special provisions for hydro projects as per tariff policy Additional capital expenditure on new works for thermal projects not within the original scope of work shall not be allowed after cut-off date (taken care of under Compensation Allowance) Special provision for R&M works, with an option for Special Allowance, linked to 5.72%, for thermal projects, added 32

17 Capital Cost : Regulation Special provisions for hydro projects Depreciation to be allowed on land for reservoir. Developers insulated from hydrological risk during the first 10 years. Enhanced free power and rehabilitation cost allowed according to new Tariff Policy, for expediting project implementation. Additional capital expenditure to be allowed: On account of damage caused of natural calamities (but not due to flooding of powerhouse attributable to negligence of Genco) after adjusting for insurance proceeds. Due to any additional work which has become necessary for successful and efficient plant operation. 33 Capital Cost : Regulation Special R&M provision for thermal station Option-I : Special Allowance (i) Rs.5.0 lakh/mw/year (ii) linked to 5.72% per annum (iii) Not available to station that have already undertaken R&M and cost was admitted by the Commission Option-II : Comprehensive R&M (i) To be approved on the basis of cost benefit analysis, efficiency gain, etc. (ii) Capital cost for Tariff = R&M and LE expenditure after deducting the accumulated depreciation already recovered from the original project cost 34

18 Debt/Equity Ratio Present approach: Regulations stipulates a D/E ratio of 70:30 for projects after As per Tariff Policy: D/E ratio of 70:30 for new projects Regulation : Uniform D/E ratio of 70:30 for all new projects, additional capital expenditure and R&M works For existing projects, D/E ratio, as admitted by the Commission, to continue 35 Return on Equity Regulations Post tax ROE of 14% for entire tariff period. Return on foreign equity to be allowed in the same currency and to be paid in INR based on ER prevailing on the date of billing As stipulated by GoI in October 1991, the norms have been: RBI Bank Rate at the beginning of the year + 5%. As per Tariff Policy: Rate of RoE fixed should maintain a balance between the interest of the consumers and the need for investments. Rate of RoE fixed by CERC for generation and transmission shall be followed by the SERCs. SERCs may adopt the rate of RoE fixed for transmission for the distribution with suitable modification. 36

19 Return on Equity : Regulation Pre-tax rate of ROE 15.5% base rate for pre-tax rate of ROE Additional 0.5% base rate for timely completion of projects Foreign equity to be converted to INR on the date of investment. 37 Pre-tax Vs Post-tax Return : Regulation regulations: allow post-tax return Actual income tax gets reimbursed. Sometimes tax burden on beneficiaries becomes heavy due to: Incentive Efficiency gain Notional expenditure Income on UI Benefit of tax holiday passed on to the beneficiaries 38

20 Pre-tax Vs Post-tax Return : Regulation Pre-tax rate of return Base rate to be grossed up considering normal tax rate applicable to the company during To be trued up with the normal tax rate of respective year applicable to the company during true up exercise Benefit of tax holiday under section 80IA shall remain with the utilities Beneficiaries not to bear the burden of income tax on other earnings (like UI earning, incentive earning and efficiency gains) 39 Interest on loan regulations: Normative loans are serviced as per the Weighted Average Rate of Interest (WARI) on actual loans Repayment: Normative repayment or depreciation, whichever is higher As per Tariff Policy: Encourage structuring of debt, including tenure. Incentives for savings in costs on account of subsequent restructuring of debt Regulation : Continue existing methodology for calculation of IOL. Repayment shall be equal to the depreciation allowed. 40

21 Depreciation : existing As per the regulations: Value Base for the purpose of depreciation is Historical Cost of the asset Historical cost includes Additional capitalization and FERV up to Straight Line Method over the useful life of the asset Depreciation Rates as prescribed in Appendix II to Tariff Regulations, 2004 Salvage Value is 10%, Depreciation is allowed up to 90% of historical cost On repayment of entire loan, the remaining depreciable value shall be spread over the balance useful life of the asset Depreciation is chargeable from the first year of operation. In case of operation of the asset for part of the year, depreciation shall be charged on pro rata basis AAD is allowed subject to certain condition. 41 Depreciation As per Tariff Policy: Depreciation Rates be notified by CERC - Notified rates shall be applicable for the purpose of tariff as well as accounting No advance against depreciation (AAD) would be allowed Benefit of reduced tariff would be available to consumers after the asset is fully depreciated SERC to follow the rate as prescribed by CERC with or without modification as evolved by FoR 42

22 Depreciation : Regulation Regulation : Value Base for the purpose of depreciation is capital cost admitted by the Commission New schedule of depreciation rate averaging to approximately 5.28% (Appendix-III) Land for reservoir in case of hydro projects to be a depreciable asset Spread over after 12 years No advance against depreciation (AAD) 43 Interest on Working Capital : existing regulations IOWC is allowed on the following components: Fuel cost Coal/Lignite: Pit head station : 1&1/2 mo. Non-pit head station : 2 mo. Gas based station : 1 mo. Secondary fuel oil (for coal/lignite) : 2 mo. Liquid fuel stock (for gas based) : ½ mo. O&M Expenses : 1 mo. Maintenance Spares: 1% of historical cost p.a Receivables : 2 mo. Interest rate is short-term SBI PLR as on or 1 st April of the year of COD, whichever is later Current Liabilities not considered. 44

23 Interest on Working Capital : Regulation Regulation: IOWC components: Maintenance Spares linked to O&M expenses Coal/Lignite based : 20% of O&M Gas/Liquid based : 30% of O&M Hydro : 15% of O&M Transmission : 15% of O&M 45 Treatment of FERV regulations: FERV is allowed as pass through. Tariff Policy: FERV shall not be pass through. Appropriate cost of hedging and swapping to take care of FERV should be allowed for debt obtained in foreign currencies Regulation : Cost of hedging is allowed To the extent hedging is not done, FERV shall be allowed as pass through. 46

24 O&M Expenses : Regulation Escalation rate 5.17% for to % for to % from Reasonable compensation for pay hikes factored into O&M Norms Special additional O&M norms for thermal projects more than 10 yrs life De-scaling factor for O&M norms of thermal projects to take care of economy of scale O&M for new hydro station increased from 1.5% to 2% of capital cost 47 O&M Expenses : Regulation Separate Compensation Allowance Introduced to meet the expenses on new assets of capital nature. Shall be allowed after 10 yrs of life. Shall be allowed unit wise in Rs lakh / MW Norm is enhanced after a block of 5 years useful life. Compensation for pay hikes :O&M expenses for shall be further rationalized by considering- Thermal: 45% increase in employees cost (35% of O&M) Hydro: 50% increase in employees cost (35% of O&M) Transmission: 45% increase in employees cost (lines= 30% of O&M; AC s/s= 60% of O&M; HVDC station= 30% of O&M) Escalation factor average escalation during the last 5 years with a weightage of 60% for WPI and 40% for CPI 48

25 Technical parameters Technical Parameters The technical parameters of tariff setting are: (1) Norms of Operation (i) Target availability/ Normative capacity index for recovery of AFC (ii) Target PLF for incentive (iii) Auxiliary energy consumption (iv)transformation loss (v) Gross station heat rate (vi) Secondary fuel oil consumption (vii)stabilisation period 50

26 Norms of Operation: Regulation Target Availability for Recovery of Full Capacity (Fixed) Charges Thermal Recovery of Capacity charges below the level of Target availability shall be on pro-rata basis. At zero availability, no capacity charges are payable. Thermal Power Stations : 80% Hydro Purely Run-of-river power stations : 90% Storage type power stations and Run of river power stations with pondage : 85% Transmission AC System : 98% HVDC bi-pole links and HVDC back to back stations : 95% 51 Norms of Operation: Regulation Operating parameters for Thermal and Hydro generating stations and Transmission system have been prescribed in the regulations. For thermal generating stations tightened ceiling norms have been prescribed for: Normative Annual Plant Availability Factor (NAPAF) for recovery of fixed charges and for incentive Gross station heat rate Secondary fuel oil consumption, with provision for sharing of savings and Auxiliary Energy consumption For hydro generating stations ceiling norms have been prescribed for: NAPAF for recovery of fixed charges and for incentive Auxiliary Energy consumption, including transformation losses For transmission system ceiling norms have been prescribed for: Normative Annual Transmission System Availability Factor (NATAF) for recovery of fixed charges and for incentive Auxiliary Energy consumption has been included in the normative O&M expenses. 52

27 Norms of Operation: Regulation NAPAF/NATSAF for recovery of fixed charges and for incentive Recovery of Fixed Charges below or above the level of NAPAF/NATAF shall be on pro-rata basis. At zero availability no capacity charges are payable. NAPAF for thermal: Talcher / Tanda / Badarpur 82% TPS I / II / I(Expansion) 72% / 75% / 80% Meija unit-i to IV/Bokaro / Chandrapura / Durgapur 82%/75% / 60% / 74% AGBPS 72% Lignite based using CFBC technology: First 3 yrs. From COD/thereafter 75%/80% NAPAF for hydro: Differs for station to station from 55% to 90% NATAF for transmission: AC System = 98% HVDC bi-pole links = 92% HVDC back-to-back stations = 95% 53 Plant Availability (PAFM) PAFM shall be computed in accordance with the following formula: N PAFM = x S DCi / { N x IC x (100-AUX) }% i = 1 Where, AUX is normative auxiliary energy consumption including transformer losses DCi is the Declared capacity (ex-bus) 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 54

28 NAPAF Regulation NAPAF determination criteria : 1) Storage and Pondage type plants: i. with head variation between FRL and MDDL of up to 8%, and where plant availability is not affected by silt :90% ii. with head variation between FRL and MDDL more than 8%, and where plant availability is not affected by silt: - Plant specific allowance to be provided in NAPAF for reduction in MW output capability as reservoir level falls over the months - Multiplying factor for head variation shall be applied as follows: (Head at MDDL/Rated head) x ) Pondage type plants where plant availability is significantly affected by silt: 85% 3) Run-of-river type plants :NAPAF to be determined plant wise, based on 90% dependable 10-daily inflows pattern as approved in the DPR. 55 NAPAF Regulation An allowance may be allowed by the Commission in NAPAF determination under special circumstances i.e. abnormal silt problem or other operating conditions and known plant limitations etc. A further allowance of 5% may be allowed for difficulties in N.E. Region In case of a new hydro station the project developer has the option to approach the Commission for determination of NAPAF 56

29 NAPAF of stations in operation Regulation Station Type of Plant Plant Capacity NAPAF (%) NHPC Chamera-1 Pondage 3X Biarasiul Pondage 3x60 85 Loktak Storage 3x35 85 Chamera-II Pondage 3x Rangit Pondage 3x20 85 Dhauligana Pondage 4x70 85 Teesta-V Pondage 3x Dulhasti Pondage 3x Salal ROR 6x Uri ROR 4x Tanakpur ROR 3x NAPAF of stations in operation Regulation NHDC Indirasagar Storage 8x Omkareshwar Pondage 8x65 90 THDC Tehri Stg-1 Storage 4x SJVNL Nathpa Jhakri Pondage 6x NEEPCO Kopli Stg-1 Storage 4x50 79 Khandong Stg.-2 Storage 3x25 69 Doyang Storage 3x25 73 Ranganadi Pondage 3x DVC Panchet Storage 2x40 80 Tilaiya Storage 2x2 80 Maithon Storage 3x

30 Norms of Operation: Regulation 1. Gross Station Heat Rate (kcal/kwh) (A) Coal Based Thermal Stations 200/210/250 MW 500 MW(sub-critical) For 500MW and above with electrically operated BFP : - 40 For combination of 200/210/250 MW sets and 500MW and above sets : weighted average Special norms for some specific stations. Talcher / Tanda / Badarpur 2950/2825/2825 Bokaro / Chandrapura / Durgapur 2700/3100/2820 Coal based using CFBC technology Norms of Operation: Regulation (B) Lignite-Fired Thermal stations Above station heat rates (as at A) to be corrected using multiplying factor as given below: Lignite having 50% moisture multiplying factor of 1.10 Lignite having 40% moisture multiplying factor of 1.07 Lignite having 30% moisture multiplying factor of 1.04 For other values: to be pro-rata of above Special norms for some specific stations. TPS I / II 4000/

31 Norms of Operation : Regulation (C) Existing Open Cycle Gas Turbine/CCGT Stations (in Kcal/kWh) Station Combined Cycle Open Cycle Gandhar GPS Kawas GPS Anta GPS Dadri GPS Auraiya GPS Faridabad GPS Kayamkulam GPS Assam GPS Agartala GPS Norms of Operation : Regulation (D) New Thermal Generating Stations achieving COD on or after (in Kcal/kWh) Coal-based and lignite fired thermal stations = x Design Heat Rate Note: shall not exceed the given maximum design unit HR depending upon the pressure and temperature ratings of the unit. Gas-based/ liquid-based thermal stations = 1.06 x Design Heat Rate of the unit/block for Natural Gas and RLNG = x Design Heat Rate of the unit/block for liquid fuel 62

32 Norms of Operation: Regulation 2. Secondary fuel oil consumption ml/kwh Coal based 1.0 Lignite fired excluding CFBC technology and TPS-I 2.0 TPS-I 3.5 Lignite fired based on CFBC technology 1.25 Meija/Bokaro / Chandrapura / Durgapur 2.0/2.0 / 3.0 / 2.4 Lime stone consumption for Lignite fired station using CFBC technology (kg/kwh) Barsinger TPS-I(Exp) Norms of Operation: Regulation 3. Auxiliary Energy Consumption (%) A. Coal based With/without Natural Draft Cooling Towers 200 MW Series MW and above Series - Electrically Driven BFPs Steam Driven BFPs 8.5 Talcher / Tanda / Badarpur 10.5 / 12.0 / 9.5 Bokaro / Chandrapura / Durgapur / / Note: With Draft Cooling Tower: +0.5% 64

33 Norms of Operation: Regulation 3. Auxiliary Energy Consumption (%) B. Gas based Combined Cycle 3.0 Open Cycle Norms of Operation: Regulation 3. Auxiliary Energy Consumption (%) C. Lignite fired With/without Natural Draft Cooling Towers 200 MW Series and above (+0.5%) MW Series and above using CBFC technology (+1..5%) 10.0 Barsingar (using CBFC technology) 11.5 TPS-I/TPS-II/TPS-I(Exp.) 12.0/10.0/

34 Norms of Operation: Regulation 3. Auxiliary Energy Consumption (including Transformation Losses) (%) D. Hydro Surface with - rotating excitation mounted on generator shaft static excitation 1.0 Underground with - rotating excitation mounted on generator shaft static excitation Commercial parameters

35 Commercial Parameters The commercial parameters of tariff setting are: (1) Recovery of Capacity charges and Energy charges (2) Incentives (3) Rebate (4) Late payment surcharge (5) CDM benefit (6) UI mechanism 69 Energy Charges : Regulation For thermal stations: Secondary fuel oil is not a part of energy charge Transit & handling losses for coal: Pit head = 0.2% Non-Pit head = 0.8% For coal and lignite (Rs/kwh): ECR = ((GHR-SFC n xcvsf)xlppf/cvpf+lcxlpl)x100/(100-aux n )) For gas and liquid fuel (Rs/kwh): ECR = GHRxLPPFx100/(CVPFx(100-AUX n )) Monthly Energy Charge (Rs): = ECR x Scheduled energy (ex-bus) for the month corresponding to scheduled generation 70

36 Hydro Tariff The two part tariff for supply of electricity from a hydro station shall comprise of : i) Capacity charge ii) Energy charge The recovery of fixed charges in the form of capacity & energy charges shall now be on 50: 50 basis 71 Tariff Structure for Recovery 50% of the Annual Fixed Cost is collected in the form of Capacity charge on monthly basis( We may refer it as period Cost) 50% of the AFC is divided by the Design energy net off of AUX and FEHS to find out energy rate per unit Energy rate so derived is multiplied with monthly scheduled energy to find out Energy charge per month. Incentive is inbuilt in the formulae and not provided separately. Capacity Charge Annual Fixed Cost Energy Charge 72

37 Capacity Charges Capacity Charge (Inclusive of incentive) payable to a hydro generating station for a month shall be : AFCx0.5x NDM/ NDY x (PAFM/ NAPAF) where, AFC is the annual fixed cost specified NAPAF is Normative plant availability factor (%) PAFM is Plant availability factor achieved (%) NDM & NDY are the number of days in the month/ year 73 Energy Charges : Regulation Energy charge is payable month wise for the total energy scheduled to be supplied for the month ex power plant to the beneficiaries, excluding free energy. No secondary energy charge payable ECR (Rs/kwh) = AFCx0.5x10 / (DEx(100-AUX n )x(100-fehs) Monthly Energy Charge (Rs): = ECR x Scheduled energy (ex-bus) for the month corresponding to scheduled generation x (100-FEHS)/100 12% /(13% units) of ex-bus energy is given free to the home state. 74

38 Compensation for loss in generation Hydrological Risk sharing Shortfall scenario (A i (actual generation in yr. i)<de): DE in ECR formulae shall be: Up to 10 yrs (till EC recovery shortfall of previous yrs. is made up) : DE r =A i After 10 yrs: DE r =A 1 +A 2 -DE Higher generation scenario (A i >DE): ECR for excess generation shall be restricted to 80 paisa per unit (in case of shortfall, ECR shall be restricted to 80p only after EC shortfall of previous year has been made up) 75 Transmission charge: Regulation For Transmission systems: Transmission Charge (TC) is inclusive of incentive TC is computed on annual basis and recoverable on monthly basis TC payable for a month = AFCx(NDM/NDY)x(TAFM/NATAF) 76

39 Incentives: Regulation Thermal and hydro generating station Shall form a part of recovered fixed charge and energy charge Linked to Plant Availability Factor Transmission Shall form a part of recovered transmission charge Linked to Plant Availability Factor 77 Rebate Regulation Rebate allowable is: 2%: for payment of bills through letter of credit on presentation of bills. 1%: for payment of bills made by a mode other than through a letter of credit but within a period of one month of presentation of bills. 78

40 Late Payment Surcharges Regulation In case of payment of any bills (other than UI and VAR charges) by beneficiaries is delayed beyond a period of 60 days from the date of billing, late payment surcharge payable is: 1.25% per month. 79 CDM benefits Provisions for sharing of CDM benefits has been introduced. 1 st year after DOCO: 100% of the gross proceeds on account of CDM to be retained by the project developer; 2 nd year: share of the beneficiaries shall be 10% Subsequent years: share of the beneficiaries shall be progressively increased by 10% every year till it reaches 50% 80

41 Unscheduled Interchange (UI) Regulation: Variation in actual generation/ drawl and scheduled generation/ drawl shall be accounted for through Unscheduled Interchange (UI) charges. UI for the generating station shall be equal to its actual generation minus scheduled generation. UI for the beneficiary shall be equal to its actual drawl minus its scheduled drawl Regulation: to be dealt in a separate regulation to be specified by the Commission Commission issued CERC (Unscheduled Interchange charges and related matters) Regulations, 2009 vide Notification No.L-1(1)/2009-CERC New Delhi, the 30th March 2009 This regulation has been amended vide Notification No.L-1(1)/2009-CERC New Delhi, the 28th April Recovery of AFC Tariff impact (Nathpa Jhakri) Old Regn( ) New Regn( ) Annual design energy (MU) Scheduled energy (ex-bus) Normative capacity index (%)/ NAPAF (%) 85% 82% Actual capacity index (%)/ Actual PAF (%) 96.70% 82.00% Auxiliary Consumption (%) 0.70% 0.70% 0.00 Transformation Loss (%) 0.50% 0.50% 0.00 Free energy to home state (%) 12% 12% 0.00 Saleable design energy (MU) Free energy to home state Scheduled saleable energy (MU) Energy charge Rate (Rs./kwh)-Primary % Energy charge (Primary)- Rs crore % Energy charge (Secondary)- Rs crore Capacity charge % Incentive (Rs. crore) % Total amount recovered (Rs. crore) % 82 Composite rate (Rs/ kwh) % 0.00

42 Tariff impact (Nathpa Jhakri) AFC Regn Regn. Difference Diff. (%) Depreciation % Higher depreciation rate (2.29% to 5.11%). IF AAD is considered AAD plus Depreciation increased from to i.e., by (16.50%) Interest on Loan % Higher repayment (Depreciation considered as repayment) Return on Equity % Increase in base rate of ROE from 14% to 15.5%; Change of approach from post-tax return to pre-tax return with grossing up by 11.33% MAT rate. AAD % AAD discontinued IoWC % As below. O & M Expenses % Impact of employes cost on 35% of O&M expenses. Total % As above. I. Tax Recovered % Change of approach from post-tax return to pre-tax return with grossed up tax rate of 12.78% on 11.33% MAT rate. Gross AFC % 83