PLANNING CRITERIA
3.1 Peaking Availability
The peaking availability of existing Hydro Electricity Plants and Thermal Plants shall be in accordance with data furnished by the respective Generating Companies and also as per the Power Purchase Agreements made with respective power stations. Availability from Central Sector Plants shall be taken as allocated by the Government of India. For the new plants, peak availability shall be as per Central Electricity Authority norms.
3.2 Plant Availability
The following outage rates for plants other than Central Sector plant shall be used in the simulation studies.
|
Unit Type
|
Planned
Outage
(Days/yr)(%)
|
Forced
Outage
(Days/Yr)(%)
|
|
Hydro Electric
|
30
|
8.2
|
16 to 37
|
4.5 to 10
|
|
Steam Thermal
|
35
|
10
|
51
|
14.0
|
|
Gas Turbine
|
30
|
8
|
37
|
10.0
|
[Note: For Central Sector plants, norms of EREB/CEA shall be adopted]
3.3 Auxiliary Consumption
Auxiliary consumption in plants for the purpose of planning studies shall be follows :
|
|
|
Size/Type
|
Auxiliary
Consumption
|
|
1.
|
Coal based Thermal Power
Station
|
i)200 MW
ii)500MW
|
9.5%
8.0%
|
|
2.
|
Gas Based Thermal Power
Station
|
i)Combined cycle
ii)Open cycle
|
3.0%
1.0%
|
|
3.
|
Hydro Station
|
|
0.5%
|
3.4 Economic Parameters
3.4.1 Reference Year for Costs
The cost estimate shall reflect economic conditions as on 1st April of the Base Year. The cost shall increase over time at the rate of general inflation and shall exclude taxes and duties in so far as they are common in the economic evaluation.
3.4.2 Reference Year for Present Value Analysis
Discounting for calculating cumulative present value cost for each scheme shall be done at an annual rate of 10%.
3.4.3 Plant Economic Life
The economic life of Generating plants may be assumed as follows for the planning studies in accordance with Govt. of India notification made under sub paragraph (A) of Paragraph VI of VI Schedule to Electricity (Supply) Act, 1948, from time to time.
|
Plant Type
|
Life (Years)
|
|
Hydro Electric
|
35
|
|
Thermal
|
25
|
|
Gas Turbine
|
15
|
3.4.4 Cost of Unserved Energy
Value of unserved energy (i.e. the loss to the economy if a KWH of energy required by consumers cannot be supplied) shall be considered in the economic analysis for the least cost generation expansion plan. Suitable pricing for such power outage costs shall be adopted from available studies applicable to Orissa.
3.5 Evaluation of Planning Studies
3.5.1 Suitable computer aided programmes shall be adopted to arrive at a least cost generation expansion plan.
3.5.2 The economic evaluation shall be carried out in accordance with the guidelines enumerated below :
-
Set out different generation expansion scenario incorporating mixed hydro/thermal expansion, only thermal expansion, mixed base/peak generation expansion, in the context of demand forecast.
-
For each scenario, determine through simulation, the timing of new installations during the planning period in order to meet the security standards.
-
Simulate the system operation in order to obtain the average annual energy production from each hydroelectric plant and each thermal plant.
-
Compute the cumulative present value cost for the scenario over the planning period incorporating capital costs for new generation and associated transmission, fixed and variable operation and maintenance costs, fuel costs and unserved
energy costs.
-
Compare the present value cost of each scenario with that of the other to arrive the least cost scenario.
-
Calculate the Long Run Marginal Cost for the least cost scenario as follows :
-
For each year of the plan period determine incremental cost of generation, energy requirement, energy generated, unserved energy, incremental net energy generated, loss of load probability in hours, Unsaved Energy %.
-
Reduce the incremental cost of generation to the Net Present Value.
-
Long Run marginal cost in Rs/KWH is = [Total net present value of incremental cost of generation (Rs.)] / [Incremental net energy generation (KWH)].
POWER SUPPLY SECURITY STANDARDS
To ensure that the generation reserve is sufficient so that the system can meet the load, even if one or more units are out of service for scheduled maintenance or in the event of non-availability of adequate hydro-electric generation capacity during the dry period, adequate reserve capacity shall be built into the system both for capacity and energy.
4.1 Capacity Reserve
Loss of Load Probability (LOLP) i.e. of 2% shall be used for planning models. This shall mean that for 2% of the year (i.e., upto 7.3 days/year) the power system may experience shortages of generating capacity.
4.2 A contingency reserve margin equal to 5% of the system peak load shall be planned to take care of fluctuations in the availability of Hydro Electric generation during the critical period of February to June of a dry- year, and to account for outages of units, power station equipment, non-availability of Central Sector share in order to maintain security and integrity of the system.
4.3 Energy Reserve
"Energy Not Served" shall be limited to 0.15% of the average annual energy.