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1 TARIFF DESIGN for GENERATING STATIONS -- Bhanu Bhushan -- a3bhanu@gmail.com Feb 2011

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2 Basic criteria Reimbursement of reasonable cost of generation and a reasonable return on investment : RoE, IoL, Depreciation, O&M, Fuel, IWC. Separation of Fixed and Variable costs, to ensure that a generating company does not suffer a financial loss when the station is asked to back down, to ensure that there are no perverse incentives, and to facilitate merit-order operation. Equitable sharing of the total payment between the beneficiaries according to benefits derived (or entitled to derive): Fixed cost α shares; Variable cost α scheduled energy.

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3 Focused incentives for improved performance, particularly to maximize MW availability and generation during peak-load hours, and to back down as per merit-order during off-peak: Fixed cost payment α plant availability; = AFC when actual availability = NAPAF; AFC and ECR based on judicious norms for heat rate, auxiliary power consumption, secondary oil, even in cost-plus tariff, but fuel cost and GCV variations are pass-through.

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4 Desirables Generators and beneficiaries should know, upfront, what the charges would be, and retrospective adjustments should be avoided. Dispute-free implementation on long-term basis: the scheduling process: availability declaration, MW and energy entitlements, requisitions, schedules, metering, deviations, U.I. accounting. Two-part tariff for all thermal and hydro generation is a must, whether cost-plus or market-based. The two components have to be worked out based on specified norms (in cost-plus) or reached through competitive bidding process (in market-based).

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5 Some salient features of the CERC (Terms & Conditions of Tariff) Regulations, 2009, issued on 19.01.2009 and effective from 01.04.2009 for 5 years Plant availability norm raised from 80% to 85%. PLF-linked incentive withdrawn; incentive is now an integral part of Capacity charge, which is directly linked to plant availability. Secondary oil cost included in AFC. Infirm power paid at U.I. rate. If secondary oil consumption is below the norm (1 ml/kWh now), savings shared 50:50 with beneficiaries.

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6 Some of the norms / provisions GSHR: 2500 / 2425 kcal/kWh for 210 / 500 MW. Auxiliary power consumption: 8.5 / 6.0% for 210 / 500 MW; + 0.5% for IDCT. Transit loss for coal = 0.2 / 0.8%. Useful life = 25 / 35 years for thermal / hydro. Shares to remain constant during a month. FEHS for hydro = 12% + 1%. NAPAF for hydro, plant-specific, as per average peaking capability, duly considering year-round inflow variation (for R-o-R), head variation (for storage), maintenance requirement (e.g. silt).

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7 13. Components of Tariff. (1) The tariff for supply of electricity from a thermal generating station shall comprise two parts, namely, capacity charge (for recovery of annual fixed cost consisting of the components referred to in regulation 14) and energy charge (for recovery of primary fuel cost and limestone cost where applicable). (2) The tariff for supply of electricity from a hydro generating station shall comprise capacity charge and energy charge to be derived in the manner specified in regulation 22, for recovery of annual fixed cost (consisting of the components referred to in regulation 14) through the two charges.

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8 Annual fixed cost (AFC) of a generating station consists of the following components – (a) Return on equity; (b) Interest on loan capital; (c) Depreciation; (d) Interest on working capital; (e) Operation and maintenance expenses; (f) Cost of secondary fuel oil (for coal-based and lignite fired generating stations only); (g) Special allowance in lieu of R&M or separate compensation allowance, wherever applicable.

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9 RoE: at a rate to provide 15.5% (post-tax). Equity in excess of 30% of project cost treated as loan. IoL: On average notionally outstanding loan for the year @ weighted average rate of interest. Annual notional loan reduction = Depreciation charged in tariff. Depreciation: @ 5.28% for 12 years, & balance spread over the remaining life. O&M: @ Rs 18.2 / 13.0 lakh per MW for 210 / 500 MW thermal units in 2009-10, with 5.72% escalation; 2% for new hydro.

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10 IWC: Working capital comprises of (i) coal stock for 1.5 / 2 months, (ii) secondary oil for 2 months, (iii) maintenance spares @ 20% of O&M, (iv) O&M for 1 month, (v) receivables for 2 months. Interest rate = short-term PLR of SBI. Monthly billing, payable in 2 months; 2.0% rebate for immediate payment through LC, 1.25% per month surcharge for delay. FERV or hedging cost is recoverable from beneficiaries.

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11 Capacity charge (inclusive of incentive) payable to a thermal generating station for a calendar month: (a) Generating stations in commercial operation for less than ten (10) years: AFC x ( NDM / NDY ) x ( 0.5 + 0.5 x PAFM / NAPAF ) Provided that in case the plant availability factor achieved during a financial year (PAFY) is less than 70%, the total capacity charge for the year shall be restricted to AFC x ( 0.5 + 35 / NAPAF ) x ( PAFY / 70 ). (b) For generating stations in commercial operation for ten (10) years or more: AFC x ( NDM / NDY ) x ( PAFM / NAPAF ).

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12 PAFM or PAFY = 10000 x Σ DCi / { N x IC x ( 100 - AUX ) } % In case of fuel shortage, the generating company may propose to deliver a higher MW during peak-load hours by saving fuel during off-peak hours. Then, DCi = the maximum peak-hour ex- power plant MW schedule specified by the concerned Load Despatch Centre for that day. ECR = { (GHR – SFC x CVSF) x LPPF / CVPF + LC x LPL } x 100 / (100 – AUX).

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13 Application of ABT to Hydro plants Hydro plants have no variable cost, and therefore can not have an energy charge rate based on variable cost. Total annual fixed cost is notionally being divided in two equal parts for recovery as capacity charge and energy charge respectively. This is done to attach values to peaking capability and energy produced, both being equally important.

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14 Capacity charge payable for a calendar month = AFC x 0.5 x ( NDM / NDY ) x ( PAFM / NAPAF ), where, PAFM = 10000 x average DC / { IC x ( 100 – AUX ) } % Energy charge payable for a calendar month = ECR x Scheduled energy x ( 100 – FEHS ) / 100, where ECR = AFC x 0.5 x 10 / { DE x ( 100 – AUX ) x ( 100 – FEHS ) } Energy charge rate for energy in excess of DE limited to 80 p/kWh (for checking windfall gain).

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15 Example: IC = 400 MW, DE = 2000,000 MWh, AUX = 1%, NAPAF = 85%, AFC = Rs 300 crore, FEHS = 12%, NDM = 30, NDY = 365, PAFM = 90%, Month’s load factor = 50%. ECR = 3000,000,000 x 0.5 / ( 2000,000 x 0.99 x 0.88 ) = Rs 861 per MWh = 86.1 p/kWh. Capacity charge for the month = 3000,000,000 x 0.5 x ( 30 / 365 ) x ( 90 / 85 ) = Rs 130,539,880. Scheduled energy for the month = 128,304 MWh Energy charge for the month = 861 x 128,304 x 88 / 100 = Rs 97,213,371. Total average rate = 115.6 + 86.1 = 201.7 p/kWh.

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16 Safe-guards against revenue loss due to persisting lean inflow In first ten years: if A1 < DE, ECR for next year shall be calculated assuming DE = A1, till energy charge short fall has been made up. Normal ECR thereafter. After 10 years, if A1 < DE, ECR for the third year shall be calculated assuming DE = ( A1 + A2 – DE ), subject to a minimum of A1 and maximum of DE, on rolling basis.

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