Overview of key solutions

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Given below are the five major aspects covered in the study. Some aspects are demonstrated by means of a case study project.

Conceptual Design and standardization

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The scale of operation of the mini hydro prospects is small relative to the size of central power stations in the respective states. Therefore, it is not cost-effective to develop individual designs for each prospect. Furthermore, the type and performance of the turbines for mini hydro vary significantly from manufacturer.

As a result of reviewing all the prospective schemes together as a group, it was found that the design head,  discharge and capacity of the schemes could be slightly adjusted to fall into a few groups with the result there would be a significant  reduction in cost of equipment and design. a vast amount of hydrological flow data by developing specialized computer software to support this conclusion.

The standardization of  installed capacities for these projects resulted in eight groups. It was concluded that most projects to be developed in the future would fall into one of these eight groups. 

Considerable cost savings were achieved by developing a set of standard specifications by grouping the available discharge and head of each scheme into eight groups each with an acceptable range. Thus only a few standardized equipment is required for the fifty five schemes thereby reducing equipment and design costs. The range varied from 350kW to 3500kW. Details are given below.

Runner Dia (mm) 2800 2500 2000 1400 1250 1000 TOTAL
Schemes 2 9 9 14 15 3 52
Requirement 10 20 25 28 32 6 121
Unit Cost 9.2 8.0 6.0 4.0 3.0 2.5 32.9
Generator (kW) 3500 2500 2000 1500 1250 1000 650 350 TOTAL
Schemes 2 3 1 5 4 8 18 11 52
Requirement 5 10 2 10 10 20 40 24 121
Unit Cost 7.5 4.0 3.0 2.5 2.0 1.5 1.0 0.8 22.3

Capital Cost Estimates

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Base Cost estimates were made in 1990 prices according to the following categories.

  Civil Structures Hydro-Mechanical Equipment Electrical Equipment Grid Tie
Main Equipment Gates Turbine Generator Conductors
Intake Gear box Auxiliaries Poles/Towers
Channel/penstock Inlet Valves Transformer  
Powerhouse Auxiliaries VAR Capacitors  
Tailrace Installation Breakers/Switches  
Others   Installation Installation Labour
Taxes 3% 6% 3% 3%
Contingencies 5% - - 5%

The costs were adjusted to account for  price contingencies assuming that annual inflation rate would vary from 8.4% in 1991, 7% during 1992-93 and and decline to 6.6% by 1994.

Economic Evaluation

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The economic viability of the schemes was assessed  in terms of their cost competitiveness relative to conventional sources of generation in the grid. Since Indian power systems are operated on a regional basis, the generation cost of these schemes  was set to the marginal cost of generation in the grid. 

The economic value of benefits of the schemes were derived as avoided costs of energy from grid at 33kV. During off peak periods this is fuel cost and operating and maintenance costs of less efficient stations in the grid. As the mini hydro's would be located very close to the consumptive centers, savings in Transmission and Distribution by increasing the economic value by 15%.

As power outages are widespread during peak hours the avoided cost of generation is the cost of auto generation by commercial units during peak hours.

 The two costs were combined to yield a singular value of avoided cost during peak and off peak hours. Cashflow streams of the costs and benefits of each scheme were evaluated.

It was thought desirable initially to give capacity credit to the schemes due to high congruity between seasonal availability of irrigation water and peak load in the grids.  However as the SEBs do not have any effective control over the discharges the energy was considered as "non-firm". 

Economic capital costs were determined by applying a standard conversion factor of 0.8 to the domestic component of civil works and equipment costs and removing taxes and duties. Annual O&M costs were set at 2% of capital costs and calculations were done for a 25 year economic life. Capital cost was assumed to be disbursed in the first year and energy production was assumed to start 18 months after construction begins.

The cashflow streams were computed and NPV for a discount rate of 12%. The EIRR for dam based schemes were in the range of 14 to 66% and 12 to 29% for canal drop based schemes.

The results showed a variation of EIRR from 12.2%  for Attehalla scheme in Karnataka to 65.7% for Brindavan scheme. Detailed results for all schemes are given in the projects page.

Financial Evaluation 

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The financial analysis was carried out for two cases. Firstly to evaluate the financial impact of the schemes on each state for the case wherein the respective SEBs implement the schemes. Specifically, the aim was to establish minimum cashflow requirements to ensure full cost recovery on mini hydro programs by the SEBs, and to assess the profitability of establishing mini hydro "cost-centers" in each state to manage and monitor accounts for all phases of the respective mini hydro programs  and secondly

Evaluate the financial attractiveness of the schemes to private sector companies. Given the conditions stipulated in recent approved lease agreements in the southern states, the aim was to determine the rate of return on equity for private sector companies which elect to develop captive power plants at some of the prospective sites.

Cost Centers for STATE ELECTRICITY BOARD's

Mini Hydro Cost Centers:  were proposed to be setup due to persistent financial problems of SEBs and hence to segregate the mini-hydro schemes to prove that they could be executed and managed by SEBs and provide a positive cash flow. Discussions with senior officials of SEBs to streamline project management arrangements in each state were held.
Financing for Cost Centers: The cost centers would contribute 25% equity and take funds from IREDA at an interest rate of 12.5% repayable in 10 years. Financing upto 75% would also be available from Power Finance Corporation and Rural Electrification Corporation.
Minimum Cashflow Requirements: The minimum cash flow required was computed for full recovery of costs incurred due to debt servicing plus annual operation and maintenance of schemes.
Revenues for Cost-Centers: Sale of energy is the primary source of revenue for cost-centers. The financial value of the revenue was established in terms of the tariff paid for bulk power imports from the National Thermal Power Corporation and the average tariff for power sales from the grid in each state. Based on this the net revenues in excess of the minimum cashflow requirements would be positive for the mini hydro cost-centers in each state indicating that the mini hydro cost centers would be self supporting.
STATE TOTAL CAPACITY ENERGY OUTPUT WEIGHTED AV COST AVERAGE TARIFF NET REVENUE TO COST-CENTERS
  (MW) (GWh/yr) (Rs/kWh) (Rs/kWh) Rs.Million/p.a
ANDHRA PRADESH 19.5 95.3 0.49 0.62 10.5 - 12.4
KARNATAKA 37.7 170.0 0.44 0.73 27.3 - 49.4
KERALA 26.6 120.0 0.29 0.53 28.8 - 37.4
PUNJAB 22.2 133.0 0.51 0.67 12.0 - 21.4
TAMILNADU 24.1 82.8 0.39 0.87 17.1 - 39.1

Return on Equity for Private Sector

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The state Governments have encouraged the private sector to invest in mini hydro as an alternative source to captive generation. The aim of the financial analysis for this case was to determine rate of return on equity for potential private investors based on the conditions stipulated in lease agreements  including restrictions on how financing should be mobilized.

The financial value of energy in this case was fixed at the variable costs of industrial diesel auto generation which at the time was Rs.1.16/kWh. At the time conditions for lease included a royalty for use of water at the rate of 10% of the tariff, electricity duties, cost of transmission line to the state grid to be borne by private developers and a 10% wheeling charge imposed by the SEBs to cover costs of power transmission from captive mini hydro. Two case studies were evaluated as below. Both showed a sufficient rate of return on equity.
   

Annual Generation

Capital Costs (M.Rs)

Financing Plan

Scheme IC (MW) Energy Wheeling Charge Net Energy Cost IDC Total Equity Public Finance Private Finance
Maddur 2 8.93 0.89 8.04 24.26 3.03 27.29 6.82 13.65 6.82
Mudhol 1 5.20 0.52 4.68 11.40 1.43 12.83 3.21 6.41 3.21
 

Cash flow Requirements

Generation Cost

Financial Savings

Net Savings

ROR

Scheme Debt Service Royalties O&M Total Mini Hydro Standby Diesel Standby Diesel Depreciation    %
Maddur 4.37 1.03 0.49 5.88 0.73 1.16 3.44 0.34 3.10 45
Mudhol 2.05 0.60 0.23 2.88 0.61 1.16 2.55 0.16 2.39 75

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