Issues in Electricity Generation

8/14/2019 Issues in Electricity Generation

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Issues in Power Generation

Some Fundamentals:

Voltage is the energy difference between the positive and negativeterminals of the battery.

Voltage causes current to flow in the wire.

Voltage=Current x Resistance (Ohm's law)

The energy consumed per second is the power.

Power=Voltage x Current

Power=Current x Current x Resistance

Units: Voltage-Volt, Current-Ampere, Resistance-Ohm, Power-

Watt

Energy=Power x Time

Electricity Consumption Unit=Number of hours of operation xPower in KW

DC Circuit: Current always flows in one direction

AC (Alternating Current): The higher the voltage, the higher the

current and vice-versa.

The number of times the current changes its direction in a second

is called frequency.

Nearly all the power systems today operate on AC because AC

Power can easily be 'transformed' or changed from one voltage to

another. This is of great help in sending the power over long

distances.Current will be less if voltage is increased. Power loss in thewires in the form of heat is proportional to the square of the current.

Therefore, higher the voltage level, the greater the reduction in power

loss. Furthermore, it is easier to generate AC power and motors operating

on AC are cheaper and easier to maintain. High voltages are dangerous

since there is a higher chance of electric shock. AC helps resolve this.

Power can be generated at low voltage at generating stations. Then it can

be transformed to high voltage and transmitted to consumer locations. At

consumer's place voltage can be lowered.

In AC circuit there are two components which resist the flow of

current. They are resistance and reactance. Reactance is caused by

coils(typically found in motors) or capacitors. Net effect of resistance and reactance is called impedence.

If current wave and voltage wave coincide then power factor is one

as in the case of a resistor like bulb.If current lags behind voltage then the

load is said to be inductive, as in the case of a motor. If current leads

voltage, the load is capacitive, caused by capacitors. In an AC System,

active power and reactive power depend on voltage, current and power

factor.

The power required by electrical equipment to operate is called

load.

Load is made up of an active part(measured by watt) and a

reactive part(measured by VAR(Volt-Ampere-Reactive)s)


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Depending on consumer behaviour, load keeps changing from

second to second.

Average Load=Sum of hourly loads/24

Load Factor=Average Load/Maximum Load

The installed Capacity of a generating unit is its maximum MW

capacity at the time of installation.

The minimum capacity is the minimum MW at which the

generating unit can operate in a stable way.

Energy generated by a generating unit is measured by metering

instruments at the station and can also be calculated if one knows the

average hourly MW generation. It is typically measured in Millions of

Units(MU) and is usually calculated for a period of one year,i.e 8760

hours (8784 hours for a leap year.)

MU=Sum of hourly MW values for one year/1000

Average Capacity is the average of all the hourly MW generation

values. Average Capacity=Annual Energy Generation/ Number of hours

in a year.

Firm Capacity of a unit is the MW power that can be assured from

the unit at any point in time.

Plant Load Factor = 100 x (Energy Generated in a Year)

(Maximum energy generation possible in a Year)3

Base load stations have high PLF and peaking stations have low PLF.

That's why power generation by base load stations is cheap and that

by peaking stations is costly. High PLF implies economy of scale due to

high capacity. Since base load is assured, high capacity stations can be set

up and run continuously to meet this load.

Availability of a generating unit is the per hour average of the

declared generating capacity values over a period of time (typically a

year)

Availability = 100 x (Hours for which the unit is available for

generating power)/ (Total Hours in the Year).

Hydropower

Penstocks are huge pipelines that carry water from the reservoir

to the turbine. The Full Reservoir level is the maximum height of the water in the

reservoir.

The Minimum Draw Down Level is the minimum permissible level

in the reservoir.

Hydro stations located right on the water stream are called 'run of

the river' stations. They don't have a reservoir to store and regulate water

flow.

Pumped Storage Stations: These are special type hydro stations

with two reservoirs-one upstream, near the dam at high level and another

downstream, after the tail race at low level. Water from the dam reservoir

is guided to the turbine making it and the generator rotate to generate


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power. Water leaves the turbine to the tail race reservoir through a pipe

called the tail race. This is the generating mode. In the pumping mode,

water is pumped up from the tail race reservoir to the dam reservoir. In

this mode, it draws power from the grid. The pumped storage station is

run in pumping mode during off-peak hours so as to increase the storage

in the dam reservoir. During peak hours, it is run as a generator to supplyenergy needs at that time. This arrangement can reduce the cost of peak

period energy generation.

The difference in levels of water at the storage reservoir and the

turbine is called the 'Head'. Head is measured in metres.

When water flows through the penstock and the valves, some

pressure is lost due to friction. The friction head is around 5% and the

remaining 'net head' contributes to power generation.

Power (kw) = 8 x Net Head (metres) x Flow Rate(Litres/sec)/100

Hydro plants can also generate some reactive power.

Hydro plants in the condenser mode can generate only reactivepower. In this mode of operation, a minimum water flow is to be

maintained and the unit will consume some active power from the grid.

A hydro station can be started up or put off in a few minutes. It

can be easily operated over a wide range of power output with high

efficiency. Ideal for peak load.

Low auxiliary power consumption-2-3% of the power generated

Simple to operate, high overall efficiency

Hydro-power is clean

Hydro-power is cheap-no fuel cost (though construction costs are

high)

If there is a natural high head, initial costs are lower.

Environmental costs and R&R costs.

Run of the river stations without adequate storage cannot be used

as peaking stations.

Hydro-power is renewable-long life

Execution of hydro projects requires thorough survey and

investigation, preparation of DPR, development of infrastructure,

Environment Impact Assessment and other preparatory works which are

time consuming and take 2-5 years.

Coal-based Station :

Main elements-Coal Yard, furnace, boiler, cooling tower,

Condenser

Coal based thermal stations are typically run as base load,

generating at the same level most of the time. This is because of the fact

that the generation level of these stations is changed by controlling steam

flow and pressure. But since there is a limit to the permissible changes,

generation levels cannot be changed fast.

Large number of devices-higher maintenance cost

Power is generated typically at 10-15 kv and the voltage is stepped

up at the substation which links the generating station to the grid.


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The fixed cost of a coal based station is less than that of a hydro

station.

Variable cost and auxiliary consumption values are high.

The overall efficiency of power generation is quite low compared

to hydro stations.

Auxiliary consumption-8-10% of the power generated

The coal based station is expected to run at full steam all the time.

But even the coal plants may be asked to reduce generation at night, when

the demand falls. Such instructions are given by the load dispatch centre.

Gas-based Station:

Fuel(LNG,Oil or Naphtha) arrives at the generating station

through pipeline from a refinery.

For safety reasons, very little fuel is stored at the station.

Open Cycle Gas Turbine Mode: Air is compressed and fuel burntin a combustion chamber. This releases high-pressure hot gases which

drive the gas turbine. The turbine turns the generator, producing power.

Closed Cycle Gas Turbine Mode: the exhaust gas from gas turbine

is sent back to the compressor, not to the atmosphere.

Combined Cycle Gas Turbine has a gas turbine followed by a

steam turbine. Output gases from the gas turbine flows into the

boiler/steam generator. Steam produced here turns a steam turbine.

Gas based stations can be started, stopped and the generation level

changed quite easily, making it a convenient choice to meet peak loads.

These stations are usually required to change generation levels at

short notice by the Load Dispatch Centre.

Less polluting.

Can be constructed quite fast.

Average life-10-15 years

High fuel cost

Auxiliary Consumption-3-4% of the power generated

Diesel-based Station:

Similar to gas based station

Ideally suited to handle peak load conditions and emergencypower requirements.

Low capital cost and requires little space.

Average life-5 years

Fuel cost and O&M cost is high.

Highly polluting.

Nuclear Station:

Similar to coal stations.

Instead of burning coal, the process of nuclear fission producesheat


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High Capital Cost

Need for stringent safety measures

Problem of Radioactive Waste Disposal

De-commissioning problems

Takes 6-10 or more years to build

High auxiliary consumption-11-12% of the power generated

Take 1-2 days to start up and shut down-used as base load plant

Overall Efficiency-30-35%

Typical life-30-40 years

Generation Scheduling:

Planning the level of generation of the available generating units to

meet the load is called generation scheduling.

The base load generating units (big coal based, nuclear, irrigation

dependent hydro etc.) are scheduled first to meet the base load. Then thepeaking stations (open cycle gas, small hydro) are scheduled during the

morning and evening peak hours. The intermediate loaded stations

(CCGT, small coal based and hydro) are used to meet the remaining load.

While scheduling the units of a particular type (say peak load),

units with low operating cost are scheduled first and the costlier ones last.

Ordering of units on the basis of operating costs is called the merit order,

which is prepared based on the Variable Cost values.

If there is sufficient generation capacity, some units may not be

scheduled at all. On the other hand, if available generating units are not

sufficient to meet the load, then power may have to be imported fromanother utility. If all the generating units and the imported power cannot

meet the demand of the state, and then load shedding has to be resorted

to. Broad plans for load shedding should be prepared as part of the

annual plan.

Generation Capacity has to be planned to meet the load forecast.

The total available generation capacity in the state and power imports

should be sufficient to meet the peak load at all times of the year. Energy

from these should meet the annual energy requirement of consumers.

Step 1: Prepare a load duration curve for the 10 year horizon.

(Load Duration Curve captures the load behaviour and the energy

requirements) Step 2: After finding the energy requirement at the consumer

location this is converted to the requirement at generating stations by

adding the estimated T&D losses over the planning horizon.

Step 3: Then account for the auxiliary consumption, spinning

reserve and expected outage of generating units. (Spinning reserve means

generation capacity which is already spinning and can be used at short

notice.This is managed by ensuring that some generators, which are 'on'

and connected to the system, are not fully loaded so that they have some

spare capacity.)

Expected Outage includes planned outage and forced outage.

Planned Outage is owing to routine maintenance planned for all

generators. On the other hand unforeseen failure of a generator is called


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forced outage. Based on the type of the generator, it is possible to

reasonably predict the percentage of time in a year during which such

failures occur.

When generation is not sufficient to meet the load it is called loss of

load. Loss of load probability (LOLP) is the probability that available

installed capacity falls short of load. If high excess capacity is planned and the spinning reserve is high,

LOLP will be low and vice-versa.

Issues for Discussion :

Severe power shortage plaguing the economy

Approximate peaking power shortage-13-14%

Average power shortage-around 8.8%

Tenth Plan original target for capacity addition-41,110 mw. In2002-03 it became clear that over 12400 mw would not be feasible due to

inadequate preparedness. These include 4000mw supercritical projects

(unit size 660 mw) of NTPC and over 3300 mw hydro projects. On the

basis of the review taken at the time of Mid term Appraisal capacity

addition of 36956 mw was found feasible. But after the finalization of this

revised target, gas based projects totalling 1730 mw (Kawas:725 mw,

Gandhar: 725 mw, Monarchak: 280 mw) had to be excluded from the 10th

plan due to non-availability of gas. The target was subsequently revised to

34000 mw and 32000 mw respectively. According to February estimates

only 23,163 mw could be added during the plan which is about 57% of the

initial target. An additional capacity of 4200 mw is stated to be coming upunder the captive category.

Reasons of slippage:

1. Non availability of escrow cover by State Governments to

IPP Projects

2. Delay in fund tie up and financial closure

3. Delay in super-critical technology tie-up by BHEL for six

units to be taken up by NTPC-Delay in tendering

4. Delay in Supply of Plants and equipments from BHEL and

other suppliers

5. Non-availability of gas and coal linkages6. Delay in land acquisition

7. Geological Surprises

8. Delay in Environment clearance

9. Delay in preparation of DPR and signing of MoU with State

Governments

10. Relief and Rehabilitation issues

11. Court Cases

12. Law and Order Problems

At present generation power projects totalling 47178 mw at anestimated cost of Rs.210948 crore are under implementation.


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11th Plan requirement for additional capacity during 2007-12-

about 79000-80000 mw. However, depending upon the preparedness of

various projects about 78530 mw seems feasible. The remaining gap is

likely to be met from renewable energy sources, through DSM and energy

efficiency measures. Another 12000 mw is likely to be added by way of

captive power plants of which 5000 mw is expected to be available to thegrid.

It takes about 5 years to execute a hydro-project after the work is

awarded for construction. Thus in order to achieve completion of a hydro

project during 11th plan, the project should either be already under

construction or execution should start at the beginning of the Plan. Power

Ministry has included those hydro projects whose concurrence has been

issued by CEA (order for main civil works likely to be placed by first

quarter of 2007-08) and those projects which are of smaller capacity/

ROR type having surface power houses.

Keeping in view the availability of fuel, a moderate capacity

addition of 3360 mw has been programmed during the 11th plan by the

Nuclear Power Corporation. All projects are presently under

construction.

Only 4242 mw gas based capacity has been planned for 11th plan

where gas supply has been tied up. This does not include NTPC's gas

based projects at Kawas and Gandhar, totalling 2600 mw.

As far as coal and lignite based thermal power plants are

concerned the following types of projects have been considered:

1. Such projects as have already been taken up for execution

in the 10th

Plan and are due for commissioning in the 11th

Plan.2. Thermal projects where Letters of Award have already

been placed

3. Thermal projects where LOA are expected to be placed by

30th September, 2008 and commissioning is expected during the

11th Plan.

Type Hydro Thermal-

Total

Thermal-

coal

Thermal-

Lignite

Thermal-

Gas/LNG

Nuclear Total

Projects

under

Construction

13831 29967 25625 1200 3142 3380 47178

Projects

where LOA

is being

pursued

2722 28630 27280 250 1100 0 31352

Total 16553 58597 52905 1450 4242 338 78530

Projects under Construction

Type Hydro Thermal-

Total

Thermal-

Coal

Thermal-

Lignite

Thermal-

Gas/LNG

Nuclear Total

Central 8565 11644 10190 750 704 3380 23589

State 3075 13597 12735 450 412 - 16672Private 2191 4726 2700 0 2026 - 6917


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All-

India

13831 29967 25625 1200 3142 3380 47178

Projects where LOA is being pursued

Type Hydro Thermal-Total

Thermal-Coal

Thermal-Lignite

Thermal-Gas/LNG

Nuclear Total

Central 1120 15120 14120 250 750 0 16240

State 530 10750 10400 0 350 - 11280

Private 1072 2760 2760 0 0 - 3832

All-

India

2722 28630 27280 250 1100 0 31352

It is discernible from the above tables that 42% of the proposed

capacity addition is yet to be brought at LOA stage. Projects aggregating

over 11000 mw under the State sector are such where orders related tomain plan and other packages are yet to be placed. Given the experience

of the 10th Plan, for achieving the 11th Plan target and that too with the

avoidance of tail end bunching, it is imperative that ordering in respect of

all projects is completed by December, 2007. States need to put an action

plan in place to ensure that placement of LOA is completed in a time-

bound manner.

There are projects adding up to 11545 mw which are originally

planned for the 12th Plan, but with additional efforts could yield benefits

during 11th Plan.

Expansion projects are to be taken up on priority as needed

infrastructure associated with the projects already exists. Marginal Costof setting up such projects is much lower than setting up Greenfield

projects.

Fuel Related Issues:

Domestic Coal Requirement by 2011-12 is 547 MT.

Total likely coal based capacity addition is 52905 mw out of which

4500 mw linkages are yet to be allocated and 1350 mw are likely to be on

imported coal for which formal fuel supply arrangements are yet to be

made.

Domestic Gas/LNG requirement now (2006-07) is 61 MMSCMD

vis--vis 40 MMSCMD actually available. The requirement will be to the

tune of 89 MMSCMD by 2011-12.

Due to uncertainty in availability of gas it would be advisable to

keep the gas based projects as back up projects. These may work out to

be a bonus in the event of availability of gas in required quantity and at

reasonable price.

Compensation to Resource Rich States for exploitation of Natural Resources:


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The coal bearing States argue that they bear huge environment

costs as well as the burden of creating and supporting the infrastructure

required for the huge thermal power projects, while the power produced

is utilised by other States. Therefore, these States should be compensated

by allowing a certain portion of the power produced by these projects

being made available to them free of cost or at variable cost. Ministry of Power's argument:

1. These States are benefited in the form of royalty on coal.

2. Distress and dislocation not as severe as in the case of hydro

projects.

3. These States are at their liberty to build plants and sale

power to other States.

4. Environmental concerns are addressed through the

environment policy governing coalmines and power plants.

5. Constitutional provisions/the working of a common market

in India/the federal structure.

6. Such demand may also give rise to demand of similar

dispensation from other power stations.

7. Host States are already getting 10% extra power allocation

from such stations.

8. Power at variable cost will only result in raising of cost of

the bulk supply tariff and this may not be in the interest of

developing a competitive market in the long run.

9. It is expected that the new R&R package for thermal

stations will adequately compensate and address the concern of the

Project Affected Persons(PAPs).

Demand from Coal bearing States for free power from Pit Head based station:

The above arguments apply in this case too.

Pithead Power Plants versus Load Centre Power Plants:

Pithead plants are a cheaper option as they save on railway

transportation tariff.

But still the load centre plants are desirable because:

1. System Stability/ Security

2. Security of State Grid and emergency supplies to critical

systems like Railway, Airports and Hospitals.

3. To take care of emergencies in case of transmission system

failure

4. Dispersion of environmental degradation

5. Problems of right of way in case of construction of new

transmission lines

Development of Private Sector Power Plants:


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Ultra Mega Power Projects-nine states are in fray

Four pithead sites-Madhya Pradesh, Chhattisgarh, Jharkhand and

Orissa

Five coastal sites-Gujarat, Karnataka, Maharashtra, Andhra

Pradesh and TamilNadu

4000 mw and above-tariff based competitive bidding

Shell Companies set up as wholly owned subsidiaries of PFC to

facilitate tie-ups of inputs, undertake preliminary studies and obtain

clearances.

Bidding process is over in case of Sasan (M.P) and Mundra

(Gujarat).

Bidding process is in progress for Krishnapatnam and Tilangi

projects.

Merchant Power Plants: Compete for customers and absorb the

full market risk. There is no guarantee that they will have a minimum

offtake of their output. They must respond to market needs. Typicallytheir risk is carried on the balance sheet of the promoter. MPPs operating

competitively help assure that power is produced with efficiency and

supplied to locations where it is needed most. MPPs would be expected to

have dedicated lines upto the nearest regional/national grid system. They

would be provided coal linkage for capacity of any of the plants upto 1000

mw. They may also be provided captive coal blocks for capacity in the

range of 500-1000 mw. PFC is the nodal agency for completing the

preliminary work.

Issues related to Technology:

Gross efficiency in power generation should increase from the

current average of 30.5% to 34%.

The efficiency of new plants should increase from 36% to 38-40%.

Need to introduce super-critical technology in the form of setting

up plants of capacity 660 mw-1000 mw.

BHEL should augment its capacity and capability to handle the

introduction of super critical plants

11th Plan-12 projects on super critical technology aggregating to

about 8000 mw.

These projects are in the central sector States should also follow suit.

Issues related to Funding:

PFC and REC have been geared up to mobilize funds for

generation projects.

Seemingly, there would be no dearth of funds for good projects

coming up in the State sector and also in the private sector.

However, for equity participation States have to make adequate

arrangements for providing funds from their Budget.

Human Resources Development:


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Hiring the manpower with requisite skill

Continuously upgrading the quality standard of the existing

manpower through requisite training.

Drawing comprehensive programmes for ensuring local persons

gaining the required skills.

States to have action plans for meeting the HRD/Training needs of

technical manpower required by the sector.

Involvement of ITIs.

Bringing unutilized Idle Captive Generation into the Grid:

The installed capacity of captive power plants has increased from

588 MW in 1950 to 19103 MW in March 2005.

The average PLF of the captive plants is of the order of 42.7%.

Captive plant including cogeneration plant could playsupplementary role in meeting the countries power demand.

Surplus power, if any, from the captive power plant may be fed

into the grid as open access has been allowed.

As per electricity act 2003 every captive generator shall have the

right to open access for the purpose of carrying electricity from his

captive plant to the destination of its use.

For a power plant to qualify as a captive generating plant not less

than twenty six percent of the ownership is held by the captive user(s) and

not less than 51% of the aggregate electricity generated in such plant,

determined on an annual basis, is consumed for the captive use. In case of

an association of persons not less than 51% of the electricity generated

annually shall be consumed by them in proportion to their shares in

ownership of the power plant within a variation not exceeding 10%.

National Electricity Policy on Captives:

1. Captives are also encouraged for facilitating creation of

employment opportunity.

2. Provisions relating to Captives to be set up by group of

consumers are primarily aimed at enabling SMEs or other

consumers that may not individually be in a position to set up

plant of optimal size in a cost effective manner.3. Surplus Capacity could be supplied to the grid continuously

or during certain time periods.

4. Grid interconnections for captive generators shall be

facilitated as per Section 30 of the Electricity Act.

5. Appropriate commercial arrangements would need to be

instituted between licensees and the captive generators for

harnessing of spare capacity from captives.

6. The appropriate Regulatory Commission shall exercise

regulatory oversight on such commercial arrangements.

At the same time it is necessary for the State Governments to

review the duties/cess on captive power with the objective that such dutiesdo not distort competition.


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Issues related to Thermal Sector:

Emission of SO2, NO2, suspended particular matter, soil

degradation and the related social cost

Ministry of Environment is continuously revising the emissionnorms and the emission norms are extremely progressive.

The environment externalities could be handled through reflecting

environment externalities directly in the respective Central Pollution

Control Boards' emissions/effluent standards and through imposition of

emission fees or environmental taxes.

Air Pollution-Provision of high efficiency Electrostatic

Precipitators, Tall Chimneys of 275 metres for 500MW and above units,

dust suppression system in coal and ash handling areas

Water Pollution-Close cycle circulating water system with cooling

towers to eliminate thermal discharge Water Conservation-recycling ash water overflow

Afforestation-developing a greenbelt of 100 metre width around

the thermal plant plus extensive plantation in available spaces in the plant

and township areas.

Soil Degradation-deposition of fly ash particles emitted from the

chimneys and fugitive emission of settled ash from the ash disposal areas-

use of tall stack of 220/275 metres to release fly ash results in wider

dispersal and low ground level concentration-designing the ash ponds in

such a way that a permanent blanket of water is maintained over the

settled ash to avoid fugitive emission of ash in the surrounding areas.

Progressively greater utilization of ash in cement plants, brickmanufacturing and other valuable products. Presently about 46% of the

total ash being generated in thermal power stations is being utilized.

Environment tax may not create any incentive to reduce emission

but would only add to the cost of electricity. It does not incentivise use of

clean coal. Such taxes could also be demanded by other industries like

steel and cement etc.

Another suggestion is that the power generating company should

contribute to an Environment Management Fund and may spend about

2% of its profits in local area development as part of its Corporate Social

Responsibility.

Issues related to Hydropower:

For realizing the target of hydro capacity addition in the 11th Plan,

a shelf of 61 projects aggregating to about 18,330 mw has been prepared.

49 projects totalling 15585 mw are 'feasible projects' and 13

projects totalling 2745 mw are 'best effort projects'.

A capacity addition of 30,000 mw is being envisaged in the hydro

sector in 12th Plan.

For this purpose, a shelf of 144 projects with aggregate installed

capacity of about 58000 mw has been prepared.


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State Governments are yet to allocate sites for a number of such

projects.

The State Governments may consider setting up a strong

monitoring mechanism to review the progress of the identified projects

against the milestones and take remedial measures for timely

commissioning of these projects. It is necessary to ensure that all the clearances are accorded in

time by the concerned agencies for taking up these projects. Some of the

11th plan projects are awaiting investment decision/financial closure and

in respect of some the concurrence of CEA/ State Governments is yet to

be accorded.

Land acquisition and R&R issues may be suitably addressed.

Many 11th Plan projects are in active construction stage. There

may be labour related problems, law and order issues, problem of

implementation of Environment Management plans etc. State

Governments must render necessary assistance to tackle these issues. Because of the inherent strength and experience of the Central

PSUs in the hydro sector, the State Governments may consider giving

preference to CPSUs or their Joint Ventures.

All projects involving CAPEX less than Rs.500 cr would not

require concurrence of CEA. Therefore State Governments should evolve

their own guidelines for according concurrence to such projects at their

level.

Hydroelectric power potential in the country was assessed in 1987

to be 84044 mw at 60% load factor.

At present, about 20% of the potential has been developed and 9%

is under development.

A total of 845 schemes have been identified in various basins,

which will yield 442 billion units of electricity. With seasonal energy, the

total energy potential is assessed to be 600 billion units per year.

In case of Central sector hydro projects the host States will be

supplied 12% of power generated by the station free of cost. Such

incentives enable the States to take care of the problems of rehabilitation

in the areas affected by the project. But recently it has been observed that

the revenue generated due to free power is not utilised for rehabilitation.

The tariff regime for hydro projects allows recovery of full fixed

charges on design energy. For generation beyond design energy a rateequal to the lowest variable cost for the Central thermal power station in

the Region is paid by way of incentive.(Design energy is calculated on the

basis of the water available in a 90% dependable year.)

If water availability goes below the design energy full fixed costs

are allowed to be recovered provided the power station achieves the

required capacity index. The normative capacity index has been reduced

from 90% to 85%.

With the objective of mitigating the hydrological risks, design

energy benefits are being reviewed by CEA on completion of the project

and every five years thereafter.


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The minimum qualifying capacity of hydro plants located in J&K

and NE to avail mega project benefits has been reduced from 500 mw to

350 mw.

Mega project benefits:

1. Import of capital equipment free of customs duty2. Deemed export benefits to domestic bidders for both public

and private sector projects

3. Domestic bidders allowed quoting in US Dollars or foreign

currency of their choice.

4. Income tax holiday for any block of 10 years within the first

15 years.

A number of States have started allocating projects to

private developers on considerations other than tariff. In fact, no uniform

criteria are followed by the States in this regard.

As per present guidelines-projects upto 100 mw-MOU basis

and above 100 mw-tariff based competitive bidding

Even for projects below 100 mw, the EPC contracts must be

awarded through ICB process.

The tariff policy notified on 6.1.2006 requires that all

distribution utilities shall procure power only through competitive

bidding (except in case of expansion of existing projects or projects set up

by the Public Sector utilities till January 2011.)

States having hydro potential are either power surplus or

do not have capacity to absorb the entire power generated. There are

uncertainties and risks associated with the construction of these projects.Unless good quality DPRs are prepared and long term arrangements for

procurement of power are put in place through PPAs the developers find

it difficult to get financial closure. This renders tariff based bidding a

difficult proposition in case of hydro projects.

While allotting projects some of the State Governments are

also charging upfront premium, demanding free equity stake in the

project and are imposing other conditions like return of the project after

a fixed period of time free of cost to the State, renegotiation of conditions

of allocation after a specified period of time etc. All these additional costs

being charged by the State Governments from the developers would

result in higher tariffs for the consumers.

Following the 'cost plus' approach, the first year tariff of

the hydel projects is quite high as compared to the levelised tariff. As a

result, some of the otherwise good hydel projects are rendered unviable.

FIs normally look at the first year tariff.

Thus, a special requirement of hydro projects is the

availability of long term funding at reasonable interest rates for back

ending of tariffs so that the cost of power during the initial years is

affordable.

In line with the transmission corridor requirements the

minimum tenure of PPAs should be at least 25 years.


15/16

Recognizing the value of peak power to the system and

resultant improvement in operation of thermal stations, it may be

appropriate to allow a premium on the sale rate for hydro generation

during peak period. Considering the fact that in future, to meet peaking

power the propositions of LNG based thermal stations may be very costly

affair, the development of hydro projects can be planned based onpremium tariff structures.

The per capita storage capacity of water in India at 262

cubic metres is among the lowest in the world. There are very few suitable

sites for construction of multipurpose storage projects and these sites

should be developed as storage type schemes by harnessing the full

potential.

However, the storage schemes involve high capital cost

making them economically unviable if the entire cost of the dam is

apportioned to the power generation from the project.

Sharing of cost of storage projects among variousbeneficiaries would result in lower tariff and would make many storage

schemes having multipurpose benefits commercially viable.

To eliminate or mitigate the adverse impacts of

hydroelectric projects, the following main environment management

plans are implemented:

1. Rehabilitation Master Plan (RMP) for the Project affected people

(PAP).

2. Environment Impact Assessment

3. Plan for protection and rehabilitation of flora, fauna, forests and

wildlife.4. Catchments Area Treatment (CAT) Plan.

5. Plan for rehabilitation/relocation of archaeological, religious,

cultural/historical monuments.

6. Compensatory Afforestation Plan(CAP)

7. Disaster Management Plan(DMP)

8. Biodiversity Conservation and Management Plan

9. Fisheries Development Plan

10. Provision of Public Health Delivery System

11. Restoration of muck disposal at the pre-determined sites

12. Landscaping and restoration of construction area to restore the

environment once construction activities are over13. Green belt and voluntary afforestation to protect soil erosion from

catchments/drainage.

State Governments can play a pro-active role in expediting the

environment related clearances.

CAT needs to be taken up in an integrated manner and its cost

should be apportioned to various developmental projects in the

catchments.

CAT to be done at project cost for hydro project should be limited

only to immediate vicinity of the reservoir and the damaged area and notthe entire catchments.


16/16

R&R Plan should be realistic and balanced keeping in view the

need of development so as to make a proper trade off between benefits

from development and sacrifice by PAPs.

MoEF guidelines-recovery of NPV of forest land being diverted for

non forest purposes.

Supreme Court has given a range for rates from Rs.5.8 lakh/ha toRs.9.2 lakh/ha for NPV.

Kanchan Chopra Report has requested for an exemption of 30%

from chargeable NPV for major irrigation and hydel projects.

Levying these rates of NPV on hydro projects would increase their

hard cost and proportionately increase the tariff. This would make the

projects costly and sometimes unviable.

Developers are already paying a huge amount to State Forest

Department in lieu of the diversion of forest land. Furthermore,

compensatory afforestation is done.

The exercise of updating the land records of affected areas may be

taken up by the States in right earnest at the stage of planning hydro

projects to prevent double recording.

States should assume responsibility to enrol the wards of project

affected families under their Employment Exchange and give them

preference for jobs.

Some State Governments are laying down additional conditionality

like minimum release of water downstream of the hydel project,

requirement to obtain consent for the project from State Pollution

Control Board, formation of local area development committees, etc.

These are retrograde steps.

Some of the State Governments are imposing additional costs likekeeping a certain percentage of the project cost towards environment

management plan and local area development over and above the

provisions made under R&R including community development. These

are too much considering the 12% free power given to them.

The Environment Management Plan is executed through the State

Government Departments. However, this is not implemented in true spirit

in a time bound manner.

Some projects fall within the boundaries of protected areas like

National Parks, Sanctuaries etc. However in many protected areas the

settlement rights of the local people has not been finalized by the StateGovernment.

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Issues in Electricity Generation

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