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.