part 1: overview of cogeneration and its status in asia - Fire

PART 1: 

OVERVIEW OF COGENERATION AND ITS STATUS IN ASIA

The concept of cogeneration 3 

1.1 Introduction 

CHAPTER 1: THE CONCEPT OF COGENERATION 

Industries and commercial buildings all over the world are the major energy end-users. In the 

developing countries of the Asia-Pacific region, electricity accounts for only around 20 per 

cent of the total energy demand of the industrial sector, the remaining demand being mostly 

in the form of thermal energy. Likewise, as much as 60 per cent of the energy demand of 

modern high-rise buildings in the tropical climate comes from comfort cooling. Typically, 

state-owned power companies assure electricity supply whereas on-site boilers and chillers 

meet the heating and cooling needs of the users, respectively. 

Thermal power plants are a major source of electricity supply in many developing countries. 

The conventional method of power generation and supply to the customer is wasteful in the 

sense that about a quarter of the primary energy fed into the power plant is actually made 

available to the user in the form of electricity. The major source of loss in the conversion 

process is the heat rejected to the surrounding water or air due to the inherent constraints of 

the different thermodynamic cycles employed in power generation. Moreover, users may be 

far from the point of generation, which results in additional transmission and distribution 

losses in the network. The concept of cogeneration is based on the principle of thermal 

cascading which consists of generating power on site where a substantial fraction of waste 

heat produced is recovered to satisfy the heating/cooling demand of the end-user. There is 

thus a considerable enhancement of the overall conversion efficiency. 

Combined heat and power generation (CHP), or cogeneration as it is popularly known, is 

widely recognized world-wide as an attractive alternative to the conventional power and heat 

generating options due to its low capital investment, shorter gestation period, reduced fuel 

consumption and associated environmental pollution, and increased fuel diversity. 

Though the concept of cogeneration has been in existence for over a century now, it found its 

popularity and renewed interest during the later half of the 70s and the early 80s. The main 

factors that attributed to this phenomenon are the two oil shocks that led to spiralling energy 

prices and the availability of efficient and small-scale cogeneration systems which became 

cost-effective and competed well with the conventional large-scale electricity generation 

units. A variety of measures were undertaken by several national authorities to promote the 

growth of cogeneration. 

As energy prices started to fall during the mid-80s, some countries lost interest in this 

technology, particularly those that had excess generating capacities. Taking the example of 

Europe, a great diversity can be observed among the member countries; electricity produced 

from cogeneration ranged from over 34 per cent in the Netherlands whereas it was less than 

1.5 per cent in France. 

The main reasons that have revived the interest in cogeneration once again are the rapidly 

increasing demand for electricity, constraints faced by the national authorities to finance 

additional power generating capacities, and the growing concern to limit the environmental 

emission and pollution associated with the use of energy. Cogeneration is presently being 

recommended when there is plan for expansion of existing facilities, development of new 

industrial zones, replacement of outdated steam generation systems, or when the cost of 

energy is high and there is scope for selling power.

4 Part I: Overview of cogeneration and its status in Asia 

1.2 Principle of Cogeneration 

Cogeneration is defined as the sequential generation of two different forms of useful energy 

from a single primary energy source, typically mechanical energy and thermal energy. 

Mechanical energy may be used either to drive an alternator for producing electricity, or 

rotating equipment such as motor, compressor, pump or fan for delivering various services. 

Thermal energy can be used either for direct process applications or for indirectly producing 

steam, hot water, hot air for dryer or chilled water for process cooling. 

Cogeneration provides a wide range of technologies for application in various domains of 

economic activities. The overall efficiency of energy use in CHP mode can be up to 80 per 

cent and above in some cases. A typical small gas turbine based CHP unit can save about 

40 per cent of the primary energy when compared with a fossil fuel fired conventional power 

plant and a boiler house (see Figure 1.1 below). Along with the saving of fossil fuels, 

cogeneration also allows to reduce the emission of greenhouse gases (particularly CO2 

emission) per unit of useful energy output. The production of electricity being on-site, the 

burden on the utility network is reduced and the transmission line losses eliminated. 

Input 

Energy 

100 

Heat Loss 

20 

Electricity 

30 

Heat 

50 

Heat Loss 

6 

Heat Loss 

56 

Input for 

Power 

Generation 

(i) Cogeneration System (ii)Conventional System 

86 

Input for 

Boiler 

Figure 1.1 Conventional energy system versus cogeneration system 

56 

Input 

Energy 

Cogeneration makes sense from both macro and micro perspectives. At the macro level, it 

allows a part of the financial burden of the national power utility to be shared by the private 

sector; in addition, indigenous energy sources are preserved or the fuel import bill is reduced. 

At the micro level, the overall energy bill of the users can be reduced, particularly when there 

is a simultaneous need for both power and heat at the site, and a rational energy tariff is 

practised in the country. 

1.3 From Self Electricity Generation to Cogeneration 

In Asian developing countries, it is not unusual to come across situations of grid power 

supply interruptions either due to technical failure of the system or because the consumer 

demand during a given time period exceeds the utility supply capacity. Industries and 

commercial buildings normally adopt stand-by power generators for taking care of their 

essential loads during these periods. It is essential to assure continuity of some activities to 

minimize production losses or guarantee minimum comfort of the clients. The stand-by 

generators have limited use in the year; moreover, these devices require investment and 

142


incur operation and maintenance costs while contributing practically nothing to reduce the 

overall energy bill of the site. 

Since these generators serve the main purpose of assuring emergency power to priority 

areas of the site, no financial analysis is carried out to assess their economic viability. 

However, these generators offer the possibility of continuous power generation so that the 

monthly power bill of the site can be reduced. Such benefits accrued can well justify the need 

for higher investment that is associated with prime movers which are designed to operate 

continuously and at higher efficiencies. 

In a gas turbine or reciprocating engine, typically a third of the primary fuel supplied is 

converted into power while the rest is discharged as waste heat at a relatively high 

temperature, ranging between 300 and 500ºC. At sites having a need for thermal energy in 

one form or the other, this waste heat can be recovered to match the quantity and level of 

requirements. For instance, steam may be needed at low or medium pressures for process 

applications. Any heat recovered from the exhaust gases of the prime movers will help to 

save the primary energy that would have been otherwise required by the on-site conversion 

facility such as boilers or dryers. 

An ideal site for cogeneration has the following characteristics: 

• a reliable power requirement; 

• relatively steady electrical and thermal demand patterns; 

• higher thermal energy demand than electricity; 

• long operating hours in the year; 

• inaccessibility to the grid or high price of grid electricity. 

Typical cogeneration applications may be in three distinct areas: 

a) Utility cogeneration: caters to district heating and/or cooling. The cogeneration facility 

may be located in industrial estates or city centres; 

b) Industrial cogeneration: applicable mainly to two types of industries, some requiring 

thermal energy at high temperatures (refineries, fertilizer plants, steel, cement, ceramic 

and glass industries), and others at low temperatures (pulp and paper factories, textile 

mills, food and beverage plants, etc.); 

c) Commercial/institutional cogeneration: specifically applicable to establishments having 

round-the-clock operation, such as hotels, hospitals and university campuses. 

1.4 Technical Options for Cogeneration 

Cogeneration technologies that have been widely commercialized include extraction/back 

pressure steam turbines, gas turbine with heat recovery boiler (with or without bottoming 

steam turbine) and reciprocating engines with heat recovery boiler. 

1.4.1 Steam turbine cogeneration systems 

The two types of steam turbines most widely used are the backpressure and the extractioncondensing 

types (see Figure 1.2). The choice between backpressure turbine and extractioncondensing 

turbine depends mainly on the quantities of power and heat, quality of heat, and


economic factors. The extraction points of steam from the turbine could be more than one, 

depending on the temperature levels of heat required by the processes. 

Fuel 

Boiler 

Steam 

Process 

Turbine 

Steam 


(i) Back-Pressure Turbine (ii) Extraction-Condensing Turbine 

Fuel 

Boiler 

Process 

Condenser 

Figure 1.2 Schematic diagrams of steam turbine cogeneration systems 

Cooling 

Water 

Another variation of the steam turbine topping cycle cogeneration system is the extractionback 

pressure turbine that can be employed where the end-user needs thermal energy at two 

different temperature levels. The full-condensing steam turbines are usually incorporated at 

sites where heat rejected from the process is used to generate power. 

The specific advantage of using steam turbines in comparison with the other prime movers is 

the option for using a wide variety of conventional as well as alternative fuels such as coal, 

natural gas, fuel oil and biomass. The power generation efficiency of the cycle may be 

sacrificed to some extent in order to optimize heat supply. In backpressure cogeneration 

plants, there is no need for large cooling towers. Steam turbines are mostly used where the 

demand for electricity is greater than one MW up to a few hundreds of MW. Due to the 

system inertia, their operation is not suitable for sites with intermittent energy demand. 

1.4.2 Gas turbine cogeneration systems 

Gas turbine cogeneration systems can produce all or a part of the energy requirement of the 

site, and the energy released at high temperature in the exhaust stack can be recovered for 

various heating and cooling applications (see Figure 1.3). Though natural gas is most 

commonly used, other fuels such as light fuel oil or diesel can also be employed. The typical 

range of gas turbines varies from a fraction of a MW to around 100 MW. 

Gas turbine cogeneration has probably experienced the most rapid development in the recent 

years due to the greater availability of natural gas, rapid progress in the technology, 

significant reduction in installation costs, and better environmental performance. 

Furthermore, the gestation period for developing a project is shorter and the equipment can 

be delivered in a modular manner. Gas turbine has a short start-up time and provides the 

flexibility of intermittent operation. Though it has a low heat to power conversion efficiency, 

more heat can be recovered at higher temperatures. If the heat output is less than that 

required by the user, it is possible to have supplementary natural gas firing by mixing 

additional fuel to the oxygen-rich exhaust gas to boost the thermal output more efficiently.


Electricity 

Generator 

Fuel Air 

Flue 

Gases 

(~ 500 °C) 

Gas Turbine 

Boiler 

Exhaust 

Heat (~ 150 °C) 

Steam 

Water 

Figure 1.3 Schematic diagram of gas turbine cogeneration 

On the other hand, if more power is required at the site, it is possible to adopt a combined 

cycle that is a combination of gas turbine and steam turbine cogeneration. Steam generated 

from the exhaust gas of the gas turbine is passed through a backpressure or extractioncondensing 

steam turbine to generate additional power. The exhaust or the extracted steam 

from the steam turbine provides the required thermal energy. 

1.4.3 Reciprocating engine cogeneration systems 

Also known as internal combustion (I. C.) engines, these cogeneration systems have high 

power generation efficiencies in comparison with other prime movers. There are two sources 

of heat for recovery: exhaust gas at high temperature and engine jacket cooling water system 

at low temperature (see Figure 1.4). As heat recovery can be quite efficient for smaller 

systems, these systems are more popular with smaller energy consuming facilities, 

particularly those having a greater need for electricity than thermal energy and where the 

quality of heat required is not high, e.g. low pressure steam or hot water. 

Though diesel has been the most common fuel in the past, the prime movers can also 

operate with heavy fuel oil or natural gas. In urban areas where natural gas distribution 

network is in place, gas engines are finding wider application due to the ease of fuel handling 

and cleaner emissions from the engine exhaust. 

These machines are ideal for intermittent operation and their performance is not as sensitive 

to the changes in ambient temperatures as the gas turbines. Though the initial investment on 

these machines is low, their operating and maintenance costs are high due to high wear and 

tear. 

1.5 Classification of Cogeneration Systems 

Cogeneration systems are normally classified according to the sequence of energy use and 

the operating schemes adopted.


I.C. Engine 

Coolers 

~ 450 °C 

Oil Air Water 

Exhaust 

Heat 

Boiler 

~ 200 °C 

Steam or Hot Water 

Process 

Figure 1.4 Schematic diagram of reciprocating engine cogeneration 

A cogeneration system can be classified as either a topping or a bottoming cycle on the 

basis of the sequence of energy use. In a topping cycle, the fuel supplied is used to first 

produce power and then thermal energy, which is the by-product of the cycle and is used to 

satisfy process heat or other thermal requirements. Topping cycle cogeneration is widely 

used in pulp and paper, food processing, textile industries, districting heating, hotels, 

hospitals and universities. In a bottoming cycle, the primary fuel produces high temperature 

thermal energy and the heat rejected from the process is used to generate power through a 

recovery boiler and a turbine generator. Bottoming cycles are suitable for manufacturing 

processes that require heat at high temperature in furnaces and kilns, and reject heat at 

significantly high temperatures. Typical areas of application include cement, steel, ceramic, 

gas and petrochemical industries. 

Cogeneration systems can also be classified according to the operating scheme whose 

choice is very much site-specific and depends on several factors, as described below: 

1.5.1 Base electrical load matching 

In this configuration, the cogeneration plant is sized to meet the minimum electricity demand 

of the site based on the historical demand curve. The rest of the needed power is purchased 

from the utility grid. The thermal energy requirement of the site could be met by the 

cogeneration system alone or by additional boilers. If the thermal energy generated with the 

base electrical load exceeds the plant’s demand and if the situation permits, excess thermal 

energy can be exported to neighbouring customers. 

1.5.2 Base thermal load matching 

Here, the cogeneration system is sized to supply the minimum thermal energy requirement 

of the site. Stand-by boilers or burners are operated during periods when the demand for heat 

is higher. The prime mover installed operates at full load at all times. If the electricity demand 

of the site exceeds that which can be provided by the prime mover, then the remaining 

amount can be purchased from the grid. Likewise, if local laws permit, the excess electricity 

can be sold to the power utility.


1.5.3 Electrical load matching 

In this operating scheme, the facility is totally independent of the power utility grid. All the 

power requirements of the site, including the reserves needed during scheduled and 

unscheduled maintenance, are to be taken into account while sizing the system. This is also 

referred to as a “stand-alone” system. If the thermal energy demand of the site is higher than 

that generated by the cogeneration system, auxiliary boilers are used. On the other hand, 

when the thermal energy demand is low, some thermal energy is wasted. If there is a 

possibility, excess thermal energy can be exported to neighbouring facilities. 

1.5.4 Thermal load matching 

The cogeneration system is designed to meet the thermal energy requirement of the site at 

any time. The prime movers are operated following the thermal demand. During the period 

when the electricity demand exceeds the generation capacity, the deficit can be 

compensated by power purchased from the grid. Similarly, if the local legislation permits, 

electricity produced in excess at any time may be sold to the utility. 

1.6 Important Technical Parameters for Cogeneration 

While selecting cogeneration systems, one should consider some important technical 

parameters that assist in defining the type and operating scheme of different alternative 

cogeneration systems to be selected. 

1.6.1 Heat-to-power ratio 

Heat-to-power ratio is one of the most important technical parameters influencing the 

selection of the type of cogeneration system. The heat-to-power ratio of a facility should 

match with the characteristics of the cogeneration system to be installed. 

It is defined as the ratio of thermal energy to electricity required by the energy consuming 

facility. Though it can be expressed in different units such as Btu/kWh, kcal/kWh, lb./hr/kW, 

etc., here it is presented on the basis of the same energy unit (kW). 

Basic heat-to-power ratios of the different cogeneration systems are shown in Table 1.1 

along with some technical parameters. The steam turbine cogeneration system can offer a 

large range of heat-to- power ratios. 

Table 1.1 Heat-to-power ratios and other parameters of cogeneration systems 

Cogeneration System Heat-topower 

ratio 

(kWth / kWe) 

Power output 

(as per cent 

of fuel input) 

Overall 

efficiency 

(per cent) 

Back-pressure steam turbine 4.0-14.3 14-28 84-92 

Extraction-condensing steam turbine 2.0-10.0 22-40 60-80 

Gas turbine 1.3-2.0 24-35 70-85 

Combined cycle 1.0-1.7 34-40 69-83 

Reciprocating engine 1.1-2.5 33-53 75-85 

1.6.2 Quality of thermal energy needed 

The quality of thermal energy required (temperature and pressure) also determines the type 

of cogeneration system. For a sugar mill needing thermal energy at about 120°C, a topping 

cycle cogeneration system can meet the heat demand. On the other hand, for a cement plant


requiring thermal energy at about 1450°C, a bottoming cycle cogeneration system can meet 

both high quality thermal energy and electricity demands of the plant. 

1.6.3 Load patterns 

The heat and power demand patterns of the user affect the selection (type and size) of the 

cogeneration system. For instance, the load patterns of two energy consuming facilities 

shown in Figure 1.5 would lead to two different sizes, possibly types also, of cogeneration 

systems. 

kW kW 

kW 

Time Time 

(i) Factory “A” (ii) Factory “B” 

Electricity Thermal Energy 

Figure 1.5 Different heat and power demand patterns in two factories 

1.6.4 Fuels available 

Depending on the availability of fuels, some potential cogeneration systems may have to be 

rejected. The availability of cheap fuels or waste products that can be used as fuels at a site 

is one of the major factors in the technical consideration because it determines the 

competitiveness of the cogeneration system. 

A rice mill needs mechanical power for milling and heat for paddy drying. If a cogeneration 

system were considered, the steam turbine system would be the first priority because it can 

use the rice husk as the fuel, which is available as waste product from the mill. 

1.6.5 System reliability 

Some energy consuming facilities require very reliable power and/or heat; for instance, a pulp 

and paper industry cannot operate with a prolonged unavailability of process steam. In such 

instances, the cogeneration system to be installed must be modular, i.e. it should consist of 

more than one unit so that shut down of a specific unit cannot seriously affect the energy 

supply. 

1.6.6 Grid dependent system versus independent system 

A grid-dependent system has access to the grid to buy or sell electricity. The gridindependent 

system is also known as a “stand-alone” system that meets all the energy 

demands of the site. It is obvious that for the same energy consuming facility, the technical 

configuration of the cogeneration system designed as a grid dependent system would be 

different from that of a stand-alone system.


1.6.7 Retrofit versus new installation 

If the cogeneration system is installed as a retrofit, the system must be designed so that the 

existing energy conversion systems, such as boilers, can still be used. In such a 

circumstance, the options for cogeneration system would depend on whether the system is a 

retrofit or a new installation. 

1.6.8 Electricity buy-back 

The technical consideration of cogeneration system must take into account whether the local 

regulations permit electric utilities to buy electricity from the cogenerators or not. The size 

and type of cogeneration system could be significantly different if one were to allow the export 

of electricity to the grid. 

1.6.9 Local environmental regulation 

The local environmental regulations can limit the choice of fuels to be used for the proposed 

cogeneration systems. If the local environmental regulations are stringent, some available 

fuels cannot be considered because of the high treatment cost of the polluted exhaust gas 

and in some cases, the fuel itself.

State of art review of cogeneration 13 

CHAPTER 2: STATE OF ART REVIEW OF COGENERATION 

2.1 Technological Advances in Cogeneration 

Cogeneration plants benefit from many of the energy efficiency improvements that are 

brought about in utility power generation because the same basic technology is employed in 

both cases. However, cogeneration being more attractive for small-scale decentralized 

applications, significant technological progress has been made in the development of 

modular and packaged cogeneration systems of lower capacities. Moreover, as such 

systems are being adopted in industrial zones and city centres, the stringent laws and 

regulations put in place for protecting the local environment has obliged the cogeneration 

technology providers to innovate incessantly. The greater availability of natural gas in many 

parts of the world has helped in the maturing of gas turbine technology. In addition, the 

possibility of using alternative fuels such as wood, agro-industrial residues, biogas, etc., for 

powering small-scale cogeneration systems has led to further technological progresses by 

taking the specific characteristics of the fuels into consideration. This section briefly 

describes some of the developments in this domain. 

2.2 Reciprocating Engines 

Reciprocating engines are mostly employed in low and medium power cogeneration units. 

The lower and upper limits of engine sizes are often a function of the fuel in use; these can 

range from 50 kW to 10 MW for natural gas, from 50 kW to 50 MW for diesel, and 2.5 MW to 

50 MW for heavy fuel oil. One of the major advantages of reciprocating engines is their higher 

electrical efficiency as compared to other prime movers. 

The two main types of internal combustion engines employed in cogeneration systems are 

diesel engines and Otto engines. The characteristic feature of the Otto engine is that an 

electric spark from a spark plug ignites a mixture of fuel and air, and this is thus known widely 

as a spark-ignition engine. In power generation applications, the Otto engine may be either a 

gasoline engine or a diesel engine converted to have spark-ignition operation. Gasoline 

engines have the ratings ranging from 20 kW to 1.5 MW. The spark-ignition engines 

converted from diesel engines and running on natural gas are available in ratings from 5 kW 

to 4 MW. The Otto engines operate at speeds between 750-3,000 rpm and have the electrical 

efficiencies of 25-35 per cent. These engines can run on different fuels such as gasoline, 

natural gas, producer gas, and digester gas. 

As opposed to Otto engines, fuel is injected into the diesel engine cylinders in which it mixes 

with air and is ignited by the heat generated when the pistons compress the fuel/air mixture, 

and this engine is often known as a compression-ignition engine. Diesel engines can 

generally be classified into two main categories, i.e. two-stroke and four-stroke engines. The 

two-stroke engine is also known as a low-speed engine, and is characterized by ignition 

taking place once every revolution, and by the engine running at a speed below 200 rpm and 

delivering an output of 1-50 MW at a high electrical efficiency of 45-53 per cent. In a fourstrike 

engine, ignition takes place during every other revolution, and this engine can be 

divided into two categories. Medium speed engines are those running at speeds between 

400 and 1,000 rpm and can be designed for ratings between 0.5 and 20 MW with electrical 

efficiencies of 35-48 per cent. High-speed engines are those operating at speeds between 

1,000 and 2,000 rpm and with ratings between a few kW and about 2 MW with electrical 

efficiencies of 35-40 per cent.


Diesel engines can run on a variety of fuels such as diesel, heavy fuel oil, light fuel oil, LPG, 

natural gas, producer gas, digester gas, etc. The diesel engines that are converted to gas 

engines are also known as dual-fuel engines. In their operation, the main fuel is gas, which is 

ignited by a small quantity of pilot oil, usually diesel oil. The pilot oil is used to make sure that 

the gas in the cylinder will ignite. The gas/oil ratio is normally controlled so that the proportion 

of pilot oil at full engine power will be around 5 per cent of the fuel quantity supplied. Diesel 

engines running in gas engine mode can be classified in another way into two groups: lowpressure 

dual-fuel engines and high-pressure dual-fuel engines. 

Typical heat balance diagram of a gas engine is shown in Figure 2.1. About 25 per cent of the 

heat recovered from the engine cooling system (cooling water, oil cooler and inlet air cooler) 

is low grade at a temperature of about 95°C. Considering the same power output, the amount 

of heat recoverable at high temperature is lower than that for the gas turbine. That is why 

cogeneration with reciprocating engine is more commonly used for producing hot water/hot 

air or low pressure steam. However, medium pressure steam can be generated by 

employing supplementary firing since exhaust gases from gas engines have an O2 content of 

about 15 per cent. 

1.5% 

Generator 

losses 

100 % 

Mechanical Thermal 

38% 

62% 

36.5% 25.0% 24.5% 

Electrical Thermal 

36.5% 49.5% 

Overall efficiency 

86% 

Engine 

Cooling 

System 

Exhaust 

gas 

Figure 2.1 Typical heat balance of a gas engine 

5% 

Radiation 

losses 

7.5% 

Exhaust gas 

losses 

In the operation of low-pressure dual-fuel engines, gas at low pressure, i.e. 3-5 bar, is 

mixed with the engine combustion air during the induction cycle. The gas/combustion air 

mixture is compressed in the cylinder and is ignited at the top dead centre by a small amount 

(approximately 5 per cent) of diesel oil being injected into the cylinder and ignited in the usual 

manner. Low-pressure dual-fuel engines have relatively low ratings and efficiencies. The 

system is sensitive to variations in gas quality. 

Gas is compressed outside the engine in a separate compressor in a high-pressure dualfuel 

engine up to 250 bar and is injected into the cylinder with a minor amount of pilot oil 

when the piston is in the vicinity of the top dead centre. High-pressure dual-fuel engines have


higher ratings and efficiencies and they are not sensitive to the gas quality. High-pressure 

dual-fuel engines are available in both two-stroke and four-stroke versions. 

2.3 Gas Turbines 

Gas turbines used for cogeneration are usually designed for continuous duty because gas 

turbines for stand-by use normally have low efficiencies and are most suitable for 

applications where the operating periods are short. 

Gas turbines for continuous duty are traditionally divided into two groups on the basis of 

differences in design philosophy (there is now some convergence in their design). 

The aero-derivative gas turbine, as its name indicates, is more or less derived from an 

aircraft propulsion engine. The characteristics of aero-derivative gas turbines are low specific 

weight, low fuel consumption, high reliability, etc. The major advantages of aero-derivative 

gas turbines are high levels of efficiency and a compact and modular design with easy 

access for maintenance. However, because skilled service personnel are required, gas 

turbines of this type are often taken off the site for maintenance. Aero-derivative gas turbines 

require a relatively high specific investment cost ($/kWe), high quality fuel and may 

experience a lowering in output and efficiency after a long period of operation. 

The industrial gas turbine, also referred to as the heavy duty or heavy frame gas turbine, is a 

robust unit constructed for stationary duty and continuous operation. It has a somewhat lower 

efficiency than the aero-derivative type, but usually maintains its performance over a longer 

period of operation. Maintenance can be easily carried out on site, and maintenance costs 

are low. The industrial gas turbine usually has a lower specific investment cost than its aeroderivative 

counterpart. Furthermore, it has the ability to make use of low quality fuel. 

The performance of a gas turbine depends on the pressure and temperature of ambient air 

that is compressed. Since the ambient conditions vary from day-to-day and from location-tolocation, 

it is convenient to consider some standard conditions for comparative purposes. 

The standard conditions used by the gas turbine industry are 15°C, 1.013 bar (14.7 psia) and 

60 per cent relative humidity, which are established by the International Standards 

Organization (ISO). The performance of gas turbines is expressed under ISO conditions. 

The actual power output of a gas turbine varies with ambient conditions. The power output of 

a gas turbine decreases when the ambient temperature rises. In contrast, the power output 

increases with the ambient pressure. The variations in power outputs of a typical gas turbine 

with ambient conditions are shown in Figure 2.2 as a percentage of ISO power output. 

The heat recovery steam generator (HRSG) is one of the major components of the gas 

turbine cogeneration system. Since the energy content of the exhaust gas rejected to the 

atmosphere is considerably high, HRSGs are designed to produce process steam (or hot 

water) by recovering a large share of the energy contained in the exhaust stream. The 

exhaust gas at 500-550°C is cooled in the HRSG to about 150°C to extract useful heat. A 

temperature of 150°C is recommended at the outlet of the HRSG to avoid condensation of 

exhaust gases. At lower temperature levels, gases such as SOx and NOx would form acids 

along with the condensation and corrode the materials of HRSG.


% of ISO Power Output 

120 

110 

100 

90 

80 

70 

60 

10 11 12 13 14 15 

Ambient Pressure (psia) 

% of ISO Power Output 

120 

110 

100 

90 

80 

70 

60 

-5 5 15 25 35 

Ambient Temperature (°C) 

Figure 2.2 Power output variation of a gas turbine with the ambient conditions 

The basic heat-to-power ratio of a simple gas turbine cogeneration system is about two. 

However, supplementary firing can double the heat-to-power ratio. The HRSG with 

supplementary firing option contains an additional burner to increase the heat output of the 

whole system. This is made possible due to the high oxygen content of the exhaust gases, 

typically 14 to 17 per cent, as a result of the need for high excess air in the combustion 

chamber (for avoiding very high hot gas temperature that can affect the turbine). By adding 

supplemental firing, fuel consumption increases slightly, however the steam production 

increases significantly. Addition of supplemental firing is quite common in gas turbine 

cogeneration systems. 

In a gas turbine cogeneration cycle, the power output can be increased by steam injection. 

High-pressure steam produced in HRSG can be injected into the combustion chamber so 

that the mass flow rate through the turbine is increased. Steam injection allows the flexibility 

of matching with the process steam demand and can increase the power output by about 15 

per cent. 

Electrical Efficiency (%) 

40 

35 

30 

25 

20 

15 

10 

5 

0 

0 5 10 15 20 25 30 35 40 

ISO Power Output (MW) 

Electrical Efficiency (%) 

40 

35 

30 

25 

20 

15 

10 

5 

0 

0 5 10 15 20 25 30 35 40 

ISO Power Output (MW) 

(i) Aero-Derivative (ii) Industrial 

Figure 2.3 Power generation efficiency ranges of gas turbines 

The power generation efficiency ranges of aero-derivative and industrial gas turbines are 

compared in Figure 2.3. The overall efficiency of the gas turbine cogeneration system is good 

without post-combustion (70 to 85 per cent), which can be further boosted to between 83 and 

89 per cent with post-combustion. When the system is opted as a retrofit in a facility already 

having boilers, it is at times possible to make use of the existing boilers.


Recuperators are used to increase the power output of gas turbine cogeneration systems if 

the heat demands are low. The recuperator is in fact only a heat exchanger that is employed 

to heat the air leaving the compressor. The exhaust stream from the turbine is passed 

through the recuperator before going into the HRSG so that a part of the energy contained in 

turbine exhaust is utilized in the recuperator. The gas turbine cogeneration system with 

recuperator is sometimes known as the heat exchange cycle. 

2.4 Steam Turbines 

Steam turbines are the most commonly employed prime movers for cogeneration 

applications, particularly in industries and for district heating. The technology is well proven in 

sugar and paper mills having demand for both electricity and large quantity of steam at high 

and low pressures. Some steam turbine manufacturers are over 100 years old and have 

products ranging from a few kW to 80 MW. However, turbines below two MW may be 

uneconomical except where the fuel has no commercial value. 

A cogeneration system using a backpressure steam turbine (see Figure 1.2) consists of 

boiler, turbine, heat exchanger and pump. In the steam turbine, the incoming high pressure 

steam is expanded to a lower pressure level, converting the thermal energy of high pressure 

steam to kinetic energy through nozzles and then to mechanical power through rotating 

blades. Thermal energy of the turbine exhaust steam is then transferred to another fluid, 

water, air, etc., in a heat exchanger, providing heat to the processes. For instance, the air 

heated by heat exchanger can be used to dry products in food processing industries. 

Depending on the pressure (or temperature) levels at which process steam is required, 

backpressure steam turbines can have different configurations. The most common types of 

backpressure steam turbines are shown in Figure 2.4. In extraction and double extraction 

backpressure turbines, some amount of steam is extracted from the turbine after being 

expanded to a certain pressure level. The extracted steam meets the heat demands at 

pressure levels higher than the exhaust pressure of the steam turbine. 

The backpressure steam turbine has a higher heat to power ratio and higher overall 

efficiency. Furthermore, back pressure turbine cogeneration systems need less auxiliary 

equipment than condensing systems, leading to lower initial investment costs. 

The extraction condensing turbines have higher power to heat ratio in comparison with 

backpressure turbines. Although condensing systems need more auxiliary equipment such 

as the condenser and cooling towers, better matching of electrical power and heat demand 

can be obtained where electricity demand is much higher than the steam demand and the 

load patterns are highly fluctuating. 

In the reheat cycle, steam is extracted from the turbine and reheated in the boiler during the 

expansion process. Reheat cycles improve the overall thermal efficiency and eliminate any 

moisture that may form as the steam pressure and temperature are lowered in the turbine. 

Steam turbines may also include a regenerative cycle where the steam is extracted from the 

turbine and used to preheat the boiler feedwater. 

The efficiency of a backpressure steam turbine cogeneration system is the highest. In cases 

where 100 per cent backpressure exhaust steam is used, the only inefficiencies are gear 

drive and electric generator losses, and the inefficiency of steam generation. Therefore, with 

an efficient boiler, the overall thermal efficiency of the system could reach as much as 90 per 

cent.


High pressure steam Extracted steam Exhaust steam 

(i) Simple backpressure (ii) Extraction backpressure (iii) Double extraction 

backpressure 

Figure 2.4 Different configurations for back pressure steam turbines 

The overall thermal efficiency of an extraction condensing turbine cogeneration system is 

lower than that of back pressure turbine system, basically because the exhaust heat cannot 

be utilized (it is normally lost in the cooling water circuit). However, extraction condensing 

cogeneration systems have higher electricity generation efficiencies. 

The techniques available for energy generation from fossil fuels are well established. In order 

to make greater use of alternative fuels, efforts have been made to take the specificity of fuel 

characteristics into account in order to overcome the technological constraints. The physical 

properties of agro-industrial residues vary considerably and can affect the conversion 

efficiency. Some areas where technological progresses have been made include fuel 

handling, combustion system and pollution abatement equipment. 

Fuel handling and transformation is important for appropriate functioning of the installation. 

Handling biomass residues depends mainly on the fuel granulometry and moisture content. 

Coarse residues can be transformed into homogeneous mass by crushing and chipping. 

Reduction of the moisture content by drying represents two main advantages: increases in 

the fuel heating value, and decrease in the fuel losses through fermentation during storage. 

Suitable technologies are available in the market to cover the handling, drying and storage 

requirements of different types of fuels. 

The selection of combustion system using alternative fuels depends on parameters such as 

the size of the unit, energy required, fuel characteristics, etc. Though grate-fired systems 

(Dutch-oven type or spreader-stokers) have been widely used because of the flexibility they 

offer, suspension burners and fluidized-bed combustors are emerging as relevant 

technologies because of their high conversion efficiencies and improved performance in 

meeting the environmental constraints. In suspension burners, ash is dragged out with the 

exhaust gases or it falls to the furnace bottom. Fluidized-bed combustors control the 

combustion better and make use of an inert material capable of absorbing energy, thus 

maximizing the heat transfer from the fuel. These units are capable of burning fuels with very 

low calorific values. Modern designs of furnaces offer staging combustion and good control of 

air-fuel ratio.


2.5 Trigeneration and Vapour Absorption Cooling 

Trigeneration is the concept of deriving three different forms of energy from the primary 

energy source, namely, heating, cooling and power generation. Also referred to as CHCP 

(combined heating, cooling and power generation), this option allows having greater 

operational flexibility at sites with demand for energy in the form of heating as well as cooling. 

This is particularly relevant in tropical countries where buildings need to be air-conditioned 

and many industries require process cooling. A typical trigeneration facility consists of a 

cogeneration plant, and a vapour absorption chiller which produces cooling by making use of 

some of the heat recovered from the cogeneration system (see Figure 2.5). 

AIR 

FUEL 

Hot 

Gases 

HRSG 

GE Gas Frame Turbine 

6 


Steam 

Steam 

Steam 


Heat 

Exchanger 

Chiller 

Generator 

ELECTRICITY 

Generator 

STEAM 

HOT 

WATER 

CHILLED 

WATER 

ELEC- 

TRICITY 

Figure 2.5 Schematic presentation of a gas turbine based trigeneration facility 

Although cooling can be provided by conventional vapour compression chillers driven by 

electricity, low quality heat (i.e. low temperature, low pressure) exhausted from the 

cogeneration plant can drive the absorption chillers so that the overall primary energy 

consumption is reduced. Absorption chillers have recently gained widespread acceptance 

due to their capability of not only integrating with cogeneration systems but also because they 

can operate with industrial waste heat streams. The benefit of power generation and 

absorption cooling can be realized through the following example that compares it with a 

power generation system with conventional vapour compression system. 

A factory needs 1 MW of electricity and 500 refrigeration tons (RT) 1 . Let us first consider the 

gas turbine that generates electricity required for the processes as well as the conventional 

vapour compression chiller. Assuming an electricity demand of 0.65 kW/RT, the 

compression chiller needs 325 kW of electricity to obtain 500 RT of cooling. Hence, a total of 

1325 kW of electricity must be provided to this factory. If the gas turbine efficiency has an 

efficiency of 30 per cent, primary energy consumption would be 4417 kW. A schematic 

diagram of the system is shown in Figure 2.6. 

1 

Refrigeration ton (RT) is defined as the transfer of heat at the rate of 3.52 kW, which is roughly the 

rate of cooling obtained by melting ice at the rate of one ton per day.


Fuel Input 

4417 kW 


Generator 

1325 kW 

325 kW 

1000 kW 

Process 

Figure 2.6 Schematic diagram of power generation and cooling with electricity 

However, a cogeneration system with an absorption chiller can provide the same energy 

service (power and cooling) by consuming only 3,333 kW of primary energy. A schematic 

diagram of the system is shown in Figure 2.7. 

Fuel Input Generator 

Compression 

Chiller 500 RT Cooling 

3,333 kW Gas Turbine 500 RT Cooling 

2.25 Tons/hr of Steam Absorption 

Recovery Chiller 

Boiler 

Exhaust 

Heat 

1,000 kW 

Process 

Figure 2.7 Schematic diagram of power generation and absorption cooling 

It can be seen that the cogeneration system incorporating an absorption chiller can save 

about 24.5 per cent of primary energy in comparison with the power generation system and 

vapour compression chiller. Furthermore, a smaller prime mover leads to not only lower 

capital cost but also less standby charge during the system breakdown because steam 

needed for the chiller can still be generated by auxiliary firing of the waste heat boiler. 

Since many industries and commercial buildings in tropical countries need combined power 

and heating/cooling, the cogeneration systems with absorption cooling have very high 

potentials for industrial and commercial application.


2.6 Working Principle of Absorption Chillers 

Like the vapour compression chiller (VCC), the vapour absorption chiller (VAC) extracts heat 

in the evaporator which is placed in the space to be cooled and rejects this heat in the 

condenser. However, VAC needs a heat source as the driving force while VCC requires 

mechanical power or electricity for the same duty. Figure 2.8 shows the schematic diagrams 

of VCC and VAC. 

High Pressure 

High Pressure 

Vapour 

Vapour Refrigerant Refrigerant 

Condenser Condenser Generator 

Vapour 

Compressor 

Figure 2.8 Comparison between vapour compression and absorption cycles 

The improved version of the VAC, commonly known as the double effect type, is designed 

such that it utilizes the vaporized refrigerant as an extra heat source. The generator is divided 

into high and low temperature sections. The refrigerant vapour produced in the high 

temperature generator gives up its latent heat to the partially refrigerant-rich solution in the 

low temperature generator that operates at a low pressure, hence the lower boiling point of 

the refrigerant. The energy consumption of a double effect VAC is approximately half that of 

the single effect VAC for the same cooling effect. Moreover, heat rejected in the condenser is 

also reduced, resulting in smaller condenser and cooling tower. 

The performances of absorption chillers strongly depend on the thermo-physical properties of 

the working pair, i.e., the refrigerant and absorbent. Binary working pairs such as ammoniawater 

(NH3-H2O) and lithium bromide-water (LiBr-H2O) have been employed commercially in 

absorption chillers for a long time and these are in commercial use. A single effect LIBr-H2O 

absorption chiller requires about 0.8 m 3 /h of hot water at around 90ºC or 8.3 kg/h of steam at 

1.5 bar to provide 1 RT. On the other hand, a double effect chiller requires only 4.5 kg/h of 

steam, though at a higher pressure between 6 and 8 bar. 

2.7 District Heating/Cooling Network 

Heat 

Mechanical Input 

Heat 

Power/Electricity Exchanger 

Evaporator Evaporator Absorber 

Low Pressure Low Pressure 

Vapour Refrigerant Vapour Refrigerant 

(i) Vapour Compression Chiller (ii) Vapour Absorption Chiller 

Individual buildings and industries may lack economies of scale when setting up cogeneration 

facilities and it may not be always possible to optimize the design parameters due to the 

peculiarity of the energy demand patterns. In such cases, one may think of developing a 

facility that caters to several user-groups with varying demand patterns that can be 

complimentary. In the building sector, for instance, offices are active during the daytime


whereas hotels may have high loads at nights. When the two loads are combined, a uniform 

composite curve may be obtained with very small amplitude. 

Besides, there are a number of justifications for grouping together several buildings and 

industries in order to meet their different energy services, such as: 

- larger cogeneration system and the economies of scale associated with it; 

- system expansion to users for whom individual facility cannot be justified; 

- improvement in the overall generation efficiency; 

- increased reliability and availability of utility services; 

- pooling of maintenance personnel and reduction in manpower cost; 

- saving of mechanical room space in the user buildings; 

- purchase of fuel at more competitive rate; 

- better negotiation power for power purchase/sale to the electric utility, etc. 

There are, however, a few drawbacks to district heating/cooling, the most important among 

them being the high initial investment on the system. The cost of steam/hot water and chilled 

water transportation and distribution can also be high. Because of the down-sizing of the 

different components installed at the central plant, capital investment cost can in fact be 

reduced by 10 to 20 per cent as compared to those which would have been required in the 

individual buildings. This takes into account the piping distribution network cost that is not 

required in conventional decentralized systems. For instance, a district cooling network is 

installed in Paris which includes three chiller plants with a total of 25,500 RT to supply to a 

museum, shopping complex, exhibition centre and offices having a total equivalent area 

exceeding one million m 2 . Decentralized plants would have required a total capacity of 

approximately 34,100 RT to be installed. The district-cooling network has thus helped to 

achieve an investment saving of over US$ 8 million for the reduced installed cooling capacity. 

2 

2.8 Evolution of Package Cogeneration 

Cogeneration systems traditionally constituted various components which were ordered and 

assembled at the site according to the client’s requirements, mostly matching the thermal 

energy needs. The minimum power generation capacity was of the order of a few MW due to 

the limited products available in the market, some of the reasons being: 

1) Investment cost per kWe is considerably higher for smaller units; 

2) Limited financing capabilities of small and medium scale enterprises; 

3) Additional investment needed by smaller units to cope with environmental regulations; 

4) Unavailability of guarantee for the overall system. 

2 R. Caillaud, “District cooling with thermal storage for shifting power loads in south-east Asia”, APEC 

Demand-side Management Inter-Utility Liaison Group Meeting, Chiang Mai, 26-29 March 1996.


However, trends have changed considerably with the introduction of modular concept which 

consists of cogeneration units packaged as “of-the-shelf" products and whose 

performances, both electrical and thermal, are guaranteed by suppliers who act as the sole 

responsible for the design of the overall system and all its interfaces. This has led to 

widespread propagation of cogeneration plants with power generating capacities less than a 

MW. Many of these adopted by enterprises that are located at the end of electric networks 

and are faced with the problem of getting reliable and uninterrupted power. Moreover, the 

expansion of the natural gas network has made it possible to employ gas engines of smaller 

capacities in urban areas without violating the environmental regulations. For example, over 

2,500 units have been installed in the Netherlands alone in the range between 100 and 300 

kW, the main clients being hospitals, community buildings, sports centres, teaching 

establishments, commercial buildings, small and medium enterprises, etc. 

A typical module of less than one MWe capacity presents itself as a mono-bloc, compact and 

soundproofed packaged unit, consisting of the following: 

− engine for mechanical energy generation; 

− alternator for electrical output; 

− heat recovery unit for thermal energy generation; 

− component for evacuation of combustion products; 

− control system, electrical protection and low voltage connection box; 

− soundproofing insulation. 

These modules are designed for being installed within a few days with very little structural or 

engineering work at the site. Moreover, as the components are well matched, high efficiency 

is guaranteed for the overall system. Some of these cogeneration facilities are designed for 

“trigeneration” at sites with process or space cooling needs. 

The strength of the package units lies with their high overall efficiency and system availability. 

Manufacturers propose cogeneration systems whose overall efficiency can be between 84 

and 92 per cent (with a mechanical efficiency between 30 and 35 per cent) and 95 per cent 

availability. Variations in their performances are a function of the type of prime mover, the 

level at which heat is required, and the quality of heat recovery devices. 

The package cogeneration plants are well suited for intermittent operations and variable 

loads. The nominal power can be delivered within a few seconds after starting (typically 90 

seconds) and the loading can be modulated between 50 and 100 per cent without much 

reduction in the efficiency. When supplied in soundproof casing, the unit may limit the noise 

level to only 65 dB at a metre. 

The supplier defines a well-defined maintenance schedule to guarantee long-term operation 

without unscheduled breakdowns. Use of the same core prime mover for numerous 

applications allows to have improved availability of the spare parts at a lower cost. A well 

maintained package cogeneration unit can have a life span of over 60,000 hours. The 

maintenance cost on small size engine-based units still remains relatively high compared 

with units with capacities exceeding 600 kW.


2.9 Innovation in Exhaust Gas Heat Recovery 

Sites requiring more thermal energy than that is available at the exhaust of reciprocating 

engine or gas turbine have the option of adopting post-combustion of oxygen-rich exhaust 

gases. For this, either the fuel required by the prime mover or an alternate cheaper fuel may 

be employed. New types of burners have been designed in the recent years that can be 

operated efficiently to provide the varying thermal energy demand of the site. 

The “GRC Induct” type of burners has been specially designed by EGCI Pillard for 

combustion of either liquid or gaseous fuels, by making use of the gas turbine exhaust gas 

(leaving at around 500°C and 13 per cent of O2 content) as the oxidizing air. Located at the 

inlet of the heat recovery boiler, it helps to increase the temperature of the gas turbine 

exhaust gas, and thus the overall efficiency of the cogeneration installation. In case the gas 

turbine is out of operation, these burners can assure steam generation by making use of cold 

inlet air from the surrounding. The heat output per burner can range from 4 to 50 MW. 

These burners function equally well on natural gas as well as liquid fuels (light or heavy fuel 

oil, residual fuel) or in simultaneous mixed mode. Steam or compressed air assures 

pulverization of the liquid fuel. The design based on the GRC LONOxFLAM technology, 

assures perfect flame stability, a low-pressure drop and an excellent combustion with low 

emissions of unburnts and NOx, thus well within the environmental pollution thresholds set by 

the regulation. When there is a combustion zone in the boiler, it is possible to reduce the 

oxygen level in the exhaust gas to around three to four per cent for further increasing the 

efficiency, while still maintaining the emission of pollutants lower than the norms. 3 

For its operation with cold ambient air, the control flaps close a part of the recovery section. 

While using heavy fuel oil, a suitable adaptation is necessary for limiting emissions. One of 

the main features of the system is the mechanism for quick dismantling which allows to 

change the burners during operation by opening the whole frame laterally within 15 minutes. 

2.10 Research and Development on Cogeneration Technologies 

There has been a steady rise in the efficiency of gas turbines and diesel engines. The inlet 

temperature of a large size gas turbine has risen to 1,350ºC and can be expected to reach 

1,500ºC in the near future. The thermal efficiency of gas engines has been increasing thanks 

to an increase in compression ratio, and the application of pre-chamber lean burn 

technologies. These improvements have been made possible mainly due to the progresses 

made in cooling, heat-resist materials, turbo machinery and combustion technologies. 

Various projects are ongoing to achieve rapid efficiency improvements by the year 2000. 4 

These include development of ceramic gas engine and gas turbine that require advanced 

technology related to ceramic science. To prove the concept, the Miller cycle gas engine 

system is being developed which has a unique intake and exhaust timing mechanism that 

allows to power generation efficiency exceeding 35 per cent. 

In a ceramic gas engine, ceramic is used as the materials of the combustion chamber to 

allow an advanced combustion. Similar to a thermos structure, air gap is provided and 

gaskets with low thermal conductivity are placed between the ceramic and metallic parts to 

3 

Energie Plus, “Lumières et ombres sur la cogénération, No.197, pp. 6, 15 December 1997. 

4 M. Motokawa, “R&D efforts for cogeneration technologies with high efficiency”, Proceedings of the 

Conference on Natural Gas Technologies: A Driving Force for Market Development, International Energy 

Agency, pp. 627-636, Berlin, 1-4 September 1996.


enhance the effect of insulation. The wall temperature of the combustion chamber is 

maintained above 1,000ºC, which helps to reduce the heat transfer from the combustion gas 

to the wall. Such a structure eliminates the need for a cooling system and renders the engine 

very compact. High efficiency is achieved by both diesel cycle combustion and the energy 

recovery unit where exhaust energy from the heat insulation is recovered and converted into 

electricity by a turbo compound system, an ultra high speed generator, and a highly efficient 

converter. As for the ceramic gas turbine, the target is to develop units having efficiencies of 

42 per cent or more. 

The thermal efficiency of an Otto cycle engine is a function of the difference between the 

maximum combustion temperature and the exhaust gas temperature. The maximum 

combustion temperature in an engine increases with a higher compression ratio while the 

exhaust gas temperature decreases with a lower expansion ratio. But the compression and 

expansion ratios of an Otto cycle engine are the same and the engine is adjusted for a lower 

compression ratio to avoid knocking. In a Miller cycle, the expansion ratio can be set larger 

than the compression ratio by adjusting the intake timing, and this results in an improved 

efficiency as well as improved durability due to the lower exhaust temperature. 

The gas injection diesel engine can now attain an electrical efficiency of 45 per cent, which is 

the highest among commercialized gas engines. The engine no longer requires pilot oil and 

glow plugs be used to ignite natural gas ignited into the cylinder at 25 MPa. 

R&D efforts are also on going to develop solid oxide fuel cells to exploit the excellent 

properties of ceramic materials and achieve efficiencies in the range of 50 per cent. Once 

these technologies are commercialized, cogeneration promotion can get a further boost as 

an energy saving and environmentally sound technology. 

2.11 Cogeneration and the Environment 

The high efficiency of cogeneration and efficient use of fuel guarantee a significant reduction 

of CO2 emission. However, cogeneration can have environmental implications in the form of 

CO, SO2 and NOx emissions to the atmosphere. The quantity of each of the pollutant 

generated depends largely on the type of fuel used and the characteristics of the 

cogeneration technology adopted. 

CO is a poisonous gas produced due to incomplete combustion and can be reduced to 

negligible levels by assuring satisfactory air-fuel ratio control. SO2 is an acidic gas produced 

when sulphur-containing fuels such as oil or coal are burned. Its emissions cause acid rain. 

Sulphur-containing exhaust gases are the main cause of corrosion of heat recovery devices 

when the SO2 in the gas is cooled below its condensation temperature. NOx is a mixture of 

nitrogen oxides produced due to the combustion of a fuel with air, and its formation is a 

function of the combustion condition, characterized by the air-fuel ratio, combustion 

temperature, and residence time. It also causes acid rain and can result in ozone and smog 

after undergoing several chemical reactions in the atmosphere. 

Technologies which have undergone rapid development are those based on spark and 

compression ignition engines and gas turbines, primarily using natural gas as the fuel. 

Natural gas is considered the cleanest among the fossil fuels as it does not practically 

contain any sulphur, nitrogen and is free of dust particles. However, the emission of NOx is 

greater, particularly for the prime movers operating at high temperatures.


Appropriate designing of the combustion chambers and control of the flame characteristic 

help to reduce NOx formation in engines and turbines. Engine design alone cannot eliminate 

NOx formation. Moreover, efforts to reduce NOx emission can lead to increase in CO 

emissions while adversely affecting the power output and efficiency. Therefore, end-pipe NOx 

abatement technologies such as those based on catalytic reduction systems must be 

applied to assure very low emission. 

2.11.1Gas engine 

Technical options adopted to minimize emissions from gas engines are optimal combustion 

process and flue gas cleaning. Lean-burn techniques are used for self-igniting engines using 

natural gas as fuel. With high load pressure and excess air (typically, 35 to 60 per cent), NOx 

emission can be reduced to 200 mg/m 3 , below the standards set by many industrialized 

countries. 

Flue gas can be cleaned with a 3-way catalyst; as its name implies, NOx, CO and 

hydrocarbon emissions are reduced. In order for it to function efficiently, a constant NOx-CO 

ratio needs to be maintained by proper control of air-fuel ratio and ignition. 

2.11.2Gas turbine 

Three commonly employed methods for eliminating NOx emissions from gas turbines are 

water or steam injection, use of dry low NOx burners, and selective catalytic reduction. 

Water or steam injection are well established techniques which boost the power output due 

to increased mass flow rate in the turbine. These also help to lower the flame temperature 

and the partial pressure of oxygen, thus inhibiting NOx formation. There is an upper limit to 

NOx reduction by this method without affecting gas turbine performance. Beyond a certain 

injection rate of water or steam, there is greater flame instability that leads to formation of CO 

and emission of unburned hydrocarbons. 

More modern gas turbines make use of dry low-NOx systems instead of water or steam 

injection in order to avoid the costs of treating and pressurizing water or producing high 

quality steam. The fuel is mixed with combustion air to a homogeneous mixture in a mixing 

chamber before being sprayed into the flame; this reduces the peak flame temperature and 

assures less NOx generation. Such systems are effective at high loads but perform poorly at 

partial loads. Where the cogeneration system is required to have a wide range of operating 

conditions, a hybrid design of low NOx burners is employed which incorporates a small 

diffusion pilot flame for stabilizing flame at low loads. 

At sites where stringent environmental standards are applied, selective catalytic converters 

can be adopted as an end-of-pipe technique. A reducing agent, normally ammonia, is used to 

convert NOx to nitrogen and water in the presence of a catalyst, the most common being 

vanadium oxide. 

2.11.3Steam turbine 

In steam turbine cogeneration systems, sulphur and nitrogen oxide emissions are important 

in oil-fired boilers whereas particulate and nitrogen oxides have to be considered in woodfired 

boilers. 

As far as the boilers are concerned, technologically advanced equipment has been 

developed to meet increasingly stringent environmental requirements. A significant 

development is the use of a secondary combustion chamber where complete combustion of 

the unburned gases occurs. Better monitoring of combustion parameters through adequate 

instrumentation has allowed the operator to better regulate the combustion.


Four types of emission control devices widely used in boiler systems are electrostatic 

precipitation, fabric filters, multi-tube cyclones and wet scrubbers. Chemical agents such as 

lime, magnesium oxide, etc., are used for flue gas desulphurization. Commonly used 

techniques employed for NOx emission abatement in steam turbine cycles include low NOx 

burners, selective catalytic reduction, flue gas recirculation, ammonia injection, etc.

Economic and financial aspects of cogeneration 27 

CHAPTER 3: ECONOMIC AND FINANCIAL ASPECTS OF COGENERATION 


Cogeneration is a proven technology that saves fuel resources, but it does not necessarily 

imply any assurance of economic benefits. Irrespective of all its technical merits, the 

adoption of cogeneration would principally depend on its economic viability, which is very 

much site-specific. The equipment used in cogeneration projects and their costs are fairly 

standard, but the same cannot be said about the financial environment that varies 

considerably from one site and/or country to another. The best way to assess the 

attractiveness of a cogeneration project is to conduct a detailed financial analysis and 

compare the returns with the market rates for investments in projects presenting similar 

risks. 

Well-conceived cogeneration facilities should incorporate technical and economic features 

that can be optimized to meet both heat and power demands of a specific site. A 

comprehensive knowledge of the various energy requirements as well as characteristics of 

the cogeneration plant is essential to derive an optimal solution. As a first step, the 

compatibility of the existing thermal system with the proposed cogeneration facility should be 

determined. Important user characteristics which need to be considered include electrical 

and thermal energy demand profiles, prevalent costs of conventional utilities (fossil fuels, 

electricity) and physical constraints of the site. A factor that should not be overlooked at this 

stage is the need for reliable energy supply as some industrial processes and commercial 

sites are extremely sensitive to any disruption of energy supply that may lead to production 

losses. 

To fully exploit the cogeneration installation throughout the year, potential candidates for 

cogeneration should have the following characteristics: 

a. adequate thermal energy needs, matching with the electrical demand; 

b. reasonably high electrical load factor and/or annual operating hours; 

c. fairly constant and matching electrical and thermal energy demand profiles. 

These are essential for full exploitation of the cogeneration installation; moreover, part-load 

operation of the plant can be avoided, which would otherwise have affected the economic 

viability of the project. 

3.2 Some Points to Consider for Cogeneration Project Development 

Cogeneration project is the same as any other commercial project requiring high investment, 

relatively longer period, and presenting certain financial risks. Therefore the steps which 

should be followed in developing a cogeneration facility would be quite the same as those 

employed for any investment project (see Figure 3.1). Projects will obviously vary from one to 

another on the basis of factors such as who is the project developer, what is the size of the 

project, who is financing the project, etc. 

Prior to undertaking any economic analysis to assist the commercial benefit of a 

cogeneration project, technical parameters which need to be considered first have been 

discussed in Chapter 1 and are summarized below:


- heat-to-power ratio; 

- quality of thermal energy needed; 

- electrical and thermal energy demand patterns; 

- fuel availability; 

- Required system reliability; 

- Local environmental regulations; 

- dependency on the local power grid; 

- option for exporting excess electricity to the grid or a third party, etc. 

Some of these concerns are further elaborated below. 

1-Technical Analysis 2-Economic Study 

4-Financial Arrangement 

6-Execution 

3-Selection of Best Solution 

7-Starting off 

5-DECISION 

8-Technical &Financial 

Result 

Figure 3.1 Typical steps for cogeneration project development 

A cogeneration system may be sized to meet either the electricity or the heat demand of the 

site. When the local power utility allows selling excess electricity generated at the site, one 

should make sure that the buy-back rate is attractive enough before over-sizing the 

cogeneration plant. 

As the electrical and thermal loads of the site tend to vary with time, the cogeneration system 

may require that any shortfall in the electricity supply be met by the purchase of electricity 

from the grid. Likewise, any shortfall of thermal energy should be met by either postcombustion 

of exhaust gases in the case of gas turbines or reciprocating engines, or from an 

auxiliary source such as a stand-by boiler. These solutions will certainly have consequences 

on the annual average efficiency and the economics of the project. The ideal operation would 

thus consist of the use of the maximum electricity on site, while assuring continuous 

operation of the processes at nominal conditions and avoiding the generation of excess 

thermal energy. 

If the thermal load is negligible or if it is required to produce only low-pressure steam or to 

heat a fluid at low temperature, gas engine may be preferred because of its higher efficiency.


When opting for gas turbine, it is advisable to first verify gas supply pressure. If the pressure 

of gas in the pipeline is low, it will necessitate additional investment on the gas compression 

station. Moreover, some amount of electricity generated would be diverted for running the 

compressor, and the operation and maintenance costs will be higher. 

The availability of fuel, its price and guarantee of its long-term supply are the major factors 

determining the choice of the prime movers. As prime movers can operate with different 

types of fuels, the option for fuel switching should be taken into consideration. 

Designing of the cogeneration facility at the initial stage should incorporate the possible 

evolution of future energy demand. This would help in the appropriate choice of equipment 

and in planning the schedule for expanding capacity according to the changes in need. 

Modern cogeneration plants are highly reliable and have a high load factor; one cannot 

however ignore the occurrence of stoppages for scheduled maintenance or unscheduled 

breakdown. There may be a need for back-up power to assure continuous operation of 

activities at the site. One solution would be to provide stand-by generation capacity at the 

site, which will increase the investment further. Alternatively, a stand-by contract may be 

signed with the power utility so that electricity can be tapped from the grid up to the maximum 

contracted demand whenever the cogeneration plant stops operating. 

3.3 Key Parameters for Cogeneration Economic Analysis 

Cogeneration may be considered economical only if the different forms of energy produced 

have a higher value than the investment and operating costs incurred on the cogeneration 

facility. In some cases, the revenue generated from the sale of excess electricity and heat or 

the cost of availing stand-by connection must be included. More difficult to quantify are the 

indirect benefits that may accrue from the project, such as avoidance of economic losses 

associated with the disruption in grid power, and improvement in productivity and product 

quality. 

Following are the major factors that need to be taken into consideration for economic 

evaluation of a cogeneration project: 

1. initial investment; 

2. operating and maintenance costs; 

3. fuel price; 

4. price of energy purchased and sold. 

Initial investment is the key variable that includes many items in addition to the cost of the 

cogeneration equipment. To start with, one should consider the cost of pre-engineering and 

planning. Barring a few exceptional cases, the cogenerator would normally hire a consulting 

firm to carry out the technical feasibility of the project before identifying suitable alternatives 

that may be retained for economic analysis. If the cogeneration equipment needs to be 

imported, one should add the prevailing taxes and duties to the equipment cost. If one plans 

to purchase cogeneration components from different suppliers and assemble them on site, 

one should take into account the cost of preparing the site, civil, mechanical and electrical 

works, acquiring of all auxiliary items such as electrical connections, piping of hot and cold 

utilities, condensers, cooling towers, instrumentation and control, etc. Table 3.1 provides an 

example of the breakdown of typical costs for a 20 MWe gas turbine cogeneration plant.


Table 3.1 Cost breakdown (US$) of a 20 MWe gas turbine cogeneration plant 1 

Gas turbine plant equipment 

- Gas turbine gen-set package (FOB) 

- Auxiliary systems 

- Fuel gas compressor/ skid 

- Back-up distillate storage 

Steam equipment 

- Heat recovery boiler with auxiliary firing 

- W ater treatment system 

- Condenser, feedwater pumps 

Electrical equipment 

- Substation transformers 

- Switch gear and controls 

- Utility interconnections 

Services and Installation 

- Engineering design 

- Civil works 

- Control and maintenance building 

- Electrical field work 

- Mechanical field work 

- Freight and handling 

Total plant cost 

- Equipment, design and installation 

- Contingency (approximately 10% ) 

If cogeneration is being adopted as a retrofit at an existing site, the cost items will depend 

greatly on the existing facilities, some of which may be retained while others are discarded, 

replaced or upgraded. 

The cost of land may be a crucial factor at some sites where cogeneration facility is 

commissioned, particularly in the case of urban buildings or when additional space is 

required for storage and handling of fuel. 

Integration of the cogeneration plant into the existing set-up may lead to some economic 

losses to the cogenerator (e.g. production downtime). Costs associated with such losses 

should be included in the total project cost. 

The operating and maintenance (O&M) cost should include all direct and indirect costs of 

operating the new cogeneration facility, such as servicing, equipment overhauls, replacement 

of parts, etc. The cost of employing additional personnel as well as their training needed for 

operating the new facility must also be taken into account. Present technology allows 

complete automation of small pre-packaged and pre-engineered units, helping to reduce the 

O&M costs considerably. 

1 Gas Turbine World, The 1990 Handbook, Pequot Publishing. 

8,100,000 

370,000 

420,000 

110,000 

1,840,000 

320,000 

420,000 

320,000 

110,000 

420,000 

1,100,000 

630,000 

320,000 

840,000 

1,470,000 

320,000 

17,110,000 

1,700,000 

9,000,000 

2,580,000 

850,000 

4,680,000 

18,810,000


Annual costs incurred due to the cogeneration plant, such as the insurance fees and property 

taxes should be included in the analysis. These are often calculated as a fixed percentage of 

the initial investment. 

Fuel costs may form the largest component of the operating expenditures. If cogeneration is 

added to an existing plant, only the fuel cost in excess of that used earlier for heat and power 

generation may be considered. Since the cogeneration plant is expected to operate for a long 

time period, escalation of the fuel price over time should be included in a realistic manner. 

The price of energy purchased and sold is a decisive parameter. This includes the net value 

of electricity or thermal energy that is displaced as well as any excess electricity or thermal 

energy sold to the grid or a third party. A good understanding of the electric utility’s tariff 

structure is important, which may include energy charge and capacity charge, time-of-use 

tariff, stand-by charges, electricity buy-back rates, etc. As for the fuel, there should be 

provision to account for electricity price escalation with time. This is particularly true where 

power utilities depend heavily on fuel in their power generation-mix. 

3.4 Source of Financing of Cogeneration Projects 

Cogeneration systems are capital intensive projects and the sources of capital financing can 

be an important consideration in the investment analysis in which different sources may be 

used. It is important, therefore, to know the rate of return for each alternative. The sources of 

capital financing could be one of the following: 

1. self financing: capital generated from cogenerator’s own activities; 

2. borrowing: requiring certain equity and guarantee; 

3. leasing: ownership maintained by the leasing company; 

4. third-party financing: undertaken by an energy service company; and 

5. facility management: reduction of energy bill for user with zero capital risk. 

Self-financing can be in various forms, such as equity capital, depreciation fund and retained 

profit. Equity capital is supplied and used by its owner in the expectation that a profit, of a 

minimum acceptable level, will be earned. In equity financing, however, the owner has no 

assurance that a profit will actually be made or that even the equity capital invested will be 

recovered. 

When the funds that are set aside out of the revenue as the cost of depreciation are a part of 

the net cash flow, these can be retained and used for capital financing of expansion projects 

like cogeneration. The equipment may continue to be used after its original value has been 

recovered through normal depreciation procedures. Hence the accumulated funds may be 

available for use until the original equipment is actually replaced. Also, if the depreciation 

procedures used in accounting are such that they provide large recoveries of the first costs 

during the first few years of equipment life, there will usually be funds available before the 

equipment must be replaced. Thus, the depreciation funds may provide a revolving 

investment fund that will become a source of capital for new ventures like cogeneration. 

Obviously, the management of these funds must ensure the availability of required capital 

when the time does come for replacement of essential equipment. 

Existing enterprises have an important source of capital financing for expansion of activities, 

like setting up cogeneration power plants, through retained profits. Normally a part of the profit 

earned by an enterprise is retained after payment of adequate dividend to the shareholders, 

and this capital is then re-invested for a further increase in profits.


In reality, the enterprise concerned may prefer to save the capital for financing its main 

activity that may present a smaller risk and can be a source of greater financial profitability. 

As an alternative, borrowed financing may seem more attractive because the suppliers of 

debt capital do not get a share of the profits accrued from the use of their capital. Here, a 

fixed rate of profit, or value of money, must be paid to the supplier of the capital and the 

repayment of the borrowed funds is negotiated on the basis of the amount borrowed, 

duration, and the interest rates. Normally, the terms of the borrowed financing (loan) may 

place some restrictions on the uses to which the funds may be put. Moreover, any amount 

borrowed will require a certain percentage of equity investment and guarantees may be 

required in the forms of mortgages or securities. 

Leasing is only one of the several ways of obtaining working capital and a decision to lease, 

rather than purchase, should be based upon the cost of capital financing by other possible 

methods, some of which have been described above. The leasing company guarantees full 

financing of the cogeneration plant, which remains its owner till the user buys it back 

according to the conditions of the contract. Most leases cannot be cancelled, or cancelled by 

incurring costly penalties, whereas borrowed financing works on some fixed obligations and 

may provide better terms. 

Some indirect costs, which are difficult to determine in most cases, are associated with the 

ownership that may not apply to the equipment under lease. In many cases, leasing turns out 

to be cheaper than owning, but the actual comparative costs and all other factors must be 

considered before a decision is taken. 

An Energy Service Company (ESCO) often does third party financing which, after preliminary 

analysis of the requirement of the client and feasibility study of the cogeneration project, 

implements the project in agreement with the client. When the ESCO covers the whole cost 

of financing the project, it is repaid by sharing the actual savings realized according to a 

predetermined contract. Accurate measurement of the actual monetary saving is essential to 

assure fairness to the ESCO as well as the client. Here, the client does not have to 

investment in the cogeneration project and starts getting benefits from the day the 

cogeneration plant is in operation. 

The concept of facility management is not very different from third party financing, except that 

the facility manager does more than an ESCO in meeting practically all the requirements of 

the site which are not directly involved with the main line of activity of the client. For example, 

a facility management firm can assure the supply of all utilities including electricity, steam, 

compressed air, water, etc., to the client, while also handling the wastes or effluents 

generated from the production process. This firm signs a contract with the client to meet the 

present and future requirements of the site and invests in the development of infrastructure 

and undertakes to operate and maintain it. By adopting innovative schemes such as 

cogeneration, sizing the components appropriately, operating the facility reliably and 

maintaining it efficiently, the facility management firm manages to reduce the overall cost 

considerably. Moreover, a part of the benefits accrued is shared with the client in the form of 

reduced bill. 

Facility management is normally feasible for bigger clients or where one firm can cater to the 

needs of several clients in the same locality. Then it becomes economical to make 

investment on a bigger facility and employing a limited number of personnel who can deal 

with several clients at the same time. 

3.5 Tools for Financial Analysis of Cogeneration Projects 

Regardless of whether the cogeneration project is a totally new facility or a retrofit of an 

existing operation, the project will materialize only if it is financially attractive. There are a


number of financial indicators to measure the attractiveness of a project. Some indicators are 

used to compare several projects to decide which one is the best alternative. 

The sizing of the cogeneration system is sometimes carried out by financial analysis in grid 

dependent cases where there is an option for importing electricity instead of self-generation 

of all the electricity. In such circumstances, the optimum size of cogeneration would 

correspond to a system that has the minimum annual total cost (or maximum annual net 

profit). 

Commonly employed financial indicators for cogeneration feasibility study are the payback 

period (PBP), net present value (NPV), and internal rate of return (IRR). 

The easiest and basic measure of the financial attractiveness of a project is the payback 

period (PBP). It reflects the length of time required for a project to return its investment 

through the net income derived or net savings realized. It is the most widely employed 

quantitative method for evaluating the attractiveness of a cogeneration system. Assuming 

uniform energy cost saving every year, PBP is expressed as: 

Payback Period = 

The simple payback period gives an idea of the time frame necessary for the net energy cost 

saving (or cash benefits) to pay the total installation cost of a cogeneration system. It 

disregards the salvage value, and the time value of money. 

The net present value (NPV) of a stream of annual cash flows is the sum of discounted 

values of all cash inflows and outflows over a certain time period. For a cogeneration project, 

initial investment costs are assumed as cash outflows and net annual energy cost savings 

(or net annual benefits) are cash inflows. Thus, NPV is expressed as 

A1 A A 2 n S 

NPV = - Io + + + .................... + + 

(1+i) (1+i) 2 

(1+i) n (1+i)n 

n Aj = - Io + + 

j=1 (1+i) j 

Where, Aj Io i 

= Net saving (or profit) in time period j (j=1,2,.....,n) 

= Initial investment cost 

= Discount rate 

NPV = Net present value 

S = Salvage value 

S 

(1+i) n 

Total installation cost 

Annual energy cost saving (or annual net benefit) 

When cogeneration system alternatives of different capacities are being compared, the net 

present value is an important financial parameter. The project that has the highest net 

present value would be chosen as the best alternative system. 

The internal rate of return (IRR) is defined as the discount rate that equates the present value 

of the future cash inflows of an investment to the cost of the investment itself. Actually, the 

IRR is the rate of return that the project earns. The equation for calculating the internal rate of 

return is given as:


0 

A1 A2 An = - Io+ + +.....+ + 

S 

(1+IRR) (1+IRR) 2 (1+IRR) n (1+IRR) n 

Manual computation of IRR is generally an iterative process. One starts with an assumption 

of the rate first and calculates the net present value of the cash flow stream. If the net present 

value is negative, the process is repeated with a lower assumed IRR. The iterative process 

would be repeated until the net present value becomes zero (or nearly zero). However, many 

personal computer spreadsheet programs and some hand-held financial calculators have the 

ability to compute IRR from a stream of cash flows. 

To judge the suitability of a cogeneration project, comparison is made between IRR and 

discount rate (or required minimum rate). If IRR happens to be less than the discount rate, 

the project would be rejected. 

3.6 Assessment of Financial Feasibility of Cogeneration Projects 

Once a client is satisfied with the rough payback period of a specific cogeneration project, a 

common and simple procedure of financial feasibility of that particular alternative may be 

pursued, as shown in Figure 3.2. 

Cost Data of 

the System 

Estimate 

NPV 

Is 

NPV > 0 

Yes 

Estimate 

IRR 

Is 

IRR>Expected 

Rate 

Yes 

Accept the 

System 

Financial 

Parameters 

Figure 3.2 Flowchart of cogeneration feasibility analysis 

In the estimation of NPV for a cogeneration project, the total investment costs are taken as 

cash outflows, and cash inflows are the difference between the annual total cost of 

cogeneration system and that of the conventional energy supplies. 

Sometimes, the total discounted costs of different cogeneration alternatives are estimated 

instead of the NPV of a single alternative, e.g., the case of a grid independent project. All the 

cash outflows are considered and discounted to the present value. The option that has the 

least discounted costs would be selected as the best system. 

No 

No 

Reject the 

System


Investment decisions are based on the above mentioned financial indicators which are 

calculated from cash flow streams. The cash flows are estimated based on a number of 

factors such as future costs, interest rates, fuel costs, expected investment levels, tax rates 

and so on. Therefore changes in these parameters affect drastically the financial indicators 

and investment decisions. It is necessary to analyze how the value of a financial indicator 

(e.g. internal rate of return) changes when one or more of the input parameters (e.g. discount 

rates, fuel prices, investment costs) deviate by a certain amount (or percentage) from the 

expected value. This is known as the sensitivity analysis. 

If the system to be installed has no access to the utility grid, the financial feasibility study will 

lead to the best cogeneration alternative since the sizing of different alternatives would have 

been carried out in the technical feasibility study. Financial indicators are estimated for each 

cogeneration system retained after the technical feasibility study. The best cogeneration 

alternative that has the highest NPV (or the least total discounted cost) would be selected. 

For systems having access to the utility grid, the optimum size of alternative cogeneration 

systems is determined by the financial feasibility study. The optimum size of each alternative 

would be that which has the highest net present value (or least discounted cost). After sizing 

each alternative system, the best alternative that has highest net present value (or least 

discounted cost) would be selected. Normally determination of the optimum size of a 

particular cogeneration system is done by computer software because it is a repetitive and 

time-consuming process, dealing with a large number of variables and parameters. The 

objective function of the optimization process may be the maximization of the net present 

value or the minimization of the total discounted costs. 

Finally, the best cogeneration system would be identified after the sensitivity analysis is 

carried out to make sure whether the selected cogeneration system is still financially 

attractive with possible variations in the values of some critical parameters. 

To summarize, assessment of the feasibility of a cogeneration project involves four distinct 

steps, as follows: 

1. Analysis of the energy demand pattern (electricity, thermal energy); 

2. Identification of the different technical options (considering technical constraints, 

equipment availability, space constraints, etc.); 

3. Optimization of each technical option (overall efficiency, part load performance); 

4. Financial analysis for selecting the best option (payback period, internal rate of return).

Policy framework for promoting cogeneration 37 

CHAPTER 4: POLICY FRAMEWORK FOR PROMOTING COGENERATION 


Small and medium size cogeneration projects extend indisputable benefits to both the 

cogenerator as well as the utilities/governments. Cogeneration projects are environmentally 

benign or have greater scope to limit the environmental impact as compared to large-scale 

fossil-fired or hydropower plants. Moreover, small to medium-scale projects are less risky to 

implement as they may have a lower life cycle cost as a result of three factors: 

shorter construction time in comparison with large scale power plants; 

lower project development expenses due to less complex negotiation process; and 

perception of lower financial risk by the potential lender. 

In addition, site selection for setting power generating facility by the utilities is a rather 

complicated procedure. In comparison, cogeneration is suitable for any site closer to endusers 

and can lead to savings on costs associated with transmission of electricity. There is 

thus a great scope for providing electricity in remote areas at a lower cost than from the 

centralized utility grid. 

In spite of the above facts, cogeneration development so far has been rather slow because 

there is a general feeling among the Asian energy policy makers that only large scale thermal 

power generation projects can be economically and financially viable to tide over the 

impending electricity capacity shortage. In the process, they have underestimated the risks 

involved in the implementation of large-scale power generation projects with private sector 

participation and overlooked the potential contributions from a great number of small-scale 

cogeneration and renewable energy projects. 

Secondly, most electric utilities look down upon cogeneration projects as unreliable. It is true 

that many industries, such as steel, cement, petrochemical and agro-processing, having 

cogeneration potential consider the output power as a by-product, thermal energy being their 

main energy source for matching the process energy demand. As the demand for thermal 

energy may fluctuate with time and production, these industries will find it difficult to optimize 

firm power purchase agreements with the utility. Instead of looking for innovative risk 

allocation and pricing schemes, utilities often limit the amount of power that can be sold to 

them in the power purchase agreement to minimize the risk of depending on the 

cogenerators. Any additional electricity supplied by the cogenerator is purchased using nonfirm 

pricing which discourages the cogenerators in investing on such projects. 

In countries where energy prices have not been rationalized, there is a tendency for the stateowned 

utilities to charge the industrial and commercial sectors more for the electricity they 

consume in order to cross-subsidize other sectors. A number of industrial and commercial 

sector clients have economically viable cogeneration potential. But as they pay a high 

electricity price to the utilities, any attempt by them to generate their own power is perceived 

as a loss of revenue and a threat by the utilities. 

The following section will cover some of the barriers to cogeneration development in general. 

This will be followed by discussion on the policy, institutional and regulatory measures 

necessary for overcoming the obstacles and promoting cogeneration.


4.2 Barriers to Cogeneration Development 

Obstacles to cogeneration development can be classified into the following: technical 

barriers, financial drawbacks, poor institutional framework, short-sighted electric utility 

policies, and low environmental concern. 

In most instances, these barriers are country specific because there are a lot of differences 

in the energy demand patterns, electricity supply structures, fuel pricing, fuel availability, 

climatic conditions, environmental considerations among the countries in the different 

continents. For instance in Europe, the share of cogeneration in the overall power generation 

in a country like France is low because the national policy in the past had been to depend 

mainly on power generation based on nuclear energy. In Netherlands and Germany where 

more natural gas and coal are available, the government policy has favoured cogeneration 

development. In a country like Spain having no need for heating of buildings throughout the 

year, there is a trend to recover the waste heat for comfort or process cooling applications 

using vapour absorption chillers in the hotter months. In colder climates, urban cogeneration 

schemes have been closely associated with district heating schemes to meet the space 

heating and hot water requirements. The problems associated with industrial or commercial 

cogeneration are quite different from those encountered in district heating applications which 

contribute to about 40 per cent of the European Union’s electricity generation through 

cogeneration. 

4.2.1 Technical hurdles 

First technical barrier is the lower level of awareness about the soundness of cogeneration 

technologies due to the lack of technical information at the level of local utilities, industries, 

potential cogenerators and governments. In fact, awareness building about cogeneration is 

the very first step to promote cogeneration systems. 

Lack of capability to locally manufacture some energy supply equipment can lead to higher 

investments linked with higher cost of imported equipment. Inferior quality of equipment 

produced by local manufacturers with poor technologies also hampers the propagation of 

cogeneration systems. 

In many developing countries, the technical expertise to design, construct and operate energy 

efficient cogeneration systems is quite limited. For grid-dependent systems with the option of 

electricity export to the grid, advanced electrical control systems are necessary for both 

cogeneration plants and local electric utilities. The local electric utilities must have competent 

personnel who are capable of operating a more complicated system consisting of utilityowned 

power plants and cogenerators. The cogeneration systems need skilled technicians 

for regular maintenance and trouble-free operation. 

Lack of infrastructure is also one of the obstacles in promoting cogeneration systems. For 

instance, there are natural gas networks in many developed countries. The lack of 

infrastructure such as gas handling, storage and distribution auxiliaries in some developing 

countries leads to technically more complicated systems for gas powered cogeneration. 

4.2.2 Economic and financial constraints 

Cogeneration systems are somewhat capital intensive. Investments required are sometimes 

out of reach of energy consuming facilities such as industries, commercial buildings, 

hospitals, etc., in many developing countries.


Any lack of guarantee for long term availability of fuels can lead to higher risks in investing in 

cogeneration systems. For example, unlike the developed economies, the availability of fuels 

in most developing countries depends on the government’s policy changes due to the 

monopoly of the energy sector. There will be uncertainties about the actual energy cost 

savings unless long-term fuel supply is ensured. 

A cogeneration scheme may be found to be a good financial investment and provide 

reasonable payback period. The hindering factors however are those which limit the income 

derived from the products (heat and electricity) or increase the cost of inputs (equipment and 

fuel). Among these, electricity pricing appears to be the deciding factor that is beyond the 

control of the cogenerator. Some sort of involvement of energy companies and development 

of third-party financing schemes can help to reduce the financial uncertainties. 

In countries where prices of other fuels and electricity are subsidized, cogeneration systems 

cannot be financially attractive for private or public enterprises if the energy consuming facility 

has easy access to the grid or can buy other subsidized fuels. The low rate of return on 

investment would not justify the high capital requirement of a cogeneration system. 

Investors may often look for some form of incentives such as reduced fuel prices, investment 

subsidy, tax benefits and attractive tariffs. In countries having no or inadequate incentives, 

cogeneration development has been found to be low or marginal. In industrialized countries, 

cogeneration has been promoted through financial incentives such as soft loans, subsidies, 

tax credit, etc. Experiences show that these financial incentives are effective tools to 

enhance the development of cogeneration in industries and utilities. 

4.2.3 Poor institutional structure and inadequate regulatory framework 

Like other energy efficient technologies, cogeneration can be effectively and rapidly promoted 

by the government and appropriate institutions working together in harmony. Institutional 

issues are mainly related to the seriousness of the national authorities in promoting 

cogeneration in order to achieve conservation of fossil fuels and protection of the 

environment. 

In some instances, existence of a promotional organization for cogeneration has helped to 

establish policy measures and develop cogeneration market. Some developing countries lack 

institutions or have inadequate institutions to deal with energy and environment matters. In 

such instances, there are no energy conservation campaigns and distribution of information 

on energy efficient technology such as cogeneration. 

Inadequate regulatory framework can set negative example in the form of poorly planned and 

designed projects. For bigger cogeneration projects involving district heating/cooling network 

in city centres or industrial estates, the need for investment may be high. When foreign 

investment is involved, the question of allocating sovereign risks and guaranteeing utility 

payment obligations must be resolved. Lack of experience in planning and lack of transparent 

power purchase agreement can lead to prolonged process of negotiation between the project 

developers and the concerned authorities, resulting in unnecessary delays in project 

implementation and financial losses to the developers. 

Some of the regulatory issues concern fulfilling of technical requirements, licensing 

arrangements, ability to “wheel” (i.e. allowing cogenerators to sell electricity and heat directly 

to energy consumers, not through utilities), etc. While the principle of authorization sounds 

reasonable, procedures can be bureaucratic, complex and time consuming, thus perceived 

as a disincentive for potential cogenerators with little experience in the power sector. 

It is also important that the government and institutions themselves must be aware of the 

benefits of cogeneration in achieving higher overall energy efficiency and lower emission of


pollutants. However, the lack of expertise in government body and relevant institutions leads 

to lower level of awareness on cogeneration and weak policy on the development of 


Some developing countries have realized the importance of energy conservation in the 

economic growth. They have formed a number of institutions to handle the energy matters 

including promotion of cogeneration. However, the duty and responsibility of each institution is 

not clearly defined or there is an overlapping of responsibility among the institutions. Such an 

inefficient institutional structure leads to ineffective cooperation between the government and 

industries or other energy intensive facilities. Contradictory policies and complicated 

procedures often frustrate the potential cogenerators. 

4.2.4 Role of electric utilities 

Equally important is the role and attitude of electric utilities towards cogeneration. In spite of 

the fact that these utilities are being restructured in many parts of the world including Asia, 

many among them remain monopolistic in nature. Significant investments have been made in 

the past to develop their generation capacities. As some of these investments have been 

written off, relatively inexpensive electricity is produced which is not conducive to the 

development of alternative options of power generation even when they are found economic. 

If electricity prices are low, there is little incentive for the users to consider supplying their 

own power or sell it to the grid with unattractive payback periods. Unhelpful utility attitudes 

and actions are manifested in the following recurring themes: 

• tariffs fixed for purchasing surplus electricity from cogenerator are too low; 

• tariffs for stand-by or back-up supplies to the cogenerator are excessive; 

• sale of electricity to third parties is rarely permitted or is too expensive; 

• technical authorization to new schemes are not always fully transparent; procedure 

followed can be time consuming and costly. 

Where utilities do not consider the cost of additional power generation (system avoided 

costs) while fixing the power purchase agreement with the cogenerators, they cannot raise 

enough funds to expand their generating capacities, while they hinder the growth of private 

investment in power generation or cogeneration. In the process, there is a shortfall between 

the supply and the demand and there is a slowdown of the national economy. 

Sometimes, although there are several energy and environment related institutions in some 

countries, they are not capable of formulating suitable energy policies. For instance, they 

cannot draft well-structured electricity tariffs. These institutions often imitate the energy 

policies directly from other countries that are not always suitable for their respective 

countries. Therefore, the lack of ability to formulate and implement sound energy policies 

leads to improper dissemination of energy efficient and environmentally sound technologies 

including cogeneration. 

4.2.5 Environmental issues 

Some developing countries feel that environment is a matter of concern of industrialized 

countries. They are reluctant to impose environmental restrictions on industries, being afraid 

that local industries would lose the competitiveness in world market. Such a situation favours 

the use of cheaper and pollution intensive fuels in inefficient manner. Without energy 

efficiency standards and environmental regulations, cogeneration systems would not get an 

advantage over other systems. Therefore, higher environmental concern is necessary to 

promote cogeneration.


Where emission regulations are used to limit air pollution related to various economic 

activities, they can be discriminatory against cogeneration installations, as the emission 

thresholds set do not always recognize the efficiency of energy conversion of the 

cogeneration process. Though a cogeneration plant may increase the local emissions, it 

normally displaces even more emissions at the fossil fuel power plant. Any relaxation in the 

limit of air pollution can help to reduce the investment on cogeneration facilities. 

Natural gas is widely recognized as a clean fossil fuel for cogeneration applications. Where it 

is available and the gas network exists, natural gas can be a promising fuel if it is not too 

expensive. The Netherlands has been most successful in gas powered cogeneration 

whereas the price of gas is cited as a major obstacle for its propagation in Germany. 

Other barriers include the lack of skilled manpower and management. In most cases, both 

the electric utilities as well as the industrial plants lack skilled manpower and managers to 

handle the specific task of heat and power production. 

4.3 Policy and Regulatory Framework for Promoting Cogeneration 

4.3.1 Establishing right policy framework 

The development of cogeneration is basically a policy issue. The first prerequisite therefore is 

an ideal policy framework, as has been demonstrated by some countries which have made 

considerable progress in this domain, such as Japan, Republic of Korea and Thailand in 

Asia, and the Netherlands and Denmark in western Europe. The motives for action may vary 

depending on the priorities set, and the methodology pursued may also be different. 

Whatever may be the rationale behind such a move and whatever the tools used, the policies 

must be supported by a clear political will for achieving any tangible result. 

Planning and decision making regarding capacity expansion should involve the national 

authorities, electricity producers and distributors as well as potential developers of alternative 

energy sources including cogeneration. Fair and transparent criteria such as costeffectiveness 

and environmental benefits will help to create a more competitive and convivial 

atmosphere for greater investment. 

Certain principles need to be upheld by the policy makers to assure greater private sector 

participation in energy generation and cogeneration, so that the capital requirements for 

power system expansion can be met. These include: 

• preparation of a well structured regulatory framework, including separation of 

responsibilities and authorities for efficient and timely project implementation; 

• launching of balanced programme in terms of the type of project (project size, 

technology, choice of fuel) and the type of market served (sale to utility, third parties); 

• systematic implementation of programmes and projects following a well defined work 

plan, including completion of important planning activities and establishment of bidding 

and contract awarding procedures; 

• setting of fair and transparent procedures for soliciting, evaluating and awarding bids, 

which will help to maximize competition thanks to a greater participation of lenders and 

investors; 

• conducting negotiations in an open and transparent manner, without resorting to negative 

tactics;


• revising regulatory frameworks, legal and institutional arrangements, bidding as well as 

negotiation procedure periodically on the basis of experience gained, and in consultation 

with all the other partners concerned. 

4.3.2 Adequate regulatory measures 

There should be certain regulations that clearly define the cogeneration system by specifying 

the fuel to be used, energy efficiency, minimum or maximum ratio of heat to power, etc. 

Regulations should allow the purchase and sale of power between cogenerators and electric 

utilities. The obligations and rights of cogenerators and electricity utilities must be clearly 

defined as well as the interaction between them. A sound investment climate should be 

created in order to attract foreign investment into the field of cogeneration. 

Development of a positive regulatory framework regarding the role of the electricity industry 

will send the right signal to the potential cogenerator. This should include purchase and sale 

of electricity, back-up facilities and wheeling of electricity to third parties. There should be 

arrangement for the grid to buy back electricity from a cogenerator. The price of electricity 

purchased should be based on avoided cost of electricity generation by the utility. 

Experiences in many countries show that capacity allowances fixed are inadequate and the 

principle of avoided costs is not fully applied while setting up the pricing structure for 

purchasing cogenerated electricity. 

Small cogenerators are prone to equipment failure or unscheduled breakdown. Penalties for 

importing electricity during these periods can have severe impact on the economics of the 

cogeneration project, as has been found in a number of countries. The utility should be 

lenient in such cases and provide emergency power at a reasonable rate. 

The arrangements for “wheeling” or selling electricity to third parties are not widely adopted or 

accepted by energy policy makers in many countries. Wheeling should not only be allowed 

but also encouraged at sites where there is a shortage of local supply of electricity or when 

power is delivered at a lower level than that of the electricity network. 

4.3.3 Examples of regulations in selected Asian countries 

Some aspects of regulations for cogeneration facilities in Thailand are presented here. The 

benefits that can be enjoyed by cogenerators in some other selected countries are also 

mentioned in order to give an idea of how cogeneration can be effectively promoted by 

means of good regulations. 

In Thailand, regulations for the purchase of power from small power producers were 

approved in 1992. The sections that are relevant to the cogeneration systems are mentioned 

below. 1 

The operating standard of a cogeneration facility is that the process must involve continuous 

use of energy by employing a topping cycle or a bottoming cycle thermal process. The 

thermal energy to be used in thermal processes other than electricity generation, must be no 

less than an average of 10 per cent of the total energy production during each year. 

The efficiency standard of cogenerators is set such that if oil and/or natural gas is used either 

as a primary or supplementary fuel, the sum of the electricity produced and one half of the 

1 

Electricity Generating Authority of Thailand, Regulations for the Purchase of Power from Small 

Power Producers, Thailand, 1992.


thermal energy used in the thermal process on an annual average must be at least 45 per 

cent of the total energy from oil and/or natural gas (based on Lower Heating Value). 

In case of the electricity being exported from a cogeneration facility to the power utilities, the 

cogenerator will be qualified as a small power producer if the following criteria are met: 

I. Electricity export capacity to utilities should not exceed 60 MW (this can be raised to 

90 MW on a case by case basis) 

II. The cogenerator must generate and supply electricity to the public utility during the 

utility’s system peak months of March, April, May, June, September and October, and 

the total hours of electricity production supplied to the utility must be no less than 

7,008 hours per year. 

The cogenerator is responsible for the cost of system interconnection which includes the 

costs of the transmission and distribution systems, metering, protective devices and other 

expenses arising from undertaking to purchase electricity from the cogenerator. 

The cogenerator is also responsible for the cost of equipment inspection which refers to the 

utility system and the expenses to be incurred from corrective actions that may arise in 

addition to the normal practices of the utility. 

If the electric export contract period is more than 5 years, the qualifying cogenerator can 

obtain the capacity payment and energy payment based on long term avoided costs of 

electric utility. Otherwise, the cogenerator can obtain only energy payment calculated on the 

basis of short run avoided energy cost of utility. 

Cogenerators are allowed to use electricity from the public utility as back-up power. In this 

case, they must pay demand and energy charges to the utilities. 

Cogenerators must be billed energy charges (Baht/kWh) at the same price as other 

electricity consumers pay, but they pay only half of the demand charges (Baht/kW/month) 

which are applicable to other small power producers. 

In Malaysia, the energy policy is geared towards cutting down on the use of oil and 

promoting the use of non-oil indigenous resources such as gas, hydro and coal. Major gas 

infrastructure developments are being carried out and greater use of gas for power 

generation is planned. 

The Electricity Supply Act (ESA) of 1990 provides a legislative framework for regulating any 

activity in the electricity supply industry in Malaysia. Together with any regulations that can be 

made by the Minister (of Energy, Telecommunications and Posts) under section 53 of this 

Act, it forms the regulatory framework for those who opt for cogeneration. 2 Benefits of 

cogenerators under ESA are: 

• Electric utilities must sell power to cogenerators’ facilities; 

• Electric utilities must provide inter-ties with cogeneration systems, if requested by the 

cogenerator; 

• Electric utilities must operate in parallel with a cogenerator facility if the cogenerator 

wishes to do so; 

2 F. X. Jacob, “Development of cogeneration and its regulation in Malaysia”, National Seminar on 

Energy for Future Generation, Malaysia, 1995.


• Electric utility rates for the sale of electricity to a cogenerator must be non discriminatory 

when compared with other customers; 

• The electric utility must provide special services to cogenerators, even though similar 

services are not extended to other customers; these include top-up and stand-by power; 

• Rates for stand-by power shall not be based on the assumption that outages of all 

cogenerator’s facilities on a given electric utility system will occur simultaneously or 

during peak periods. The rates for power purchased during maintenance shall take into 

account the extent to which the scheduled outages of the cogenerator's facility can be 

usefully co-ordinated with those of the utility’s facilities; 

• Cogenerators who qualify to sell electricity to the utility will be paid for at the utility avoided 

cost. 

In the Philippines, Energy Regulations No. 1-95 allows private sector participation in power 

generation activities and also covers cogeneration systems. 3 Under this regulation, the 

benefits gained by cogenerators are: 

Electric utilities shall sell power to a cogenerator if requested; 

Cogenerators can sell power to the electric utilities and the utilities can purchase at a rate 

based on utilities’ avoided cost; 

Except for back-up power, rates for sales of electric utilities to cogenerators can be based on 

the net interchange of energy between them. The applicable rates in this case shall be the 

rates stipulated in a contract between cogenerators and utilities; 

Electric utilities shall provide the back-up power and maintenance power at a rate approved 

by Energy Regulatory Board; 

For small scale cogenerators (having capacities below 10 MW), the electric utilities shall 

shoulder all costs needed for establishing the physical connection between the cogeneration 

facilities and utilities’ transmission network; 

For the cogeneration facility of any size, maintenance costs for the interconnection facilities 

shall be borne by electric utilities. 

4.3.4 Financing issues 

Cogeneration systems are somewhat capital intensive. Many countries in the region face a 

major obstacle to the development of innovative energy technologies such as cogeneration 

due to lack of investment financing, particularly when there is a rapid economic growth taking 

place and the energy prices are low. It becomes imperative to look for financing techniques 

that will have less impact on a firm’s financial balance sheet. In some cases, grants can help 

to reduce investment costs and to promote the financing of remaining investment. The aim of 

the grant should not be merely subsidized to improve the company’s profit, but to minimize 

financial risks associated with innovative technologies. 

Incentives provided by the public authorities may include tax relief and accelerated 

depreciation for investments in cogeneration systems. Interest rate subsidies and loan/equity 

guarantees may also be considered for reducing the risks associated with private sector 

investment in small and medium enterprises. As an energy efficient device, some equipment 

3 

Department of Energy, Implementing Rules and Regulations, Executive Order No. 215, the 

Philippines, 1995.


to be used in cogeneration systems should avail duty-free or low duty benefits. Several 

countries in Asia have already adopted a number of these measures in their efforts to 

encourage efficient energy generation and utilization. For example, the government of India 

has listed a number of energy generating devices which are eligible to apply for reduced 

import taxes and duties, accelerated depreciation, income tax holiday, capital and interest 

subsidy, etc. (for more details, please see Part II, Chapter 1). 

In Europe, apart from the national incentives given to private companies, there are several 

European Union energy programmes that provide grants to encourage investment in energy 

efficiency (e.g. JOULE, THERMIE). The concept of third party financing is strongly supported 

by the European Commission in order to help companies finance investment without 

affecting their balance sheets. Projects suitable for third party financing can get assistance 

from the SAVE programme and the Technology Performance Financing (TPF) system 

developed under the SPRING programme of the European Commission. 

4.3.5 Role of electric utilities 

A factor of prime importance appears to be an adequate definition of the structure and activity 

of the electric utility. There is a trend across the globe for liberalization, restructuring and 

gradual disintegration of the traditional vertical energy supply monopolies. Some Asian 

developing countries are already envisaging to separate the production and distribution 

operation of the vertically integrated utilities. The emphasis should be clearly to bring forth 

progressive changes in the utilities so that they gradually become suppliers of energy 

services. 

The public and monopolistic natures of electric utilities in many developing countries lead to 

subsidized price of electricity and improper tariff structures that hinder the promotion of 

cogeneration systems. The electric tariff should be acceptable to all parties concerned and 

not protect the interest of any specific entity. For projects with long term commitments, the 

tariff structures should reflect the long-run marginal cost of electricity generated. There 

should be rules and regulations for the sale and buy-back rates for electric utilities and 

cogenerators; the latter should get benefits for their installed capacities and exported 

electricity based on the avoided costs of electric utilities. 

The active and supportive role of electric utilities in different forms, such as promotional 

activities on behalf of cogenerator, investment in schemes, establishment of joint ventures 

and setting up conducive tariff structures, can be crucial to the development of cogeneration. 

For example, utility owned cogeneration is quite common in Denmark and Germany that have 

a long record of adopting district-heating networks. In countries like the Netherlands, Spain 

and the United Kingdom of Great Britain and Northern Ireland (United Kingdom), joint ventures 

have been established between utility and cogenerator. Similar initiatives have also been 

taken in Japan, Republic of Korea and Thailand. 

A contentious issue related to private participation in power generation is the decision on 

fixing the new capacity that should be added. Capacity planning should not only have 

representation from government and electricity producers and distributors, the interests of 

those willing to contribute to decentralized power generation and cogeneration, should also 

be protected. The procedure applied should be fair and transparent, taking into account 

factors such as cost-effectiveness, location of the plant, environmental benefits, etc. If a 

cogeneration facility shows the same economic promise as a conventional power plant, it is 

obvious that the former should be given a priority. 

The idea of the power utilities implementing a competitive bid process seems the right 

approach to determine the realizable potential for cogeneration. This helps to avoid situations 

of the supply of power greatly exceeding the demand.


4.3.6 Internalization of environmental costs 

Fossil fuel and electricity prices are forecasted to remain low for the short and medium 

terms. As a result, there is likely to be a lack of market forces to support energy efficiency 

projects, including cogeneration using fossil fuels. In the absence of other specific incentives 

for cogeneration development, there is a need to develop a mechanism to internalize external 

environmental costs. Though Denmark and Sweden have succeeded in introducing such 

measures for energy conservation, the European Union proposal for an energy/carbon tax 

has met with significant resistance. The tax revenues on fossil fuel and electricity, similar to 

the one introduced in Thailand (a small tax imposed on oil products to sustain the Energy 

Conservation Promotion Fund), could be used to promote all activities leading to energy 

conservation, including cogeneration. 

4.3.7 Setting targets for cogeneration development 

It is important to set ambitious but realistic targets for cogeneration development as it 

demonstrates a clear political commitment. If insufficient action is being taken, pressure may 

be applied by the organizations that are in-charge of promoting cogeneration. In the European 

Union, specific targets have been set by a number of countries including the Netherlands, 

France, Spain and the United Kingdom. This obliges the concerned authorities to monitor the 

evolution of cogeneration on a regular basis, and intervene, if necessary, in a proactive 

manner by taking timely policy and implementation decisions in consultation with all the 

beneficiaries.

Cogeneration in Asia today 49 


CHAPTER 1: COGENERATION IN ASIA TODAY 

The concept of cogeneration is not new to Asia. What is new, on the other hand, is the 

renewed interest in cogeneration associated with the recent changes in government policies 

regarding the role of private sector in the power sector. Deregulation of the power sector has 

given the right thrust towards revitalization of the cogeneration concept, and has provided an 

excellent opportunity for cogeneration to flourish. Experience in some countries have shown 

that while independent power producers (IPPs) are facing some teething problems, the small 

to medium sized cogeneration projects, despite their relatively small scale, have been more 

successful under the small power producer (SPP) programme. Based on location, 

environment and small-scale advantages, these projects have been capable of providing 

surplus power at highly attractive rates. 

The technology of cogeneration has matured over the years and equipment of all capacities 

and designs are readily available in the market. Moreover, the Asian region has a very large 

and growing industrial base from which cogeneration projects can be easily developed. Given 

the right policy and regulatory framework, and rational pricing mechanism, cogeneration is 

guaranteed to bring economic and environmental benefits at the micro and macro levels. 

The degree of cogeneration development varies widely from one country to another. There are 

several determining factors, including the level of economic and industrial development, 

status of power sector in terms of demand versus supply, availability of fuels, government 

policies regarding the role of private sector in energy supply, local climatic conditions, etc. 

Each country should develop its own strategy and set targets for developing cogeneration on 

the basis of above factors. 

In this context, the examples set by Japan as an industrialized country, and Thailand as a 

developing country, are noteworthy and their cogeneration experiences have been given in 

some details in this section. The status of cogeneration in some other Asian countries is also 

briefly covered here. 

Many Asian countries have a strong agriculture base and do generate large quantities of 

residues from agro-processing industries. These residues have proved to be an excellent 

primary energy source for cogeneration, not only meeting the thermal energy and power 

needs of the industries concerned, but also providing excess power which can be exported to 

the utility grid or sold to neighbouring industries. The last part of this section gives an overview 

of cogeneration from wood and agro-industrial residues in South-East Asia. 

1.2 Status of Cogeneration in Japan 1 

Following the Third Conference of Parties held at Kyoto in December 1997, Japan has set 

itself a target of reducing the greenhouse gas emission by 6 per cent by the year 2010, taking 

1990 as the base year. An Environmental White Book was released in June 1998 wherein 

cogeneration appears as one of the important measures to reduce CO2 emission. 

1 

A. Ishiyama, “Use of cogeneration system in Japan”, ESCAP South-east Asia Sub-regional Seminar 

on Promotion of Energy Efficiency and Pollution Control through Cogeneration, Hanoi, 10-11 November 

1998.

50 Part II: Cogeneration experiences in Asia and elsewhere 

Cogeneration is a well known concept in Japan, and the total cogenerating capacity of public 

power plants and industrial and commercial cogenerators represents 1.8 per cent of the total 

power generation capacity of the country. As of March 1998, there were 1,490 units totalling 

789 MW installed for commercial use and 1,051 units totalling 3,507 MW for industrial 

applications. The details of capacities installed according to the type of prime mover are 

summarized in Table 1.1. As can be observed, industrial cogeneration plants with an average 

power generation capacity of 3.34 MW tend to be much bigger in size compared to the ones 

used for commercial applications, typically around 0.5 MW. Gas turbines are popular as prime 

movers for bigger capacities, followed by diesel engines, and gas engines are widely applied 

at sites with very low demand, ranging between 220 and 450 kW. Gas turbines have a low 

generating efficiency but higher heat recovery rate, making them more attractive for industries 

having high demand for steam. On the other hand, diesel engines with high generating 

capacities but low heat recovery rates are recommended for sites with high electricity 

demands and less heat, mostly in the form of hot water. Gas engines perform somewhere 

between the other two types of prime movers. 

Table 1.1 Cogeneration plants by types and capacities in Japan (March 1998) 

Type of application Projects Prime movers 

Commercial Use 

- Gas turbines 

- Diesel engine 

- Gas engines 

Industrial Use 

- Gas turbines 

- Diesel engine 

- Gas engines 

Number Total Capacity 

(MW) 

45 

768 

677 

255 

563 

233 

156 

407 

226 

1,986 

1,366 

155 

1.2.1 Cogeneration development trend 

Average capacity 

(kW/project) 

3,467 

530 

334 

7,788 

2,426 

665 

Number Average capacity 

(kW/unit) 

81 

1,347 

1,022 

333 

1,075 

344 

1,926 

302 

221 

5,964 

1,271 

451 

The number of installations as well as the capacity has been steadily increasing over the last 

decade (see Figure 1.1). After a sharp rise in 1990, the growth rate slowed down in 1992 due 

to recession and decline of energy price. There has been a renewed interest in cogeneration, 

proven by the fact that over 850 MW of cogeneration capacity was added between March 

1996 and March 1998. 

Data of commercial and industrial cogeneration by type of activity, including number of 

installations and generating capacities, are summarized in Table 1.2. Among commercial 

applications, hotels rank first in terms of number and total capacity, followed by shopping 

centres and offices. The main features of these sites include long and continuous operating 

hours, constant demand of thermal energy for hot water, steam and chilled water. Though a 

few in number, the district heating and cooling network projects with much higher average 

sizes, contribute significantly to the total capacity. Among industrial uses, pharmaceutical and 

chemical industries have the largest share in terms of number and capacity. Other subsectors 

having high cogeneration capacities are oil and gas, pulp and paper, iron and metals, 

and machinery. In contrast, the food industry uses many smaller systems. 

1.2.2 Government support for promoting cogeneration 

The support extended by the government for promoting cogeneration may be classified into 

four categories: special taxation, low interest loan, investment subsidy, and subsidy for new 

technology development.


4,000 

3,000 

2,000 

1,000 

0 

Figure 1.1 Cogeneration development trend in Japan 

Table 1.2 Details of commercial and industrial cogeneration projects in Japan 

(March 1998 data) 

Commercial Cogeneration Industrial Cogeneration 

Building type No. of 

projects 

Office 

Hotel 

Sports facility 

Petrol station 

Shops 

Training centres 

R&D centres 

Hospitals 

Bath houses 

District heating/cooling 

Others 

MW Generating Capacity 

Industrial 

Commercial 

79 83 87 91 95 

Fiscal Year 

193 

292 

164 

86 

194 

89 

52 

153 

87 

13 

165 

Total capacity 

(kW) 

95.7 

161.9 

74.2 

5.5 

138.8 

33.8 

33.2 

81.6 

11.9 

69.7 

83.0 

Industry type No. of Total capacity 

projects (kW) 

Food 

Textile 

Pulp and paper 

Pharmaceutical/chemical 

Metal 

Electrical equipment 

Machinery 

Oil and gas 

Water works/sewage 

Mining 

Others 

The cogenerator may avail either 30 per cent depreciation on the installation cost or 7 per cent 

of tax exemption in the first year of acquisition of cogeneration plant. Low interest loans (2.3 

per cent per year) can be had for 40-70 per cent of the total investment cost. 

Types of subsidies given by different organizations depend on the type of projects, as follows: 

• Subsidy by New Energy and Industrial Technology Development Organization (NEDO): 

- large scale cogeneration for district heat supply (15 per cent of the investment, up to a 

maximum of US$5 million); 

186 

70 

65 

205 

89 

87 

123 

49 

24 

16 

138 

271 

171 

319 

938 

398 

191 

275 

596 

20 

46 

282


- high efficiency natural gas cogeneration system (less than one-third of investment; if 

the project is implemented by the local government, the amount can be as much as 

one-half of investment, with an upper limit of US$174,000); 

• Subsidy by Ministry of International Trade and Industry (MITI): cogeneration for petrol 

stations (up to one-fifth of investment but no more than US$43,000); 

• Subsidy by LPG Gas Centre: LPG cogeneration for LPG Depots (a maximum of 

US$150,000); 

• Subsidy by the Local Government: Cogeneration in regional central disaster hospital (up to 

one-third, not exceeding US$1.5 million). 

Lastly, grants can be obtained for development of new generation environment-friendly 

technologies such as ceramic gas turbines, ceramic natural gas engines, large-scale high 

efficiency fuel cells, etc. 

1.2.3 Revision of electricity supply law 

Under the Electricity Supply Law, nine regional electric utilities had the monopoly to supply 

electricity in the whole country. This law was revised in 1995, which now helps in further 

propagation of cogeneration. The law now allows the private sector to: 

• Sell self-generated electricity to the electric utilities - Private sector was invited by the 

electric utilities to supply 2.7 GW of electricity by tender for the period from 1999 to 2002; 

all the offers added up to 11 GW capacity of which 3 GW was finally approved. In the 

second phase for 2001-2004, another invitation was extended for sending tenders for 2.9 

GW capacity and 14 GW of offers were received; the selection process is on for 

accepting 3 GW of capacity; 

• Wheeling self-generated electricity to other areas through the utility transmission network 

(from April 1998) – The transmission cost is about one-third of the electricity price set by 

the power utilities. Some companies have benefited from this option by exporting 

electricity from one site to another, such as Ooji Paper Company (such as the Kure 

factory, and the Nobeoka factory), Sumimoto Chemical Company and Asahi Chemical 

Company; 

• Supply self-generated electricity to third parties – this has helped in strengthening Energy 

Service Companies. For example, 10 companies in Suwa area have established an 

energy supply company that uses gas turbine cogeneration to supply 3 MW of electricity 

and steam as well as chilled water to hospitals and other users. A utility service company 

has installed 3 units of gas turbines, each of 4.3 MW capacity, to supply electricity, steam 

and chilled water to 67 clients in Amagasaki city. 

While concentrating efforts on promoting cogeneration, adequate measures have been taken 

in the country towards air pollution control from cogeneration plants in urban areas. Standards 

of NOx and particulate emissions have been set for prime movers, keeping in view the 

availability of appropriate and affordable technologies to attain those values. 

Lastly, as cogeneration is perceived as the most important energy conservation technology in 

Japan, a country which relies heavily on imports of primary energy supplies, the government 

is keen on developing new cogeneration technologies which can reduce cost, increase power 

generation and heat recovery efficiency, and minimize NOx emissions.


1.3 Thailand 

Thailand can be considered as an excellent showcase for many of the Asian developing 

countries as far as the promotion of small power generation and cogeneration is concerned. 

The government of Thailand approved a policy in October 1988 to encourage private sector 

involvement in power generation through cogeneration, renewable energies and waste fuels. 

The Energy Policy Sub-committee established a working group with the task to develop 

regulations for the purchase of power from small power producers. After experts reviewed the 

draft regulations, a revised set of regulations was announced by the power utilities of 

Thailand, defining the conditions for the purchase of power from small power producers 

(SPP). This was followed by the first request for proposal of 300 MW and an amendment in 

the EGAT 2 Act, allowing direct sale to third party if not connected to the grid. It took a little 

while to build up awareness in the private sector but once the ideas were understood, there 

was a tremendous response. This is proved by the fact that from only 13.3 GWh of electricity 

purchased from SPP in 1994, the figure went up to 2,152 GWh in 1997. By June 1998, EGAT 

had issued notification of acceptance of electricity from 70 SPPs with a total power capacity 

of 2,951 MW. 

1.3.1 Potential for cogeneration in Thailand 

According to the report of a survey commissioned by the National Energy Policy Office 

(NEPO) of Thailand in April 1992, industries were found to have an installed generating 

capacity of over 876 MW, 22 per cent of which was set aside as the spare capacity. A 

detailed study undertaken for each of the industrial sub-sectors revealed a technical potential 

for increasing the existing generation capacity by over 3,000 MW. A rigorous financial analysis 

using the prevailing economic and financial parameters and relatively conservative 

assumptions indicated that about one-half of the estimated technical potential, over 1,500 

MW, could be financially viable. 

2 

Table 1.3 Existing and potential cogeneration in Thai industries (1992 data) 

Type of 

industry 

Chemical industry 

Food industry 

Industrial estate 

Municipal waste 

Oil refinery 

Palm oil mill 

Petrochemical 

Pulp and paper 

Large rice mill 

Saw mill waste 

Sugar mill 

Textile mill 

Existing 

cogeneration 

capacity (MWe) 

8.4 

15.3 

- 

- 

27.0 

6.0 

64.1 

68.4 

47.2 

- 

630.0 

9.4 

Additional 

technical 

potential 

(MWe) 

626 

681 

N.A. 

48 

141 

32 

268 

252 

444 

- 

329 

277 

EGAT: Electricity Generating Authority of Thailand 

Additional 

financial 

potential 

(MWe) 

236 

216 

- 

69 

20 

- 

100 

45 

200+ 

- 

100 

33 

Remarks 

many small factories 

many small factories 

pending cabinet decision 

requires low cost fuel 

expansion in production 

high-pressure system retrofit 

all financially viable 

smaller size not feasible 

use of surplus husk at 50 bar 

unsteady supply 

buy-back at 1.2 Baht/kWh 

grid purchase reduction only


The National Energy Policy Office (NEPO) has estimated the technical potential for 

cogeneration in about 20 industrial estates alone to be as high as 5,000 MW. 

1.3.2 Institutional initiatives and government policies 

Apart from the government’s policy to encourage private sector participation in power 

generation in the form of independent power producers (IPPs), the energy authorities of the 

country recognize that energy generation from non-conventional energy, waste or residual 

fuels, and cogeneration: 

1. promotes the use of indigenous by-product energy sources and renewable energy for 

electricity generation; 

2. increases the efficiency in the use of primary energy; 

3. encourages the participation of small power producers (SPPs); 

4. reduces the financial burden on the public sector with respect to investment on electricity 

generation and distribution. 

The power utility has the obligation to purchase electricity from any SPP who cogenerates 

using any type of fuel, meeting certain requirements. These include the type of thermal cycles 

to be used, the minimum amount of thermal energy to be used from the cogeneration plant, 

and the minimum overall efficiency on the basis of the type of fuel used. 

Further boost has been given, through the announcement of a special power purchase price 

in September 1996, to the SPPs intending to develop waste-to-energy projects. As of April 

1997, 22 projects using bagasse, rice husk, wood chips, and palm oil wastes had been 

accepted, with a capacity to produce 462 MW of electricity, of which 182 MW will be sold to 

the power utility. 

The price for purchasing electricity from SPPs is based on avoided cost of electricity. For 

those signing contracts to supply a firm capacity, the purchase price is based on the long-run 

avoided cost of the utility. On the other hand, there is no contracted demand for non-firm 

contracts, and accordingly, there is no capacity payment. As an example, the purchase price 

of electricity for a non-firm contract is 1.29 Baht/kWh whereas it can increase to 1.60 

Baht/kWh in the case of a firm contract for a period of 25 years. Figure 1.2 shows the 

evolution of power purchases from SPPs during the period 1994-97. 

Purchased,GWh/year 

1,800 

1,500 

1,200 

900 

600 

300 

0 

Firm Non-firm 

1994 1995 Year 1996 1997 

Figure 1.2 Evolution of power purchases from small power producers


1.3.3 Impact of regional economic crises on cogeneration development 

Initially, proposals were submitted by 91 potential SPPs to sell over 4,680 MW of electricity to 

the utility grid. The power utility issued notification of acceptance of electricity from 70 SPPs 

with a total power capacity of 2,951 MW, with 48 firm contracts (2,806 MW) and 22 non-firm 

contracts (145 MW). 3 

The regional economic crises have had serious impacts on the development of cogeneration 

projects, many due to the devaluation of the currency affecting project investment costs. 

Thanks to the intervention of the Ministry of Finance in the form of adjusting the currency 

exchange system to a Baht float system, many SPPs have managed to survive and continue 

their projects. As of June 1998, the number of SPPs proposing to sell electricity had gone 

down to 56 in number, and the total capacity proposed amounted to 2,470 MW. Though EGAT 

has committed to buy up to 2,436 MW of power from the SPPs, 51 power purchase 

agreements have been signed so far between the utility and SPPs for supply of 2,255 MW. 

The status of these projects is summarized in Table 1.4. 

Table 1.4 Impact of financial crises on the status of SPP projects (June 1998) 

Status Number of 

SPP 

PPAs signed 

• in operation 

• final stage of development 

• early stage of construction 

• no construction/financing 

51 

29 

9 

3 

10 

Total generating 

capacity (MW) 

4,336 

1,529 

887 

480 

1,439 

Capacity sale to 

EGAT (MW) 

2,255 

It is estimated that 10 projects totalling 1,479 MW of installed capacity would not be 

completed, reducing the power purchased by EGAT to 1,795 MW, of which 1,608 MW will be 

on firm-contract basis. 

It is interesting to note that 22 of the projects based on natural gas as fuel have all signed firm 

contract agreement with EGAT for a period ranging from 21 to 25 years. These are followed 

by 13 projects which use bagasse as fuel and which have signed non-firm contracts due to 

the seasonal availability of the fuel as a waste in sugar mills. 

The first two important SPP projects which went into commercial operation in 1996 with an 

aggregated installed capacity of 300 MW, have signed firm contracts with EGAT to make a 

total of 180 MW capacity available for a period of 21 years. Located in a newly developed 

industrial zone, the plants use offshore natural gas as fuel and sell the cogenerated steam at 

two different pressures to several industries in the industrial estate. 

Some of the regulations in place may require further fine-tuning and refining on the basis of 

experience gained. On the whole, Thailand has set an excellent example to other developing 

countries in the region concerning how a combination of good policy initiatives, regulatory 

measures, and rational tariff structure can assure a rapid development of cogeneration. An 

active participation of the private sector can help to alleviate the financial burden on the 

national power utility. 

3 P. Srisovanna, “Thailand’s experiences with promotion of cogeneration”, ESCAP South-East Asia 

Sub-regional Seminar on Promotion of Energy Efficiency and Pollution Control through Cogeneration, 

Hanoi, 10-11 November 1998. 

693 

630 

270 

662


1.4 India 

India continues to face serious power shortages in spite of an installed capacity close to 

90,000 MW, mainly due to the lack of funds for new installations as well as poor operation of 

the power industry managed by the public sector. As a result, the country faces shortages of 

more than 18 per cent in peak demand and over 9 per cent in electricity requirements. 

Realizing the important role that the private sector can play in power development, 

government has recently opened the power sector to the private sector. In addition, 

government is also encouraging other low-cost or more efficient alternatives, such as the use 

of non-conventional energies and cogeneration in industry. 

1.4.1 Assessment of cogeneration potential 

A report prepared by the Ministry of Power reveals that considering the various in-house 

generating facilities adopted by Indian industries, the installed capacity in industry alone is 

around 12,000 MW, without taking into account units of less than 1 MW capacity. Though 

some of the industries have already adopted cogeneration plants, additional cogeneration 

potential in selected industrial sub-sectors is estimated to be 6,530 MW. The actual installed 

capacity is still very low, and aside from the sugar industry, cogeneration has not been 

pursued seriously due to various reasons. 

According to this report, sugar mills have the highest cogeneration potential, estimated as 

3,200 MW. To achieve this, the mills need to be modernized. On supply side, high-pressure 

boilers with high efficiency turbo-generators can assure better utilization of bagasse. On the 

demand side, replacement of small turbines by hydraulic drives and use of multiple-effect 

evaporators can help to reduce the process steam demand. 

A recent national survey estimates the overall industrial cogeneration potential to be around 

15,000 MW, with the sugar mills alone accounting for one-third of the total, followed by 

distilleries, fertilizer plants, rice mills, textile industries and pulp and paper mills, and others. 4 

1.4.2 Drawbacks in cogeneration development 

The main drawback in cogeneration development has been the lack of clear policies and 

regulations. The State Electricity Boards (SEBs) have not been supportive of the idea of 

captive power plants; cogeneration being regarded as a subset of the captive segment, was 

also neglected and never fully promoted. SEBs consider the power from industry to be too 

small and its cost to be generally higher than the prevailing tariff. As industries are charged a 

higher tariff, utilities are afraid to lose good customers. 

Many industries are not aware of the benefits of cogeneration in terms of cost savings, the low 

level of incremental investment needed, and the existence of a number of financing options. 

They are concerned about the problem of space, shut down and investment necessary for 

setting up cogeneration facilities. They are not sure about the long-term availability of fuel for 

operating the cogeneration plant. In case there is excess electricity available for export to the 

grid, industries are not sure whether the SEBs can pay as most of them are facing acute 

financial constraints. 

4 A.S. Bakshi, “Status of cogeneration development in India”, ESCAP South-Asia Sub-regional 

Seminar on Promotion of Energy Efficiency and Pollution Control through Cogeneration, Dhaka, 14-15 

November 1998.


1.4.3 Government initiatives to promote cogeneration 

Acknowledging the fact that cogeneration plants are more efficient, have low gestation period, 

and can effectively create additional power generating capacity, government has issued 

guidelines related to clearance of projects and fixing of tariff for export of electricity by 

cogenerators. 

Industries will be allowed to develop cogeneration facilities without necessarily going through 

competitive bidding process. If the cogeneration plant is a topping-cycle, it must supply at 

least 5 MW to the grid for not less than 250 days in a year in order to assure grid stability and 

adequate planning of the power system. Depending on the type of fuel used, the plant should 

meet certain efficiency criteria to be eligible as a cogeneration facility. If the cogeneration 

facility is a bottoming cycle, the total useful power output should not be less than 50 per cent 

of the total heat input through supplementary firing. 

The schedule for power supply to the grid should be mutually worked out between the SEB 

and the cogenerator, keeping in mind that the surplus power may vary during the day and with 

season. While negotiating tariff, the basic consideration should be to share the benefits of 

higher efficiency. Industry will be assured of power supply, possibly at a lower tariff than that 

charged by the utility due to cross subsidization. 

Some progresses in cogeneration have been made thanks to the initiatives and proactive role 

of the Ministry of Non-conventional Energy Sources (MNES) and the Indian Renewable Energy 

Development Agency (IREDA). They have extended financial assistance such as subsidies, 

low-cost loans and technical assistance. In order to launch demonstration projects, MNES 

provides capital subsidy of Rs 20 million/MW of surplus power (comprising Rs 7 million/MW 

as subsidy and balance as soft loan) to cooperatives and public sector sugar mills, and Rs 7 

million/MW of subsidy (maximum of Rs 60 million per project) to other sugar mills. 5 In 

addition, there is an interest subsidy of Rs 1.5 million/MW for projects with 1-4 MW of surplus 

power generating capacity, and Rs 3.5 million/MW for those with more than 4 MW surplus 

capacity. IREDA provides up to 75 per cent of the financing of the project at lower than market 

interest rates, and allows for a repayment period of 10 years, allowing for a moratorium period 

before the cogenerator is actually required to start repaying the loan. 

5 

Table 1.5 Incentives offered by state governments for cogeneration projects 

States Maharashtra Tamil Nadu Karnataka Uttar Pradesh 

Participation Government & 

cooperative 

Power wheeling 

rates 

SEB buy-back 

rate 

20 per cent of energy 

generated 

>4 MW: Rs2.25/kWh; 


Lately, the Ministry of Power has been involved in simplifying procedures by persuading SEBs 

to allow third-party sale of electricity, buy-back surplus power at higher rates (close to Rs 2.25 

per kWh in most instances), and offer clear and transparent wheeling and banking policies. 

SEBs are now more receptive to the idea of captive power generation and are encouraging 

proposals for cogeneration facilities. Some state governments are also providing incentives 

for cogeneration, such as capital cost subsidies and exemption from generation taxes (see 

Table 1.5). 

1.5 Indonesia 

In Indonesia, cogeneration technology has been traditionally associated with major process 

industries having high steam demand, such as paper, chemicals, refineries, and food and 

beverage industries. However, not many industries are presently utilizing cogeneration 

technology due to two main reasons. The industrial decision-makers are little aware of the 

technology and its economic merits. Secondly, the energy price does not reflect its actual 

cost. 

On the other hand, captive power plants are commonly employed in Indonesia due to the 

geographical characteristics of the country and inability of the national grid system to supply 

the amount of energy required by the users. The share of energy from captive power plants 

represented 36 per cent of the total in 1990. According to projected figures, the share of 

captive power plants will be 9,000 MW, or 29 per cent of the total 20,000 MW in 1998-99. 

Majority of cogeneration facilities established in industries is located in East Java. Adopted 

mostly by textile and paper industries, the total installed capacity of 11 cogeneration plants in 

operation exceeds 530 MW. The units, with capacities ranging from 4 to 38 MW, employ 

either coal-fired steam turbines or natural gas fired gas turbines with heat recovery boilers. 6 

According to the information available with the Indonesian power utility, PLN, there were about 

10 plants under construction at the end of 1996, using steam and gas turbines, reciprocating 

engine and combined cycle, with a total capacity exceeding 360 MW. 

1.5.1 Institutional initiatives and policies for promoting cogeneration 

There are two relevant documents that reflect government’s policy on cogeneration. The first 

regulation issued in 1993 allows the IUKU holder (the one who has the license to provide 

electricity to the public) to allow the industries to adopt cogeneration technology for their own 

use within utility’s concession area, and sell the excess power from the cogeneration facility 

to the utility. The Ministry of Mines and Energy published the tariff for purchase of electricity 

from small power producers. After power generation from solar, mini-hydro and wind 

energies, cogeneration from agricultural and industrial wastes was given the next priority, 

allowing sale of up to 30 MW for Java-Bali grid system, and up to 15 MW for the other grids. 

The third priority was given to cogeneration using conventional fuels, followed by power 

generation alone with conventional fuels. 

In line with the energy policy, government will look into some factors while issuing permits to 

private generators and cogenerators who intend to produce energy for their own use and for 

selling excess to others. These include the local grid capability, primary energy source used, 

pricing mechanism, security of energy supply, and environmental impact. 

6 M. Oetji, “Electric Power in Indonesia: Public-private partnership and opportunity for cogeneration”, 

Paper presented at the 1996 Cogeneration in Asia Conference, AIC Conferences, Singapore, 25-27 

November 1996.


1.5.2 Launching of innovative facilities management schemes 

Many industries have been compelled to go for captive power generation, but do not have the 

skill and competence necessary to operate these units efficiently. Though they realize the 

importance of increasing efficiency of their generating facility, they are not willing to lose focus 

on their core businesses. A captive power plant presents itself as another cost centre, without 

giving any return from the investment or directly contributing any profit to the company. 

Moreover, it requires qualified staff and management time. 

Initiatives have been taken by specialized companies to offer facility management services to 

such enterprises so that all their energy supply needs are met and guaranteed, allowing the 

enterprises to concentrate on their core business activity, to avoid making investment on 

energy supply, and to mitigate operation and maintenance risks. All that they have to do is to 

pay their monthly energy bill, as they would have done in the case electricity was purchased 

from the grid. 

Figure 1.3 A typical facility management company (PT. Cogindo DayaBersama) 

Having well qualified and experienced staff, the facility management firms shoulder the 

responsibility of investing on the cogeneration plant, managing the operation and maintenance 

as well as fuel supply, spare parts and supply of consumables. Acting as the sole point of 

responsibility, these firms strive to provide quality, reliable and cost-effective energy products 

since energy is their core business. 

1.6 Philippines 

Boundary of Industrial/Commercial Area 

Industrial or 

commercial 

activity 

Activity of the Enterprise 

All forms of 

energy 

Monthly 

energy bill 

Cogeneration 

Plant 

Owned by the Facility 

Management Company 

The base-load or stand-by generating capacity of industries in the Philippines is estimated to 

be 600 MW, 58 per cent of which is operated in cogeneration mode. Industries with 

cogeneration systems have generally designed their equipment to meet only the on-site 

electricity needs. Many of these facilities are found to be under-utilized. Most of the 

cogeneration installations have been commissioned prior to the oil shock of the 1970s. 

Fuels 

Spare Parts 

& 

Consumables 

O&M 

Activities & 

Personnel


Sugar sub-sector alone accounts for about 60 per cent of the total generation capacity of 346 

MW. Other sub-sectors having important cogeneration capacities are the pulp and paper, 

wood and petrochemical industries. 

1.6.1 Policy and institutional framework for supporting cogeneration 7 

Studies conducted by the Department of Energy (DOE) place the cogeneration potential at 

around 400 MW. The government has manifested a growing interest to promote industrial 

cogeneration, with the following rationale: 

1. development policy: recognizing that adequate power supply is one of the basic prerequisites 

for sustained economic growth, decision was taken to allow private sector 

participation in the power sector; 

2. additional resources: the private sector can be expected to bring additional resources or 

equity funds; 

3. efficiency improvement: many industries with continuous demand for low quality steam 

can install power generation units and use the waste steam for industrial process needs, 

thus high fuel use efficiency can be achieved; 

4. environmental benefits: cogeneration offers substantial reductions in exhaust gas 

emissions. 

Government has therefore instituted policies, incentives and programs for supporting 

cogeneration along with renewable energy technologies. The Executive Order No. 215, which 

took effect in July 1987, allows for private sector participation in power generation, including 

cogeneration. It applies to those intending to sell the generated electricity to the utility or to 

third parties. Those wishing to qualify as a cogenerator have to satisfy certain technical, 

efficiency, and financial criteria. 

Fiscal incentives extended to the cogenerators include income tax holiday for six years, 

reduced duty of only 3 per cent on imported capital equipment and spare parts, tax credit on 

domestic capital equipment and spare parts and tax deduction for labour expenses. 

For purchase of power from cogenerators having less than 10 MW capacity, standard power 

purchase rates are adopted which reflect the structure of capacity and energy costs of the 

national utility for varying levels of power availability and dispatchability. The electric utility shall 

sell power to the cogenerator upon request. The back-up power provided by the utility will be 

at a rate approved by the Energy Regulatory Board. 

The host utility is obliged to interconnect and wheel the electricity generated to a third party; 

for cogeneration with less than 10 MW capacity, the utility will shoulder all the costs. For 

cogeneration facility of any size, maintenance cost of the interconnection facility shall be 

borne by the electric utility. 

In September 1997, the National Power Corporation signed a power purchase agreement for 

the biggest cogeneration facility that will add 304 MW of power to the Luzon grid and at the 

same time, supply quality steam to an oil refinery and a chemical plant. 

7 A. M. Nabong, “Status of cogeneration development in the Philippines”, ESCAP South-East Asia 

Sub-regional Seminar on Promotion of Energy Efficiency and Pollution Control through Cogeneration, 

Hanoi, 10-11 November 1998.


1.7 Republic of Korea 8 

The rapid economic growths associated with industrialization in the last three decades have 

resulted in sharp increase in power and energy demand. To cope with this, the government 

has been actively involved in adopting ways and means for using energy more efficiently, 

conserving energy through recovery of waste energy, supplying reliable energy at low cost, 

and supplying energy more effectively in a decentralized manner to industrial zones and 

satellite cities. 

A major outcome of these efforts has been the widespread development of cogeneration 

since the 1980s. This is proven by the fact that the share of power generation of cogenerated 

plant over the total generating capacity has sharply increased from 4.6 per cent in 1985 to 20 

per cent in 1995 (see Figure 1.4). 

Cogeneration development that has taken place in the Republic of Korea can be classified 

into 4 distinct categories: industries, high-rise buildings, industrial estates, and district heating 

networks. The total number of cogeneration plants in these four areas was 90 units in 1995, 

with a cumulative power generation capacity of 6,225 MW. 

Share of cogeneration, % 

25 

20 

15 

10 

5 

0 

81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 

Year 

Figure 1.4 Share of electricity from cogeneration over total grid system 

The industrial sector has seen rapid growth in cogeneration. As of 1995, there were about 60 

units in operation, with an aggregated capacity of 2,534 MW. These plants were adopted by 

the sub-sectors that have helped in the industrialization process, namely steel, petrochemical, 

refinery, textile, pulp and paper, and food industries. Data for 1994 shows that the 

industry sector had a captive power generation capacity of 3,056 MW and a total of 19,938 

GWh was generated. Steel mills alone accounted for one-half of the total installed capacity. 

High-rise buildings constructed in recent years have high demands for heating, ventilation and 

air conditioning, and are therefore ideal clients of cogeneration. As of 1995, there were 7 

cogeneration facilities developed with a total power generating capacity of 59.1 MW. 

Industrial complexes have been developed to induce small and medium scale enterprises and 

government has a policy to encourage the setting up of cogeneration facilities to supply 

different forms of energy to individual factories within the industrial zone. A target has been set 

to adopt cogeneration systems in 33 industrial complexes by 2001. Financial assistance and 

tax incentives are extended to individual firms that invest in such projects. Loans with 

8 R.T.Lee, “Cogeneration projects for industrial sector as well as residential/commercial sector in the 

developing countries”, Paper presented at the 1996 Cogeneration in Asia Conference, AIC Conferences, 

Singapore, 25-27 November 1996.


favourable terms are provided, offering 8-year grace period and 7-year repayment period in 

instalments with interest rates that are about half the market rate. By 1995, 13 industrial 

complexes had cogeneration plants with a total capacity to generate 619 MW of power. 

The most important cogeneration development has been in connection with district heating 

system in the outskirts of Seoul metropolitan city. Government set up an ambitious plan to 

provide two million residential units, mostly apartment buildings, outside Seoul city during late 

80s and early 90s, in order to disperse the population in newly developed towns. Ten such 

projects were commissioned by 1995 in the satellite cities that have a great demand for heat 

during the cold season. Cogeneration plants were jointly built by two public sector enterprises; 

the Korea Electric Corporation assured the electric power supply, while district heating was 

handled by the Korea District Heating Corporation. A total power generating capacity of 3,013 

MW was already in place by 1995. Further expansion plans include the southern part of Seoul 

city, which will include residential areas for over three million people. 

An example of cogeneration and district heating project that has been developed recently is 

the one in the town of Bundang. In order to supply electricity and other forms of energy to 

approximately 100,000 households in mostly apartment buildings, natural gas fired combined 

cycle cogeneration plants were installed with a total capacity of 600 MW of power and 560 

Gcal/hour of heating facility. Covering a total heating area of 13.8 million m 2 , and selling 1.523 

million Gcal/year, this installation has been estimated to save around 83,000 toe/year. 

1.8 Cogeneration from Agro-industrial Residues: ASEAN 9 Experience 

Agricultural residues from rice, sugar cane, palm oil, coconut and timber industries in ASEAN 

totalled almost 100 million tons in 1990. These five main agro-industrial sectors convert 

between 30 to 70 per cent of total raw material into waste that constitutes an energy 

equivalent of 25 Mtoe, approximately equal to the total industrial primary energy demand of 

ASEAN. Experts estimate that only 50 per cent of this bio-waste is utilized, generally 

employing inefficient and outdated technologies, to generate heat and/or power and to meet 

about 20 per cent of the total industrial primary energy demand in ASEAN. 

Changes in national policies have led to private participation in power generation and rational 

use of indigenous energy resources. Moreover, there is a growing concern for clean energy 

and environmentally sound solutions. These have renewed interest among the self-producers 

of energy to employ more efficient and modern technologies for added economic benefits and 

environmental compatibility. Results of studies conducted by the EC-ASEAN COGEN 

Programme 10 for assessing the potential of energy generation from agro-industrial residues in 

ASEAN are summarized below. 

1.8.1 Rice industry 

Rice husks produced as residues from the rice milling industry can be used as fuel. In a 

typical rice mill, electricity required for milling is purchased and heat needed for either 

mechanical paddy drying or for parboiling is generated from fossil fuels or rice husk. Over 

200,000 rice mills are estimated to be in operation in ASEAN, producing over 26 million tons of 

rice husk annually. 

9 

ASEAN represents the Association of South-East Asian Nations. 

10 The EC-ASEAN COGEN Programme is an economic co-operation between the European 

Commission and ASEAN. Co-ordinated by the Asian Institute of Technology, it aims at accelerating the 

implementation of proven technologies generating heat and/or power from wood and agro-industrial 

residues.


Every ton of paddy processed generates around 250 kg of husk which, when used as fuel, is 

capable of producing 100 kWh of electricity on an average. The milling power needed for a ton 

of paddy ranges from 20 kWh for white rice production to 60 kWh for parboiling and 

mechanically dried white rice. Assuming that 2.7 kg of husk are necessary to produce 1 kWh, 

theoretically over 13,000 GWh/year of electricity could be generated. In practice, however, 

much less may be expected from the rice-milling sector as financial analyses show power 

generation to be feasible only for plants having a capacity above 5 tons/hour. As shown in 

Table 1.6, rice-milling capacities of many ASEAN factories are far too small to be financially 

attractive for cogeneration applications. 

Country Rice mills Paddy 

(10 6 tons) 

Indonesia 

Malaysia 

Philippines 

Thailand 

Viet Nam 

>78,000 

380 

>13,000 

17,000 

>100,000 

1.8.2 Sugar industry 

Table 1.6 Status of rice industry in ASEAN 

49.7 

2.2 

10.5 

33.8 

24.9 

Rice husk 

(10 6 tons) 

10.94 

47.0 

2.32 

7.45 

5.49 

Generation 

potential 

(GWh/year) 

5,472 

237 

1,160 

3,725 

2,746 

Milling 

capacity 

(>5 tph) 

0 

62 

71 

78 

55 

Generation 

capacity 

(MW) 

0 

28 

68 

61 

66 

In most sugar mills, bagasse generated as residue is utilized for heat and power generation. 

There are over 150 sugar mills in the ASEAN, producing close to 35 million tons of bagasse 

annually. A little less than one-third of the raw sugar cane is turned into bagasse. Processing 

one ton of sugarcane will generate an average of 300 kg of bagasse. Assuming that bagasse 

is consumed efficiently, 3 kg of bagasse is necessary to produce a kWh of electricity. Based 

on this, the technical potential for power generation from bagasse in ASEAN can be estimated 

at 11,600 GWh/year (see Table 1.7). However, the existing equipment in most facilities is old 

and inefficient, often resulting in the generation of low-pressure steam. There is a need for 

adopting boilers of higher capacities and pressures greater than 40 bar. 

Country Sugar 

mills 

Indonesia 

Malaysia 

Philippines 

Thailand 

Viet Nam 

Table 1.7 Status of sugar industry in ASEAN 

67 

N.A. 

36 

46 

16 

1.8.3 Palm oil industry 

Sugarcane 

(10 6 tons) 

29.05 

N.A. 

18.50 

57.97 

11.29 

Bagasse 

(10 6 tons) 

8.72 

N.A. 

5.55 

17.39 

3.39 

Generation 

potential 

(GWh/year) 

2,906 

N.A. 

1,777 

5,797 

1,129 

Generating 

capacity 

(MW) 

792 

N.A. 

758 

1,871 

54 

In a palm oil industry, as much as 70 per cent of the fresh fruit bunches (FFB) are turned into 

wastes such as empty bunches (23 per cent), fibres and shells (19 per cent), while between 

600 and 700 kg of liquid effluent are produced per ton of FFB. Though many palm oil mills 

generate combined heat and power from fibres and shells, the use of palm oil residues could 

still be optimized. Fibres and shells generated by a ton of FFB can produce approximately 45 

kWh; empty bunches could contribute to another 35 kWh of electricity generation.


More than 40 million tons of fresh fruit bunches are processed annually (of which, almost 75 

per cent are in Malaysia alone) by about 430 mills in ASEAN. Thus the technical potential for 

power generation from solid residues from ASEAN palm oil industry amounts to over 3,200 

GWh/year and around 2,470 MW of total generating capacity. 

1.8.4 Wood industry 

The wood industry - including sawmills, plywood factories and furniture industries - converts 

about half of the raw wood into residue during the production process. The wood waste 

generated in the plant is capable of generating as much as 150 kWh of electricity. But the 

majority of sawmills in ASEAN (mostly located in Indonesia and Malaysia) are either 

connected to the national grid or use diesel generators to meet their electricity demand. 

The plywood industry requires large amount of power and heat. The wood waste can be 

effectively utilized to cogenerate heat and power to satisfy all the energy demand of the plant. 

Financial analyses carried out on some specific projects show that the pay-back period on 

investment would be around 3 to 4 years, thus making the wood cogeneration market most 

lucrative. The owners of integrated factories, combining sawmill, plywood and furniture 

making, can benefit a lot through better utilization of the cogeneration plant capacity. 

The technical potential for power generation from over 19 million tons of residues in ASEAN 

wood industry is assessed to be over 4,800 GWh/year and around 920 MW of total generating 

capacity can be expected. 

1.8.5 Full-scale demonstration projects 

Many biomass energy technologies are technically sound and economically viable, and yet 

have not yet been implemented due to a number of reasons, the most important among them 

are the lack of awareness and unavailability of suitable technologies. The EC-ASEAN COGEN 

Programme attempts to establish references for such technologies and to accelerate the 

implementation of proven technologies in ASEAN by launching full-scale demonstration 

projects (FSDP). Financial and technical assistance is extended to implement proven 

technologies on full-scale basis in the hope that replication of such projects will reduce fossil 

fuel dependence and will contribute to the protection of the environment. 

To date, about 15 full-scale demonstration projects (FSDPs) have been commissioned under 

this Programme. The salient features of some of these projects are highlighted below. 

Wood waste-based cogeneration 

This is a factory located in Sarawak, Malaysia. The project consists of a 1.65 MW wood 

waste-fired power plant that includes a boiler with a capacity to produce 30 tons/hour (tph) of 

steam at 21 bar. Steam is supplied to a fully condensing turbine to produce 1,650 kW of 

power. About 10 tph of process steam is required at 7 bar to be used for kiln drying of wood. 

The total cost of the project is a little less than US$ 2 million and the payback period is 

calculated as 3.1 years. 

Cogeneration in a rice mill 

This is a factory located in Nakorn Ratchasima, Thailand. The project consists of a rice huskfired 

2.5 MW power plant that includes a boiler producing 17 tph of steam at 35 bar. This 

steam is supplied to a condensing turbine to generate 2.5 MW of power. Flue gas from the 

boiler is used for paddy drying. The total cost of the project is around US$ 3.87 million and the 

payback period is estimated as 3.6 years.


Cogeneration in a plywood industry 

This is a factory located in South Sumatra, Indonesia. The installation consists of a turn-key 

supply of a wood-waste fired boiler to replace two existing boilers which cannot supply 

sufficient steam to operate an existing turbo-generator with a net output of 3.2 MW. About 35 

tph of steam generated at 35 bar and 380°C with the new efficient boiler would be adequate 

for meeting the turbo-generator requirement as well as that needed for the process. The 

overall project cost is US$ 1.6 million and the payback period works out as 2.4 years. 

Cogeneration from palm oil waste 

The factory is located in Johor, Malaysia. The waste from the mill will be fed to the proposed 

steam boiler to produce 35 tph of steam at 23 bar. This steam is expected to pass through a 

backpressure turbine to generate 1.2 MW of power and the exhausted steam at 4.1 bar will be 

adequate to meet the process steam requirements. The total cost of the project is estimated 

as US$ 693,300 and the payback period is calculated as 3.7 years. 

Cogeneration in a paper mill 

The factory is located in Chachoengsao, Thailand. Earlier, 24 tph of steam was produced in 

an existing rice husk-fired boiler at 20 bar and was passed through a pressure-reducing valve 

to meet the process heating requirement at 6 bar. The project consists of introducing a 

backpressure turbine after the boiler so that the steam at 20 bar can be expanded up to the 

required pressure of 6 bar, while generating 600 kW of electricity. The cost of the turbine with 

the accessories is US$ 102,000, which leads to a very short payback period of 1.4 years. 

Energy from waste water in rubber factory 

The factory is located in Selangor, Malaysia. The project consists of wastewater treatment 

plant that will treat the liquid effluents from the factory by anaerobic digestion to produce 

around 7,820 Nm 3 of biogas per day. This biogas will partially substitute the medium fuel oil 

used in the existing thermal fluid heater. The project cost is estimated as US$ 1.5 million and 

the payback period works out as 4.1 years.

Examples of cogeneration projects implemented in Asia 67 

CHAPTER 2: EXAMPLES OF COGENERATION PROJECTS IMPLEMENTED IN 


ASIA 

A vast majority of the Asian countries has yet to tap the existing cogeneration potential to the 

maximum. Considering the rapid industrial growth in many parts of the region, one would 

expect many more new process industries and commercial buildings to be added to the 

existing stock within a short span of time. These investments can be even better managed if 

the concept of cogeneration is well understood by the developers and investors. The endusers 

will have greater choices and more alternatives, in addition to having enhanced scope 

for decision making and professionalism. At the same time, the power utilities can have 

access to low cost and reliable excess energy produced in some areas faced with chronic 

deficit of power supply in the past. 

There is also a potential for cogeneration development based on privately funded projects in 

close cooperation with potential end-users/customers and power companies. Owners of 

existing as well as new industries and commercial buildings will benefit from these schemes 

by having access to low-cost and more reliable energy supplies. Moreover, it will help them to 

conserve their capital that would otherwise have been required for on-site energy facilities; the 

saved resources and capital can be ploughed into their core business for improving their profit 

margin and competitiveness. 

It is encouraging to note that there are already a large number of cogeneration plants which 

have been commissioned in some Asian countries in the last decade or so. The following 

sections are aimed at providing sample examples of initiatives already undertaken in the 

directions highlighted above. Each of the examples briefly covers the situation that led the 

decision-makers to opt for cogeneration and the various benefits accrued from the project. 

2.2 Cogeneration in Petrochemical Industry 

Reliable power is essential for commercial viability of petrochemical industries. A small power 

interruption does not only result in substantial production loss but can also jeopardize the 

safety aspects of the plant. Thus, factories located in areas that are exposed to unreliable 

power supply are obliged to have their captive power plants to ensure reliability of operation. 

Faced with the situation of deficient power supply, one such gas cracking complex in India 

decided to install a cogeneration plant to obtain reliable power at a reduced cost. 1 

2.2.1 Assessing the economic benefits of cogeneration 

A preliminary study was conducted to establish the economic merits of the cogeneration 

system in comparison with the existing situation where the conventional boilers supplied 

process steam and power was purchased from the utility grid. 

The power demand of the plant was of the order of 50 MW, and the total process steam 

requirement was found to be 93 tons/hour. For analyzing the cogeneration option, the power 

requirement was hiked to 65 MW, to include the provision for future expansion. The cost of 

having a contract demand of 17.6 MVA with the utility had to be considered for assuring 

continuous operation in case of the stoppage of the cogeneration plant. This would assure 

1 

A.K. Sood, “Commercial role of cogeneration in petrochemical industry”, Paper presented at the 

Cogeneration Asia ’97 Conference, AIC Conferences, Singapore, 25-26 November 1997.


undisturbed operation of several power consumers in the plant during any unexpected tripping 

by drawing power automatically as and when required up to the extent of 17.6 MVA. 

Considering longer outage of the cogeneration plant during major overhauls or during the 

recommended inspections, it was decided to include an additional captive power generation 

capacity of 20 MW to guarantee power supply without depending on the public utility grid. 

Similarly, to avoid the problem of steam shortage during the outage of heat recovery steam 

generators, an additional boiler was included as a spare unit. This would also take care of the 

start-up constraint of the gas cracker plant when greater amount of steam was required than 

during normal operating conditions. Lean gas was considered as the sole fuel for operating 

the cogeneration unit. The results of the economic analysis, considering the prevailing costs 

of equipment, fuel, O&M, manpower, etc., are summarized in Table 2.1. The cogeneration 

case has a clear edge over the existing case as it helps to reduce the energy bill by 36 per 

cent and improves the reliability of the production process. 

Table 2.1 Economic analysis of cogeneration in the gas cracker complex 

Existing Situation: 

Process steam from conventional boiler and power purchase from utility grid 

Description Annual Cost 

Investment: 

Boilers (2 x 136 tons/hour of steam) 

Operating & Maintenance Costs: 

(US$/year) 

3,780.00 

Electricity purchased from the grid (50 MW) 

40,832.00 

Fuel gas (6,626 tons/hour) 

4,529.00 

Other utilities 

2,479.00 

Maintenance & Chemicals 

315.00 

Manpower 

336.00 

Total Costs (existing situation) 

52,271.00 

Steam cost (US$/ton) 

15.37 

Power cost (US$/MWh) 

Cogeneration Case: 

102.08 

Power and heat from the cogeneration plant, minimum demand contract with utility grid 

Investment: 

Boilers (3 x 136 tons/hour of steam) 

Gas turbine generators (3 x 20.7 MW) 

Steam turbine generator (25 MW) 

Operating & Maintenance Costs: 

18,267.00 

Demand contract with the grid (17.6 MVA) 

754.00 

Fuel gas (15.148 tons/hour) 

10,355.00 

Other utilities 

1,862.00 

Maintenance & Chemicals 

1,720.00 

Manpower 

504.00 

Total Costs (cogeneration case) 

Steam cost (US$/ton) 

Power cost (US$/MWh) 

33,462.00 

12.30 

51.64


Annual cost with the existing case 

Annual cost with the cogeneration case 

Net annual saving 

Percentage annual saving 

Estimated Savings with the Cogeneration Case 

52,271.00 

33,462.00 

18,809.00 

36 per cent 

Based on the preliminary analysis, further optimization studies were conducted by 

considering nine different cases involving different capacities and numbers of major 

equipment. The most optimum scheme retained for actual implementation is shown in Figure 

2.1. It consists of 3 gas turbines (including one spare), each with an ISO rating of 25 MW; a 

double-extraction condensing steam turbine for producing medium and low pressure steam; 

and 3 heat recovery steam generators (including one spare), each with a capacity to generate 

136 ton of steam per hour at 105 Bar and 510°C. 

Air 

HSD/Gas 

Air 

HSD/Gas 

Air 

HSD/Gas 

SM 

SL 

G 

GT-1 

GT-2 

GT-3 

STG 

C 

G 

G 

G 

Atmosphere 

FD Fan 

Atmosphere 

FD Fan 

Air 

Atmosphere 

SVH 

To deaerator 

PRDS 

FD Fan 

Air 

PRDS 

SVH 

to process 

plant 

HRSG -1 

Gas/LSHS/HSD/PG 

HRSG-2 


HRSG-3 


PRDS 

Atmosphere 

SVH: 108 bar 

SH: 42 bar 

SM: 19 bar 

SL: 3.5 bar 

Figure 2.1 Cogeneration scheme implemented at the petrochemical complex 

SH


2.2.2 Details of the cogeneration system 

The gas turbines with an ISO rating of 25 MW are capable of producing 20.7 MW at the site. 

Since the gas supplier could not guarantee lean gas supply, dual fuel configuration (lean gas 

as well as high-speed diesel) was specified for the gas turbines. This was further altered to 

allow simultaneous firing of liquid and gas in such a manner that the gas gets a preference 

and the liquid fuel meets the balance requirement. 

A 25 MW capacity steam turbine generator was selected with the option for extracting 

medium pressure steam at 19 bar and low pressure steam at 3.5 bar. The condenser was 

designed for generating up to 20 MW of power without any steam extraction. The heat 

recovery steam generators (HRSG) have the option for auxiliary firing with multi-fuel option. 

High-speed diesel is used as a start-up fuel and the lean gas is supplied as the main fuel with 

low sulphur heavy stock as the alternate liquid fuel. By-products available from the gas 

cracking unit such as pyrolysis gasoline and off gas can also be fired. In order to allow the 

HRSG to operate as a conventional boiler when the associated gas turbine was not operating, 

a forced draft fan for supplying combustion air is installed with suitable dampers and safety 

protections so that the boiler can run without exhaust from the gas turbine. This change over 

scheme was well designed and tested and works satisfactorily at present. 

In order to maximize the heat extraction from the exhaust gases after economizer and to 

increase the overall efficiency of the HRSG, a separate low-pressure water coil was installed 

in exhaust gas path. Such an arrangement allowed to generate hot water which, when 

flashed, gives low-pressure steam that is used for deaeration of boiler feed water. This 

feature helps to reduce the steam demand for the deaerator by 4 ton/hour. 

2.3 Cogeneration in a Textile Mill 

Encouraged by the Thai Government policy on industrial cogeneration and sale of excess 

electricity to the utility grid, a synthetic fibre manufacturing industry decided to explore the 

opportunity for cogeneration. The factory was particularly susceptible to any unintended 

shutdown due to power interruption while led to high restarting costs. In addition, the factory 

had a generating capacity to meet only 15 per cent of its demand and the existing diesel 

generators were over 20 years old and were expensive to maintain. A techno-economic 

feasibility study was first undertaken to identify the best cogeneration scheme in line with the 

Government’s newly announced power buy-back option. 2 

2.3.1 Existing energy situation of the factory 

The production processes in the factory required steam at two different pressures, 56 bar and 

12 bar, respectively. The total demand of steam was 101,120 tons of steam per annum, 

giving an average of about 11.5 ton/hour, though the maximum and minimum demands were 

of the order of 17 and 9 tons/hour, respectively. To meet these demands, 4 boilers were 

employed with the following capacities: 

- two boilers producing steam at 60 bar, each with a generating capacity of 7 tons/hour, 

- two others operating at 12 bar and generating 15 tons of steam per hour each. 

Heavy fuel oil used as fuel in the boiler was purchased at a price of US$ 0.12/litre. 

2 P. Srisovanna, “Case study of cogeneration in textile sector”, ESCAP South-East Asia Sub-regional 

Seminar on Promotion of Energy Efficiency and Pollution Control through Cogeneration, Hanoi, 10-11 

November 1998.


The total electricity demand of the factory was 59,000 MWh/year, with an average demand of 

around 6.7 MW. The actual demand varied between a minimum of 5.9 MW and a maximum of 

8.9 MW. About 1 MW of electricity representing 15 per cent of the total demand was selfgenerated, 

using more than 20 years old diesel generators. 

Four alternatives were considered during the feasibility study and compared with the existing 

situation: (1) Back pressure steam turbine, (2) Gas turbine, (3) Combined cycle, (4) Diesel 

engine. In all cases, the criteria set was to meet the peak steam demand of the factory, i.e., 

17 tons/hour. 

2.3.2 Option 1: back pressure steam turbine 

The proposed option is schematically shown in Figure 2.2. This option was found to be not 

attractive due to the need for extracting steam at two different pressures. The varying demand 

of steam at these pressures will lead to quite unfavourable steam turbine operation. In steam 

matching option, the net output would be only 0.8 MW, which is less than the current standby 

needs. 

Moreover, the unavailability of a suitable standard turbine will lead to high installation cost and 

will be more difficult to operate in practice. Considering 40 per cent of custom duty and tax, 

the investment was calculated as US$ 7,500/kW. The annual maintenance cost was 

estimated as 3 per cent of the investment, i.e., US$ 180,000/year. 

130 c C, 12.73 t/h, (1.93 MW) 

Fuel 

10.6 MW 

Water: 70 o C 

11.5 t/h, 

(0.94 MW) 

Boiler 

η= 90% 

Figure 2.2 Steam turbine cogeneration option for the textile mill 

2.3.3 Option 2: gas turbine 

Steam: 100 bar/450 o C 

12.73 t/h (11.47 MW) 

Steam: 12 bar/237 o C 

1.23 t/h (0.99 MW) 

Electricity 

800 kW 

Steam to Process 

12 bar/237 o C 

6 t/h (4.84 MW) 

56 bar/380 o C 

5.5 t/h (4.79 MW) 

The schematic diagram of this option is shown in Figure 2.3. The system included a diesel 

fired gas turbine with heat recovery steam boiler and an option for auxiliary firing to meet the 

varying steam demands. A boiler bypass would allow the gas turbine to run at full load, and 

the auxiliary firing option with heavy fuel oil will let the boiler run at full load even when the gas 

turbine is shut down. The net output of the alternator would be 4.7 MW, and assuming a 90 

per cent availability factor, the cogeneration plant was capable of providing 58 per cent of the 

power needs of the factory, the rest being purchased from the utility grid. 

ST 

G


Air 

4700 kW 

G 

Fuel 

16.7 MW 

Figure 2.3 Gas turbine cogeneration option for the textile mill 

The investment, including the custom duty and tax, amounted to US$ 1,617/kW. The annual 

maintenance cost was taken as 2.5 per cent of the total investment, i.e., US$ 190,000. 

The main drawback of this option was the high price of diesel oil required in the gas turbine 

that led to a long payback period. The cost of diesel oil is US$ 0.19/litre as compared with 

US$ 0.12 /litre for heavy fuel oil. Moreover, the former has a lower heating value as compared 

with the latter (36 MJ/litre versus 39.1 MJ/litre). 

2.3.4 Option 3: combined cycle 

As can be seen in the schematic diagram of this option in Figure 2.4, this is a combination of 

the first two options. As a result, the combined power generation from the gas turbine and 

steam turbine reaches 6.8 MW. This allows the plant to be self-sufficient during 93 per cent of 

the year. The investment cost, including taxes, was computed as US$ 2,000/kW and the 

annual maintenance cost was taken as 2.5 per cent of the investment. 

As in the previous case, the main disadvantage of this system is the need for diesel as fuel, 

which has a much higher cost when compared with heavy fuel oil. 

2.3.5 Option 4: diesel engine 

Exhaust 

18.8 kg/s 

545 o C 

C T 

Water: 70 o C 

11.5 t/hr 

(0.94 MW) 

160 o C 

Supplementary 

Firing 

Fuel: 200 kW 

56 bar/271 º C 

5.5 t/h, 

(4.26 kW) 

12 bar/188 º C 

6 t/h, 

(4.64 kW) 

Steam 

56 bar/271º C 

1.05 t/h, 

(0.81 kW) 

Water 

120 º C 

12.55 t/h (1.76 kW) 

This configuration consists of a diesel engine with heat recovery steam boiler with auxiliary 

fuel firing option, as shown in Figure 2.5. The investment cost, including taxes, was estimated 

to be US$ 1,500/kW. This option provided the best economic result for the factory. Though the 

possibility of using 2 diesel engines for generating more power and selling to the utility grid 

was explored and led to higher economic returns, the factory management was interested in 

this alternative. 

H 

RS 

G


Air 

6000 kW 

G 

2 × 6350 

kW 

G 

C 

Fuel 

21.6 MW 

Exhaust 

36.2 kg/s 

456 o C 

GT 

Water: 70 o C 

11.5 t/hr 

(0.94 MW) 

Figure 2.4 Combined cycle option for the textile mill 

Fuel 

31.0 MW 

DIESEL 

ENGINE 

Cooling Water 

5.5 MW 

Exhaust 

450 o C 

Water 

70 o C 

11.5 t/hr 

(0.94 MW) 

HRSG 

Water 

120 º C 

12.5 t/h 

(1.75 kW) 

170 o C 

HRSG 

100 bar/450 º C 

12.5 t/h (11.26 kW) 

Figure 2.5 Diesel engine cogeneration option for the textile mill 

o C 

12 bar/237 

800 kW 

G 

Steam to 

Process 

12 bar/237 º C 

6 t/h (4.84 kW) 

56 bar/380 º C 

5.5 t/h (4.79 kW) 

1.0 t/h (0.81 MW) ST G 

56 bar/271º C 

5.5 t/h, 

(4.26 kW) 

Air Cooler To Process 

Water: 110 o C 

11.5 t/hr 

(1.47 MW) 

12 bar/188 º C 

6 t/h, 

(4.64 kW) 

Steam 

56 bar/271º C 

0.43 t/h, 

(0.34 kW) 

Water 

130 º C 

11.93 t/h (1.81 kW)


2.3.6 Comparison of the different options 

Table 2.2 summarizes the results of the analysis of the 4 options considered. As it can be 

seen from the payback periods calculated, the diesel engine option has a clear edge over the 

others. The results could however have been quite different had natural gas been available at 

the site at a reasonable price. 

Table 2.2 Comparison of the cogeneration options retained for the textile mill 

Alt. Technical Power Percentage Investment + 40 Main Payback 

Option Output Demand Met Per Cent Taxes Fuel Period 

(MW) ( per cent) (10 6 US$) (Year) 

1 Steam turbine 0.8 10 6.0 HFO 20 

2 Gas turbine 4.7 60 7.6 Diesel 20 

3 Combined cycle 6.8 80 13.6 Diesel 20 

4A Diesel engine 12.7 160 12.6 HFO 6 

4B Diesel engine 8.7 120 10.4 HFO 6 

4C Diesel engine 6.4 80 

9.6 HFO 6 

On the basis of the analysis and in order to minimize the investment, the factory decided to 

purchase a new diesel generator of 5 MW capacity and operate it along with the existing 

generator to meet all the low-pressure steam demand of the factory. The existing highpressure 

boiler met the demand for high-pressure steam. 

2.4 Cogeneration in a Paper Mill 3 

Cogeneration is widely used in paper mills around the world. Steam generated is used at 

different pressures and temperatures for cooking of chips in digesters in the pulping process 

and for drying of paper in paper machines. In addition, some amount of steam is used for 

concentration of black liquor in multiple effect evaporators. 

A small paper mill in India with an installed capacity to produce 60 tons of writing, printing and 

duplex quality paper per day, uses agro-industrial residue based cogeneration to meet all the 

process energy requirements. Waste paper is mainly used as the raw material and a small 

quantity of pulp is produced from bagasse, the residue from the cane sugar mills. 

2.4.1 Existing energy supply facility 

Steam demand of about 7 tons/hour at 4 bar is met by two boilers, each with a capacity to 

produce 6-7 tons of steam per hour, using coffee and rice husk as fuel. The utility grid met 

electricity demand of about 2,500 kVA. During power interruptions, a stand-by diesel generator 

set with an installed capacity of 1,525 kVA was used to take care of the essential power 

needs. 

Frequent power cuts, lasting for as much as 25-30 per cent of the year, forced the factory 

management to look for an alternative economic source of power than the stand-by diesel 

generator. Coinciding with the plan to increase the production capacity to 100 tons of paper 

per day, a study was conducted to assess the viability of cogeneration. With the expansion 

plan of the factory, the process steam demand was estimated as 13 tons/hour and the power 

demand was expected to increase to 2,700 kW. 

3 M.M. Patel and P. R. Raheja, “Case study presentation on cogen project and benefits at South India 

Paper Mills”, paper presented at the CII Energy Summit ’96, Chennai, 11-14 September 1996.


2.4.2 Economic evaluation of cogeneration options 

Four different options were considered for comparing with the present case, as follows: 

1. Use of low pressure boilers for process steam only , and no power generation on site; 

2. Use of a high pressure boiler and a back pressure turbine to meet 30-40 per cent of the 

power demand; 

3. Use of a high pressure boiler of a higher capacity, a back pressure turbine and an 

additional condensing turbine, or a single extraction-condensing turbine to meet 60-70 per 

cent of the power demand; 

4. The same as (2), but all the power needs of the factory are met in this option. 

2.4.3 No power generation 

To meet the increased steam demand of digesters and for availing stand-by capacity, it was 

proposed in this case to replace an old boiler by a new fluidized bed combustion boiler having 

a capacity to produce 10 tons of dry saturated steam per hour at 10.5 bar. Entire power 

requirement was to be met by the purchase of power from the utility grid, the diesel generator 

continuing to provide the back up in case of power outages. 

2.4.4 30-40 per cent power generation 

The erratic power supply of the utility makes it absolutely necessary to have at least a 

capacity to self-generate 30-40 per cent of the power need (600-700 kW) to avoid production 

losses. Though a diesel generator is available, the power generated from this unit is quite 

expensive and the maintenance cost of this unit is expected to mount with time. 

As there was a need to acquire a new boiler, this option considered the option of generating 

steam at 42 bar and 440°C. The steam could be supplied to a back pressure turbine to 

generate around 30-40 per cent of the power demand of the factory, and the steam leaving 

the turbine at a pressure of 4 Bar can be sent to fulfil process heating needs. 

The initial investment as well as the operating cost of this system was found to be lower than 

a diesel engine. The fuel used in the boiler is cheap and available in abundance. Moreover, 

only the incremental cost of fuel required generating the same quantity of steam at higher 

pressure and temperature was considered, which is only 20 per cent higher. The cost of 

power generation worked out to be 36 per cent lower than that with the diesel generator. 

From the practical side, a smaller size would mean the use of inefficient single stage turbine 

and low voltage generator. This may lead to large imbalance in the system due to variations in 

the process steam and power demands. The system balance can be achieved only by 

operating the system at low plant load factor, thereby compromising the overall efficiency and 

productivity of the factory. 

2.4.5 60-70 per cent of power generation 

At this level of power generation, higher productivity can be guaranteed with practically no 

production losses. Installation of a higher capacity (14 tons/hour) and higher pressure (42 bar 

and 445°C) boiler was considered. As much as 6-7 tons/hour of steam could be used in the 

back pressure turbine and match the process steam demand. The remaining high-pressure 

steam can be sent to a condensing turbine for additional power generation. The latter will also 

assure to absorb the fluctuations in the process steam demand, without affecting the power 

output adversely. Further, the use of a single multistage backpressure cum condensing 

turbine will assure increased power output and higher system efficiency.


Though the initial investment becomes higher due to the higher boiler capacity and larger 

turbine and generator, condenser, etc., it can be justified by the higher efficiency and plant 

load factor. Moreover, the cost of additional fuel will be marginal. The power generated would 

be adequate to handle all the critical loads whereas the non-critical loads can draw power 

from the grid. Thus the plant productivity will no longer be affected by the utility power outages. 

2.4.6 Full power generation 

As there was a need to include installation and management of the fuel and ash handling 

system, cooling water circuit for the condenser, and power interfacing and distribution, one 

more alternative was included to further increase the boiler and turbine capacities to meet all 

the heat and power needs of the factory. Though the investment required was higher, power 

generation cost became much lower compared with that of the utility or the diesel generator, 

mainly due to the low fuel cost. In addition, the option to avail full depreciation of the 

investment in the first year made the economic viability of the project particularly attractive. 

Hence the factory management retained this last option. The details of the economic 

calculations for this alternative are summarized in Table 2.3. 

Table 2.3 Technical and economic parameters of the cogeneration facility 

Description Units Values 

Power plant capacity 

Cogeneration plant power consumption 

Net power output for the factory 

Working hours 

Plant load factor 

Annual electricity generation 

Annual fuel (rice husk) consumption 

Annual fuel use for process steam 

Annual net fuel supply for cogeneration alone 

Investment on the cogeneration facility 

Cost of electrical modernization 

Price of electricity purchased 

Avoided cost of electricity generated 

Cost of fuel 

Cost of fuel for cogeneration 

Operation and maintenance costs 

Annual cost saving 

Gross payback period 

kW 

kW 

kW 

Hours/year 

per cent per annum 

10 6 kWh 

tons/year 

tons/year 

tons/year 

10 3 US$ 

10 3 US$ 

US¢/kWh 

10 3 US$/year 

US$/ton 

10 3 US$/year 

10 3 US$/year 

10 3 US$/year 

Year 

2,000.00 

350.00 

1,650.00 

8,760.00 

0.80 

11.56 

30,000.00 

12,000.00 

18,000.00 

2,000.00 

286.00 

9.43 

1,090.00 

22.86 

411.00 

114.00 

565.00 

4.00 

It is expected that when the mill capacity is increased to 100 tons/day of paper, the same 

cogeneration plant will operate with 20 tons/hour of inlet steam to provide 12-13 tons of 

process steam per hour at 4 bar and generate around 2,700 kW of power. 

A desuperheater was added near the paper machine to reduce about 100°C of superheat of 

the process steam extracted from the turbine. Compared with the earlier process line 

pressure of 7-8 bar, the present system operates at 5 bar pressure, thus the steam 

consumption is reduced and the power output from the turbo-generator is increased per ton of 

steam. In order to extract the maximum benefit from the cogeneration system and to make


the system more flexible and cost effective, the turbo-generator is run in parallel with the utility 

grid. 

2.5 Cogeneration in a Palm Oil Mill 

The palm oil industry is one of the major energy consumers of energy. This industry also 

generates vast amount of biomass such as mesocarp fibre, shell, empty bunches, fronds, 

trunks and palm oil mill effluent, which can be used as the main source of fuel for 

cogeneration with a capability to meet all the electricity needs of the factory. A crude oil and 

palm kernel producing plant in Malaysia decided to install a cogeneration plant to meet all its 

energy requirements, thus improving the efficiency, competitiveness, reliability, flexibility and 

ease of operation. 4 

2.5.1 Production process of the factory 

The ripe palm fruit bunches are subjected to steam-heat treatment for a period between 75 to 

90 minutes in a horizontal sterilizer where saturated steam at 3 bar and 140°C is used as the 

heat medium. These are then fed to a rotary drum stripper to separate the fruits from the 

bunches and the fruits are sent to a digester. Digestion involves mashing of fruits under 

steam heated conditions using direct live steam injection. Twin screw presses are used to 

press out the crude oil from the digested mash under high pressure. 

The crude palm oil consisting of a mixture of palm oil (35-45 per cent), water (45-55 per cent) 

and fibrous materials is sent to clarification tank which is maintained at about 90°C to 

enhance oil separation. The skimmed clarified oil is then passed through a high-speed 

centrifuge and vacuum dryer. With the introduction of a cogeneration plant, excess thermal 

energy and electricity are used in a kernel crushing plant. Both palm oil and palm kernel oil are 

sold to palm oil refineries and oleochemical factories for further processing. 

During steady plant operation, almost 5 tons/hour of palm shell was available with two 

different moisture contents, 8.3 per cent and 16 per cent respectively. Likewise, 11.55 

tons/hour of palm fibre was discarded with two different moisture contents, 19.25 per cent 

and 30 per cent respectively. These residues were previously burned off in oversized and 

inefficient boilers in order to overcome the waste disposal problem. 

2.5.2 Technology adopted for cogeneration 

The cogeneration system adopted to reduce the overall energy bill by simultaneous 

generation of heat and power. A backpressure steam turbine system was adopted as the 

simplest configuration for achieving the highest efficiency and maximum economy. 

A water tube boiler is installed with a capacity to generate 35 tons of steam at 23 bar. The fuel 

supply and combustion rate is controlled as a function of the airflow rate, by manual or 

automatic adjustment of the fuel conveyor. Steam from the boiler is passed through a back 

pressure turbine to generate 1,200 kW of electricity, meeting all the electricity needs of the 

factory as well as the worker’s residential quarters. The steam leaving at 3 Bar is used as the 

process heat for sterilizer, digester, crude oil tank, clarification, oil storage tank, kernel dryers 

and other applications (see Figure 2.6). 

4 L. Low, “Investing in cogeneration for efficiency, competitiveness, reliability and ease of operation at 

Kilang Sawit United Bell”, Paper presented at the Cogeneration Asia ’97 Conference, AIC Conferences, 

Singapore, 25-26 November 1997.


P. Shell 

P. Fiber 

Hot Water 

for Boiler 

BOILER 

Sterilizer Digester 

350 psig 

Crude Oil 

Tank 

Turbine #1 

Turbine #2 

(Future) 

Back to Pressure 

Receiver Distributor 

Figure 2.6 Steam turbine cogeneration in the palm oil mill 

The total investment cost of the cogeneration plant amounted to US$ 523,000 and the annual 

cost savings expected from the self-generated electricity is estimated as US$ 243,700. The 

factory expects to recover the investment within 3 years after the commissioning of the 

cogeneration plant. 

Encouraged by the results, the company plans to achieve a ‘zero waste’ level in the factory. 

There is a plan to fully exploit the excess energy by generating up to 2.5 MW of electricity and 

integrating the operation of downstream activities such as the kernel crushing plant and 

medium density fibreboard project. 

2.6 Cogeneration in an Industrial Estate 

Clarification 

(Oil Room) 

Exhaust: 45 psig (3 bar) 

1,200 kW 

Power Supply to Mill 

Supply to other 

integrated activities to 

harness excess energy 

Oil Storage 

Tank 

Kernel 

Dryer 

The Thai Government policy of initiating and decentralizing economic development has led to 

the successful creation of several industrial complexes away from the capital. These 

industrial complexes require considerable amount of reliable power and process steam. Many 

industries inside these complexes are excellent customers of large-sized cogeneration 

plants. One such 300 MW gas-fired cogeneration power plant was launched in Map Ta Phut 

Industrial Estate as early as in 1994. 5 

5 Y. Le Scraigne, “The first IPP project developed in Thailand – The Map Ta Phut cogeneration plant”, 

Paper presented at the 1994 Cogeneration Conference, AIC Conferences, Bangkok, 20-21 June 1994.


2.6.1 Description of the cogeneration project 

The cogeneration project was developed in two identical phases. Taking the environmental 

concerns into consideration, natural gas-fired combined cycle cogeneration option was 

retained which minimizes the level of exhaust emissions and reduces the cooling water 

requirement by half in comparison with a conventional power plant. Each phase included 3 

gas turbines (35 MW each), a heat recovery steam generator (HRSG) to recover heat from 

the flue gases of the gas turbines, a steam turbine of 50 MW capacity, and the auxiliary 

equipment necessary to produce and distribute the generated electricity and steam to 

industrial customers and the utility grid (see Figure 2.7 for details). In each phase, 150 MW of 

electricity and 145 tons/hour of process steam were generated at two different pressures 

required by the industries: 60 tons/hour at 52 bar and 425°C, and 85 tons/hour at 19 bar 250° 

C. The high pressure steam is taken directly from the boiler. The medium pressure steam is 

bled off the steam turbine, with a back up provided by the high pressure steam supply through 

a turbine by-pass fully equipped with a pressure reducing and desuperheating station. 

Fuel: 100% 

11.7%: 3×15.1 MW 

88.3%: 3×114.6 MW 

Air 

Comb. 

C T 

61 

.3 

% 

238.7 

MW 

G 

Electricity 

64.2% 

3 ×83.5 MW 

27%: 3×35 MW 12.3%: 47.8 MW 

Stack 

8.8%, 34.3 MW 

HP Steam: 

6.8%: 26.3 MW 

MP Steam: 

13.9%: 53.8 MW 

Cooling Water 

31.2%%: 121.4 MW 

Figure 2.7 Combined cycle cogeneration (Phase 1) at the Industrial Estate 

The cogeneration plant assures electricity, steam and demineralized water supply to several 

petrochemical and downstream industries. Customers have signed long-term contracts to 

take or pay for a minimum off-take quantity of steam. The steam price has three components: 

capacity, energy and transportation. Steam is supplied to the customers with an availability 

guarantee. A part of the electricity generated is sold to the customers whose price has 

capacity and energy components, the remaining amount is sold to the utility grid according to 

the tariff set for small power producers. 

H 

R 

S 

G 

Water


Natural gas is used as the main fuel for which a long-term agreement has been signed with 

the Petroleum Authority of Thailand. Distillate oil can be used as a back-up fuel. 

In line with the incentive policies of the Board of Investment, certain privileges were granted to 

this project, such as: 

- import duty exemption or reduction on imported machinery; 

- corporate income tax exemption for 8 years, and further reduction of 50 per cent for 5 

more years; 

- double deduction from taxable income of electricity, water and transport costs for 10 years 

from the date of first sales; 

- deduction from net profit of the costs of installation or construction of the project’s 

infrastructure facilities; 

- exemption of personal income tax on dividends to shareholders. 

2.6.2 Choice of the cogeneration plant 

The choice of technology is primarily based on the consideration that both steam and 

electricity can be supplied with high efficiency and reliability. During the plant operation, there 

is practically no SOx emission and the NOx level is reduced to 50 ppm (with 15 per cent O2) 

with steam injection. 

The major advantages of this configuration are: 

- low capital cost: approximately three-fourth that of a conventional power plant of the same 

output; 

- short gestation period: two-third of the power available with gas turbines within 12 to 15 

months, and remaining one-third is available with steam turbine within 18 to 20 months; 

- low operating and maintenance costs; competitive operating costs and higher availability, 

particularly in comparison with coal fired thermal steam power plants; 

- higher efficiency: electrical efficiency of 45.14 per cent in combined cycle mode, and 

global efficiency of almost 70 per cent in cogeneration mode; 

- flexibility of operation: ensured by the modularity of the plant, gas turbine exhaust by-pass, 

steam turbine by-pass system, and the option of auxiliary firing on HRSG which allows 

some decoupling between power and steam generation. 

The gas turbines are installed outdoor. The unit is capable of being operated at full load within 

16 minutes. Each unit consists of the following components: 

- air inlet module with filter, silencer and ducts; 

- gas turbine and auxiliary equipment package; 

- generator package with load gear, exciter and coolers; 

- exhaust module with ducts, bypass stacks, silencer and expansion joints; 

- control components with option for local operation; 

- medium voltage compartment with circuit breakers and auxiliary transformers.


The gas turbine consists of a 17-stage compressor, combustion system with 10 individual 

combustors, a 3-stage turbine, air systems, lube oil system common to gas turbine and 

generator, cooling water, and fuel systems. It is equipped with a steam injection skid for NOx 

emission, acoustical enclosure for noise reduction, silencing equipment on inlet and exhaust 

ducts, and a CO2 fire protection system. 

The HRSG is of simple and proven design. It has a low thermal inertia to allow fast start-up 

and rapid load swings, high resistance to thermal shocks, low exhaust gas pressure drop, 

high heat recovery, and high reliability and maintainability. 

2.6.3 Financing of the project 

Most of the difficulties encountered in financing large-scale power projects are avoided as the 

project is of a reasonable size. The financeability of the project is enhanced by the 

commitment and references of the project sponsors as well as the quality of the customers. 

The project sponsors have large experience in energy projects. The industrial clients are 

mostly very much capital intensive and are able to take long term off-take commitments. 

The electric utility plays an important role by purchasing surplus electricity, thus providing 

stable and additional revenue to the project. Also, back-up electricity is provided from the grid, 

ensuring that availability targets of the industrial users can be achieved. 

The Government has demonstrated a clear policy for privatization of power generation along 

with accompanying regulations and incentives. 

The equipment suppliers provided necessary confidence and guarantees to the lenders and 

guarantors on the following: 

- project investment cost control, by accepting the construction of the plant for a fixed and 

firm price; 

- completion on time, by accepting liquidated damages, for failures to meet targeted 

completion date; 

- plant performance in terms of availability and reliability, by accepting liquidated damages 

for failure to meet targeted figures. 

In addition, there was the advantage of reduced interest during construction due to 

progressive investment and short gestation time, and the ability to generate income after only 

a year of signing the contract when the plant started operating in open cycle. 

The debt-equity ratio of the project was 3:1. During the financing arrangement, maximum 

flexibility in the choice of currency and the type of interest rates were offered to the 

developers. The subsidized loan included a 10-year loan term from the commissioning date of 

the project. Local financing could be made available to cover other investment costs.

Cogeneration experiences around the world 83 

CHAPTER 3: COGENERATION EXPERIENCES AROUND THE WORLD 


There is no standard procedure or method to gather reliable and up-to-date data on 

cogeneration-based power generation and installed capacity in each country on a basis 

comparable with the others. There is yet to be a commonly agreed definition and an 

assessment of the quality of cogeneration in terms of its energy efficiency and environmental 

benefits. 

Based on data available in literature, north European countries are presently the leaders in the 

field of cogeneration, having between 30 to 40 per cent of their power generating capacities as 

cogeneration. In the case of the European Union of 15 countries, cogeneration represented 13 

per cent of the total gross installed power generating capacity and 9 per cent of the total gross 

electricity generation in 1994. However, countries like Denmark, Finland and the Netherlands 

far exceed the others. 

Next in line are the central European countries and China, which have an average of 10 to 15 

per cent. The United States has less than 10 per cent of electricity coming from cogeneration 

whereas the figure for Australia is just over five per cent. Worldwide trends indicate that a 

significant increase in cogeneration is likely to occur over the next 20 years. 

There is a general consensus that the importance of cogeneration technology is linked with its 

potential for rendering higher energy efficiency, more stable energy supply, and reduced 

environmental impact. Even in countries where the power sector is mature and the demand 

for electricity has stabilized, options are being explored to deal with the seasonal variations in 

electricity demands with an expansion of decentralized electricity generation, where small and 

medium scale cogeneration will find a niche market. 

In many industrialized countries, cogeneration is playing an increasingly important role in 

industry and in the residential and service sector. It is being perceived not as a competitor to 

the conventional power generation system, but as an advanced technology that can be 

applied to hospitals, hotels, shops and offices. Another area where cogeneration has become 

popular is the district heating network, and more recently district cooling in tropical climates. 

This section briefly describes cogeneration experiences of selected countries around the 

world, focussing mainly on the United State of America and Europe where cogeneration is 

better organized and data for most countries are more easily accessible. 1 

3.2 United States of America 

The United States of America has been widely recognized as the first country for having set 

up policy for promoting cogeneration. The Public Utility Regulatory Policies Act of 1978 

("PURPA") was signed into law in November 1978. Enacted as part of a package of legislation 

to combat the "energy crisis," and the perceived shortage of natural gas, PURPA's primary 

purposes were to promote conservation (through cogeneration of both steam and electricity) 

and to encourage greater use of alternative sources of power generation. In order to 

accomplish these objectives, PURPA established a class of non-utility generators comprised 

of small power producers and cogenerators. 

1 Much of the information in this section was gathered from a number of websites.


PURPA requires electric utilities to offer to sell electric energy to qualifying cogeneration 

facilities and qualifying small power production facilities, and purchase electricity from such 

facilities. Importantly, PURPA was intended to accomplish its objectives while protecting 

consumers from having to pay more for power from cogenerators than they would pay for 

power produced or purchased by the utility. The benefits enjoyed by a cogeneration facility 

under PURPA are significant. These are: 

1. Advantageous buy-back rate treatment for sales of cogenerated electricity: Utilities may 

negotiate to pay up to their avoided costs to purchase cogenerated power; 

2. Ease of interconnection and backup service: Expensive equipment redundancy for 

reliability is no longer required. However, cogeneration systems are still required to meet 

the utility’s safety and protection conditions while interconnected to the grids; 

3. Supplemental Utility backup power at reasonable rates: Utilities cannot discriminate 

against cogenerators by charging unreasonably high rates for supplemental power; 

4. Exemption from federal and state utility regulations: Qualifying cogeneration facilities are 

exempt from public utility regulations. The expense of reporting and the compliance 

burden associated with the Federal Energy Regulatory Commission (FERC) and state 

utility commissions can be avoided. 

Besides the benefits mentioned above, other favourable regulations intended to ease 

administrative burdens for cogenerators to seek exemptions and to eliminate fuel use 

restrictions for industrial cogenerators are mentioned below. 

Exemption from Fuel Use Act for Using Oil and Natural Gas: Fuel Use Act (FUA) of 1978 

prohibits the use of oil and natural gas in existing power plants and major fuel burning 

installations if the facilities have or could have the capability of burning coal or another 

alternative fuel. New power plants and major fuel burning installations with boilers cannot be 

built without the capability of using coal or another alternative fuel. A new or existing 

cogenerator has to obtain an exemption from the Economic Regulatory Administration for 

using oil and natural gas. 

Exemption from Natural Gas Incremental Pricing: The Natural Gas Policy Act of 1978 

(NGPA) requires all incremental cost increases incurred as a result of the phased 

deregulation of natural gas well-head prices to be passed to customers who burn natural gas 

in non-exempt industrial boilers and other non-exempt industrial facilities defined by the 

FERC. NGPA authorizes the FERC to exempt cogenerators from incremental pricing. 

Energy Tax Credits: Energy tax credits were established for various qualified cogeneration 

components by two energy laws, the Energy Tax Act (ETA) of 1978 and the Crude Oil 

Windfall Profits Tax Act (COWPTA) of 1980. 

Cogeneration equipment investments are not specifically addressed in the ETA. However, 

certain components used in the cogeneration system such as waste heat boilers, preheaters, 

economizers, etc., can qualify for a 10 per cent energy tax credit in addition to the regular 10 

per cent investment tax credit. 

Between January 1, 1980 and December 31, 1982, the COWPTA provided a 10 per cent, 

non-refundable energy credit for qualified investments in cogeneration equipment that have a 

five-year or longer operating life and a 6 per cent credit for qualifying cogeneration facilities 

that have a three to five-year life. 

Tax-Exempt Financing: State and local power authorities and other government-owned 

electric utilities may issue tax-exempt bonds (exempt from federal income tax) and use the 

proceeds of the bond to finance the construction of cogeneration systems. However, if an


industrial company of an investor-owned utility plans to construct a cogeneration facility or if a 

government-owned utility plans to construct such a facility and sell more than 25 per cent of 

its output under a long-term contract to a private user, the facility will generally not be eligible 

for tax-exempt financing. 

According to the most recent data available, at the end of 1996, wind turbines, solar and 

geothermal units together accounted for 4.9 per cent of all installed non-utility generation 

capacity. Biomass comprised another 15.1 per cent. On the other hand, natural gas, coal and 

oil make up for over two-thirds, or 68.8 per cent, of the installed non-utility generating capacity. 

3.2.1 Renewed interest in cogeneration 

Cogeneration is now used extensively by several energy-intensive industries, including pulp 

and paper, chemicals, and petroleum refining. Following are the developments that have 

renewed interests of both government and industry in expanding cogeneration applications to 

other industries as well as other sectors of the economy: 

- Recent advances in technologies such as combustion engines, steam turbines, 

reciprocating engines, fuel cells, and heat-recovery equipment have decreased the cost 

and improved the performance of cogeneration systems; 

- A significant fraction of the country’s boilers will be replaced in the next decade, which will 

provide opportunity to upgrade them with clean and efficient cogeneration systems; 

- Environmental policies related to abatement of greenhouse gas emissions have created 

pressures to find cleaner and more efficient means of energy use; 

- The restructuring of the electric power market provides new opportunities for innovations 

in power generation and smaller-scale distributed systems such as cogeneration. 

Although the technical performance and costs of cogeneration systems have improved, there 

are significant barriers to their widespread use, which include the following: 

- Environmental Policies: Environmental permission for cogeneration systems remains 

complex, costly, time-consuming, and confusing. Air pollution permits are required from 

state environmental authorities before the plant can be constructed. Current environmental 

regulations do not recognize the overall energy efficiency of cogeneration, or credit the 

emissions avoided from displaced electricity generation; 

- Utility Policies: Many utilities currently charge backup rates and require complex 

interconnection arrangements for cogeneration systems; 

- Tax Policies: Depreciation schedules for cogeneration investments vary depending on 

system ownership. The depreciation period can be as long as 39 years for some types of 

owners, much longer than the depreciation period for utility-owned power plants. This 

limits the use of alternative financing or ownership arrangements. 

The Department of Energy (DOE) is attempting to raise awareness of the energy, 

environmental, and economic benefits of cogeneration, and to promote innovative thinking 

about ways to accelerate its propagation. Key participants in this challenge will be the state 

and regional officials. One target is to expand the use of this technology in government 

facilities by working with the Federal Energy Management Programme (FEMP) and facilities 

management agencies. 

DOE is undertaking its efforts in co-ordination with the United States of Environmental 

Protection Agency, which is focusing on environmental permit issues such as application of 

output based emissions standards to CHP systems, and the inclusion of cogeneration as a 

strategy in State Implementation Plans for the Clean Air Act.


3.3 Denmark – One of the European Leaders in Cogeneration 

Being more than 90 per cent dependent on imported oil, Denmark was vulnerable to oil price 

escalations as a consequence of the first oil shock. Danish Energy Policy 1976 focused on oil 

substitution and security of energy supply. Power plants switched from oil to coal and targets 

were set to increase the growth in cogeneration to meet the heat demands from 8 per cent in 

1976 to 25 per cent by 1995. This was achieved mainly due to the supply of natural gas from 

the North Sea. 

The Electricity Supply Act 1976 gave sufficient authority to the government to intervene in the 

planning and operation of the power sector, such as selection of technology, including 

cogeneration, and placing the power plant near heat loads. The power utilities were obliged to 

accept the deliveries of cogenerated electricity at high buy-back rates, 10 to 15 per cent lower 

than the utility tariff charged to large consumers. The Heat Supply Act 1979 was aimed at 

adopting the most appropriate space heating and hot water supply systems, and municipal 

authorities gained the right to make the connection to district heating systems mandatory. 

By the mid 80s, cogeneration was widely used in large towns and fresh initiatives were taken 

in 1986 to develop around 450 MW of small scale cogeneration programmes in about 300 

small towns with the power utilities playing a major role. In 1988, guidelines were issued by 

the Ministry of Energy, which required all municipalities to ban the use of electric heating in 

new buildings in areas having collective heat supply facilities. The Heat Supply Act was 

revised in 1990, which obliged all municipalities to ensure that cogeneration schemes are 

approved and that local heat markets are created. 

In 1990, ‘Energy 2000 - a plan of action for sustainable development’ was initiated with an 

ambitious emissions target and in which cogeneration development was emphasized. All new 

power generating capacities planned up to 1995 were to be in the form of conversion of 

existing districting heating systems to small-scale cogeneration systems fuelled by gas, 

waste or biofuels. This plan also initiated the substitution of coal with gas in large-scale 

cogeneration facilities for which 15-25 per cent grants were available. 

Energy taxes were introduced in the late 70s to keep power prices at a consistently high level 

and taxes were adjusted to maintain the prices charged to consumers constant. But the 

accompanying legislation ensured the competitiveness of cogeneration projects in relation to 

individual oil firing. Following the introduction of legislation in December 1991 to limit CO2 

emissions, a subsidy was introduced for small-scale cogeneration plants that deliver 

electricity to the grid (0.1 DKr/kWh for cogeneration based on gas and 0.17 DKr/kWh for 

cogeneration based on biomass). 

The Danish industries have done little in the past to meet their own energy needs. Thus only 

about 150 MWe of industrial cogeneration is in operation today. With the introduction of energy 

tax for industry and the availability of grants and subsidies, about 450 MWe of economic 

cogeneration potential have been identified. 

In 1993, utility generation accounted for 29,782 GWh of electricity and 19,546 GWh of heat. 

The energy efficiency of conversion was 58 per cent that would have been 40.3 per cent 

without cogeneration. Non utility cogeneration accounted for only 607 GWh of production. On 

the whole, over 10 per cent of fuel are saved through cogeneration in Denmark. This figure is 

a little low because of the low load factor, i.e. cogeneration plants often operate in noncogeneration 

mode due to the low heat demands. Heat from cogeneration plants accounted 

for 64 per cent of the total heat supply to district heating network, and almost half of this was 

for space heating alone.


By 2005, district heating is expected to account for 60 per cent of the total heat demand (47 

per cent in 1990) and 90 per cent of this demand (55 per cent in 1990) would be met by 

cogeneration. This achievement is only possible with a very conducive policy framework set 

by the national authorities, active involvement of the utilities and a combination of legislation, 

grants and subsidies, tariffs and tax incentives. This could not have become a reality if left 

purely to the market initiatives because of the major capital investments necessary for the 

development of large cogeneration and district heating networks. 

3.4 Cogeneration Development in France 2 

The long-term energy policy adopted by France following the first oil shock has resulted in a 

successful nuclear power generation programme to the extent that the generation capacity 

exceeds the demand in France and the electricity prices are among the lowest in Europe. The 

role of cogeneration has thus been marginal up to the 80s. In 1995, cogeneration represented 

only around 1.4 per cent of the total power production in France. According to the study done 

by Ceren in 1996 for the Ministry of Industry, the total installed cogeneration capacity at the 

end of 1995 was 3,200 MW. The production for 1995 was around 9 TWh of electricity and 34 

TWh of thermal energy. Steam turbines dominated with a share of 75 per cent, followed by 

gas turbines (19 per cent) and internal combustion engines (6 per cent). 

The Ministry of Industry had forecasted this figure to rise to 5 GW by the year 2005. However, 

recent policy and tariff changes have favoured much rapid development of cogeneration, 

proven by the fact that in 1997 alone, the installed capacity had doubled the figure of 1996, 

attaining 500 MW. If a few of the planned big projects are actually implemented, the figure 

could easily surpass 1,000 MW in 1998. 

3.4.1 Cogeneration in the past and at present 

By the French law of 1946 which nationalized the electricity sector, only small individual 

producers were allowed to generate up to 8 MVA of power which the public power utility, 

Electricité de France (EdF), was obliged to purchase. The key factor was the purchase price 

of electricity, which was perceived by potential developers as too low to encourage 

cogeneration projects, as the payback periods were too long. There were limited periods in 

the year (during winter season) when the price of electricity was 10 to 20 times higher than 

the off-peak periods. It was during this period that the industrial users found it attractive to set 

up cogeneration facilities. However, cogeneration plants are economical if they are allowed to 

operate for at least 4,000 hours per year, even in the industrial sector. Moreover, small-scale 

plants were prone to periodic scheduled maintenance and unscheduled failures, during these 

periods the user had to depend on EdF that applied high stand-by charges. 

In 1993, in order to better control and encourage electricity production from cogeneration, EdF 

established a buy-back rate linking a fixed bonus to the selling price of electricity. Electricity 

generation then became lucrative and some enterprises installed power plants using 

reciprocating engines. Their objective was to produce electricity up to the level of 8 MVA 

during winter months when the purchase price of electricity is the highest. The low efficiency 

of these power plants (35 per cent) resulted in the generation of electricity, which was 

economically attractive but with poor performance and high pollution. 

To deal with such a situation, the decree of December 1994 lifted the obligation imposed on 

EdF to purchase all electricity produced in France (the decree of May 1955), except in cases 

where electricity is obtained from renewables (solar, wind), incineration of industrial or urban 

wastes, and from cogeneration systems having an efficiency above 65 per cent. 

2 B. Mohanty, “French experience in cogeneration development”, Presented at Korea-French Seminar 

on Advanced Technologies for Electricity Production, Seoul, 27-28 October 1998.


The attitudes of the government and the power utility have changed slowly over the years. 

New ‘decrees’ were announced in favour of cogeneration by the national authorities in the 

beginning of 1995. The national gas company, Gaz de France (GdF) is also promoting 

development of cogeneration using natural gas through information dissemination, technical 

and economic appraisal, financing arrangements, maintenance and advisory services. There 

has been a very rapid evolution of natural gas use in new cogeneration installations in the 

recent years, as can be seen in Figure 3.1. 

Installed Capacity (MW) 

600 

500 

400 

300 

200 

100 

0 

Building 

Heating Network 

Industry 

91 92 93 94 95 96 97 

Figure 3.1 Statistics of cogeneration with natural gas as fuel 

The sudden hike in installed capacity between 1996 and 1997 is the result of the new policy, 

removing barrier on the limit of electricity sale to the grid. In 1995 and 1996, most units had a 

size ranging between 1 and 8 MW whereas much bigger installations were commissioned in 

1997, mostly in industries. There were altogether 84 installations ordered in 1997, 22 using 

turbines and 62 using combustion engines. The total installed capacity for gas turbines was 

450 MW whereas for engines, it amounted to 132 MW only. 

Recent policies regarding financial assistance for cogeneration include tax holiday on natural 

gas for 5 years, reduced tax on investment costs, 50 per cent reduction in professional tax, 

etc. For facilitating further development, the “Cogeneration Mission” of Gaz de France started 

offering a package of services including: 

- technical advice during the preliminary study (75 per cent of the projects done since 

1991); 

- assistance in engineering during project implementation or during the signing of 

maintenance contract (25 per cent of the projects since 1991); 

- assistance for arranging finances (35 per cent of the projects since 1991); 

- financial guarantee on possible changes in energy prices (35 per cent of the projects 

since 1991). 

3.4.2 Other actors promoting cogeneration 

The French Environment and Energy Management Agency (ADEME) has been an ardent 

supporter of cogeneration for several years. Before 1990, this technique was supported by 

ADEME because it allowed reducing around 30 per cent of fuel thanks to its efficiency ranging 

from 75 to 80 per cent. In the early 90s, another important justification to support cogeneration


was the reduction in environmental pollution associated with energy saving of cogeneration 

installations. Moreover, cogeneration favours the concept of decentralized energy production, 

in the range of 1 to 100 MW, which will find its relevance particularly when there will be a need 

to replace the existing nuclear power plants in 2005 and 2010. Today, around 65 power plants 

produce about 80 per cent of the electricity for the country, Such a centralized production 

leads to environmental problems related to transportation lines and the constraint of supplying 

to some regions. 

Today ADEME provides advisory service before the client approaches a consulting firm. It 

also assists public organizations during the bidding process. Public authorities solicit ADEME 

when new norms and standards are being formulated on cogeneration. 

The Club Cogénération, created in 1991, groups many important French entities concerned 

with cogeneration. These are local communities, district heating networks, heat operators, 

energy suppliers, equipment suppliers (turbines, engines, etc.), engineers, consulting firms, 

financing and insurance agencies. The Club proposes to public authorities regulatory 

measures that can favour the growth of cogeneration. It participates in working groups and 

gives opinion on the texts prepared in France as well as in Europe. It plays the role of a 

catalyst for exchanging experiences and information among professionals. The Club 

organizes training workshops and seminars periodically. The club also assures the follow-up 

on technological developments in cogeneration: new models and systems, efficiency 

improvements, impact of the installations on the economy and environment. 

3.4.3 Innovative cogeneration development 

Many industries and some communities are concerned about their main areas of activities 

and have limited budget for investing large sums in cogeneration plants. They often associate 

themselves with a company that includes an operator, a manufacturer, and a fuel supplier. 

Some of the operators sign a contract with their client that includes operation and 

maintenance guarantee for 6 to 12 years. 

The Général de Chauffe - Esys Montenay is a European leader in operating cogeneration 

installations. It proposes to take care of the production of all thermal energy needs of its client. 

It has 1,600 industrial clients in Europe (of which 90 per cent are in France and the United 

Kingdom), and has a share of 35 per cent of the French market. The company manages large 

district heating networks and steam generation facility to cater to industries with high steam 

demand. 

An industry that decides to install a cogeneration plant need not approach an operator, in 

which case, it has to make high investment and accept a long payback period. On the other 

hand, when an industry decides to go through an operator, it can achieve 10 per cent energy 

saving due to cogeneration without spending any money on the installation or getting involved 

in the operation and maintenance. Once it signs a contract to purchase energy from the 

operator, it is guaranteed a price and the quantity of steam to be supplied. Some industries to 

which the Général de Chauffe - Esys Montenay group supplies cogenerated energy are 

Michelin in Clermont-Ferrand (gas turbine of 30 MW capacity) and Troyes (gas turbine of 20 

MW capacity), and Swatch-automobile in Forbach (gas engine). 

In the framework of its development activities in the energy field, Sofregaz created a 

company specialized in cogeneration, known as Cogeplus. The objective of this entity was to 

develop competence and know-how in the domain of cogeneration in France, which could 

later be exported to other countries. Today, Cogeplus has attained its first objective. It has a 

variety of references in industries and municipalities, such as the factory of Rhone-Poulenc in 

Salindre (5 MW), factory of Pechiney in Gardane (80 MW), and an installation for the city of 

Limoges. Cogeplus undertakes turnkey projects and advises its clients. It assures the overall


responsibility for each of its projects by committing to implement the project in time and 

guaranteeing performance. It can offer to co-ordinate project financing for the client by getting 

in touch with financial institutions. 

3.5 Spain’s Energy Policy Favouring Cogeneration Development 

In spite of the fact that Spain has a milder climate and an industrial base which is less 

developed as compared with the Netherlands or Germany, the country has emerged as one 

of Europe’s leader in the development of cogeneration. This is a direct consequence of the 

energy policies favouring cogeneration. 

The country has demonstrated that clear policy actions can lead to the development of 

effective tools, ensuring rapid cogeneration growth and reaping the energy, economic and 

environmental benefits associated with it. It has also set an example of how such a 

promotional policy can lead to some adverse effects if it is not undertaken in a broader 

perspective of long-term sustainable energy planning in a country. 

The policies developed by the national authorities in the late 80s sent a very positive signal to 

the market and favoured cogeneration to an extent beyond what was projected in 1990. The 

scale of incentive tariffs announced led to payback periods as low as 3 years. Cogeneration 

appeared to have become such a lucrative activity that some cogenerators sold all the 

electricity generated in their plant to the grid and met their own power needs by buying it from 

the grid at a cheaper rate than their selling price. The rationale behind this incentive tariff is 

that the cogenerator takes the bulk of the project risk in the form of raising up-front capital and 

having a short term purchase contract. However, the Association of Electricity Self-producers 

(AAEE) counters this by pointing out that the number of cogenerators actually enjoying such 

high profitability is very marginal. On the other hand, cogeneration projects have helped to 

save over 15 billion Ptas annually in oil imports. 

The evolution of cogeneration has been entirely in the industrial sector, often with the 

participation of the power sector. An energy conservation law established in 1980 provided 

attractive legal framework for electricity self-generation and cogeneration through tariff 

incentives. The tariff at which electricity was purchased by the utilities even exceeded avoided 

costs but these were passed on to the consumer by the utility. Guaranteed electricity supply 

to the utilities fetched the highest rates. However cogeneration did not develop fast till 1986 

and most utilities were opposed to cogeneration development. The Institute for Diversification 

and Promotion of Energy (IDAE) started promoting it in 1986 through information 

dissemination programmes, advisory services, third party financing, etc. 

As a part of the national energy plan, major initiatives were undertaken by the Plan for Energy 

Conservation (PAEE) in the areas of energy conservation and substitution, cogeneration and 

renewable energies. The cogeneration programme set a target for increasing cogeneration 

capacity from 959 MW in 1990 to 2,222 MW by the year 2000 (see Figure 3.2). The annual 

contribution from cogeneration was expected to increase from 4,708 GWh in 1990 to 14,227 

GWh in 2000, resulting in 42,000 toe of annual fuel saving.


2000 

1994 

1993 

1992 

1991 

1989-90 

1986-88 

1980-85 

1980 

0 500 1,000 1,500 2,000 2,500 

MWe installed capacity 

PAEE target 

Over target 

Figure 3.2 Forecast of cogeneration growth in Spain 

Spain has about 20 utilities, mostly private, which account for 98 per cent of the generation 

and supply of electricity. As cogeneration schemes were found to provide lucrative returns 

with payback periods of 5 years or less compared to 25 years for the conventional plants, 

many utilities took active interest in promoting cogeneration in the form of investment and joint 

ventures, mostly in industrial schemes. Data for 1994 shows that the installed capacity was 

higher than the PAEE target at 1,847 MWe, producing 10,650 GWh and accounting for 6.5 per 

cent of the total power generation. Three industrial sectors - paper, refining and chemical - 

had about 110 new schemes, accounting for 75 per cent of the new capacity. Small 

cogeneration units installed since 1980 contributed to 17 MWe, of which 36 installations were 

below 1 MWe capacity, mostly using natural gas. 

Though some utilities became active in promoting cogeneration because of the attractive 

returns on investment, the response of the power sector as a whole was mixed. On some 

occasions cogeneration was opposed, on others the power industry was either neutral or 

supportive to the concept. This confused attitude often sent a negative signal to the 

prospective investor. Particularly, a year prior to the issuance of the new Electricity System 

Law in 1995, it was widely known that some changes unfavourable to cogeneration would be 

introduced. This effectively put a block on the development of new schemes. 

The new law of 1995 is expected to have some regressive impact on the extent of new 

cogeneration development in Spain. This legislation intends to harmonize self-generation with 

the central system and develop a uniform tariff. A major blow on the cogenerator has been the 

reduction of the tariff of exported electricity in steps by 30 per cent after 5 years of 

commissioning. Accordingly, the payback periods are expected to be much longer, as much 

as 15 years. The minimum purchase contract period has been specified for five years. The 

cogenerator is allowed to sell only the electricity produced in excess. Penalties for non-supply 

of guaranteed electricity have become so high that the cogenerator is likely to choose a 

programmed tariff that has a lower rate. The law appears more favourable to the power sector 

which will become a major player in cogeneration investment in the future as it is highly


unlikely that lower returns and higher risks involved in cogeneration projects can attract private 

sector investment any longer. 

3.6 Cogeneration Promoting Strategy in the United Kingdom 3 

The United Kingdom has a target to attain 5,000 MW of cogeneration by 2000. This would 

require an installation rate of 270 MW of new cogeneration capacity per year for the period 

1991-2000. According to the data monitored by the Department of Environment in 

collaboration with other organizations and the cogeneration industry, good progress was 

made during the first half of 1990s. At the end of 1995, there were approximately 3,500 MW of 

cogeneration installed in around 1,300 sites, meeting about 5 per cent of the country’s 

electricity requirements. Table 3.1 shows the evolution in the total capacity and electricity 

generated from 1991 to 1996. This steady increase in capacity is the outcome of the 

concerted efforts from industry, cogeneration promotion association (CHPA) and government 

to promote the technology. Cogeneration technology is considered as a crucial area of the 

government’s Energy Efficiency Best Practice programme which provides credible and 

independent information through various media, and much of direct support for technology 

development and innovative applications. 

Table 3.1 Steady growth of cogeneration in the UK from 1991 to 1996 

Year 1991 1993 1994 1995 1996 

Total cogeneration capacity (MWe) 2,312 2,893 3,141 3,487 3,562 

Electricity generated (GWh) 11,017 14,171 12,152 17,611 19,081 

Most recent cogeneration figures available show that there are a total of 1,336 cogeneration 

schemes in operation throughout the United Kingdom with a total capacity of 3,562 MWe. The 

details of the different sizes are given in Figure 3.3; as it can be seen, the vast majority of 

these in operation have a capacity less than 100 kW while larger than 10 MWe units make up 

for almost 80 per cent of the total capacity. Almost three-quarter of the total number of 

installations was for commercial, residential and public sector buildings. On the other hand, 

the industrial sector dominates the cogeneration market, accounting for 89 per cent of the 

total installed capacity. From this information, one can conclude that industrial cogeneration 

schemes had much bigger power generating capacities than those in the other sectors did. 

The largest growth in the number of schemes has been in the small sector, typically below 1 

MWe. As many as 273 schemes were installed during 1994-1996, with an aggregated power 

generating capacity of 60.2 MW, with an average of only 220 kW per scheme. As for the 

larger installations, 16 units were contracted in 1995, amounting to a total of 292 MWe. 

3 ETSU, “Statistics for combined heat and power in the United Kingdom”, Prepared for the Digest of 

United Kingdom of Energy Statistics (DUKES), 1997.


Number of installations 

800 

700 

600 

500 

400 

300 

200 

100 

0 

Installations 

Total capacity 

< 0.01 0.1 - .99 1 - 9.9 > 10 

Electrical capacity range, MWe 

Figure 3.3 Capacity range of cogeneration units installed in the UK (1996) 

3.6.1 Policies and initiatives for promoting cogeneration 

3,000 

2,500 

2,000 

1,500 

1,000 

Privatization of the public utilities and the on-going liberalization of the energy market have 

given a boost to the cogeneration business. The majority of the small cogenerators does not 

require getting a license and have been exempted from the fossil fuel levy. Even export of 

power up to 500 kW is allowed with the need to have a supply license. 

Government policies encourage the development of local generation, and there is a growth in 

the provision of integrated energy services, as opposed to simple energy supply, an approach 

which is very much compatible with cogeneration. Some of the policy changes that have 

benefited cogeneration include: 

- The level of supply at which a generation license is required has been increased from 10 

to 50 MWe; in certain circumstances, temporary supply of power above 50 MWe is 

allowed; the rule of 51 per cent “own use” has been relaxed; 

- The rules regarding supply of electricity have been changed, giving more flexibility for 

cogeneration scheme operation and the opportunity for more on-site customers to benefit 

from it; 

- With the introduction of net trading, the burden on the cogenerator is removed as the 

electricity that is used on-site does not have to be sold through the pool; 

- Cogeneration involving community heating, when it displaces electrical heating system, 

can be supported under the Public Electricity Suppliers’ obligations; 

- The Electricity Act has been amended to favour municipal waste based cogeneration; long 

term contracts are signed for electricity from renewable sources; 

0 

500 

Total capacity, MWe


- Local authority capital finance rules have been relaxed to facilitate cogeneration and 

community heating through private sector partnership; such schemes are also eligible for 

revenue support. 

There are several constraints to cogeneration development in the United Kingdom, the most 

notable among them is the need for high investment even though one can except to get 

attractive returns and cheap energy. Added to this is the overall volatility in the energy market 

and a perception of falling electricity prices that lead to uncertainty in decision making. 

Even though cogeneration and district heating are well established and found to be generally 

reliable, there is still a lack of awareness and distrust of the technology and its benefits. Some 

potential cogenerators are concerned about the commercial impact of protracted negotiations 

with regional electric companies, or do not comprehend well the regulatory and market 

complexities. 

The next few years offer a number of key opportunities for cogeneration to grow. Complete 

liberalization of the energy market will allow all energy users to choose their energy suppliers. 

As a result of privatization and market liberalization, energy companies are expanding their 

range of products and services. There is an increasing trend to shift from simple fuel and 

power supply to integrated energy service packages. Expertise of energy service companies 

and their ability to finance projects will provide excellent opportunity for cogeneration to grow. 

Greater development of community heating with the participation of local authorities and 

private sector developers will provide new opportunity for cogeneration. Energy recovery and 

cogeneration from waste will represent the best practicable environmental option and provide 

a major opportunity for sustainable waste management. 

Government has set an objective to establish an undistorted market for cogeneration and to 

eliminate any unnecessary barrier so that the target of 5,000 MWe by the year 2000 is met. To 

start with, government seeks cost effective options for applying cogeneration to its own estate 

and to persuade the public sector to follow suit. Currently over a half of all cogeneration 

installations are in the public sector. 

Government is also working with the cogeneration industry and other partners in order to 

develop new cogeneration market where there is unrealized potential. Efforts are being made 

to replicate the experience already gained in industries and buildings where cogeneration is 

well accepted. 

Lastly, government intends to continue the promotion of this technology by keeping the 

decision-makers informed through the “Energy Efficiency Best Practice” programme and 

other environmental and energy management initiatives.

PART 3: 

SUMMARY OF COUNTRY STUDIES - BANGLADESH AND VIET NAM

Framework for the country studies 97 

1.1 Background 

CHAPTER 1: FRAMEWORK FOR THE COUNTRY STUDIES 

The first task of the ESCAP cogeneration project was to identify two countries, one in South 

Asia and the other in South-East Asia, which offer considerable potential for cogeneration 

development but have not so far undertaken any methodical study to assess the opportunity 

for cogeneration. 

Bangladesh was chosen in South Asia because the country is presently facing with electricity 

shortage and the government is in the process of developing and implementing policies for 

encouraging private sector participation in the power sector. The country is endowed with 

natural gas and this gas is already available through distribution networks to many industrial 

and commercial customers to mostly meet their thermal energy requirements. The 

economic development of the country will see growth of new industries and commercial 

buildings as well as expansion of the existing facilities. Some of these enterprises are good 

clients for cogeneration. However, the awareness of the benefits of cogeneration appears to 

be low among the potential cogenerators as well as the policy makers. No initiatives have 

been taken so far by the public authorities to promote cogeneration in a systematic manner. 

In the case of South-East Asia, Viet Nam was selected because of its uniqueness among the 

South-East Asian countries. The shift from a centrally-planned to a market-based economy 

and the more recent integration of the country within the Association of South-east Asian 

Nations (ASEAN) have brought in new opportunities and challenges to the much desired 

economic development of the country. Sudden spurt of industrial and commercial 

developments along with the need for revamping the existing outdated production facilities 

has put tremendous pressure on the government. Already facing with the huge task of 

assuring the smooth transition of socio-economic development, the public authorities are 

short on finances to cope with the incessant need for infrastructure development, particularly 

related to the energy sector that is in the process of being restructured. Efforts are being 

made at the higher authorities level to look for both supply and demand options to deal with 

the present situation and to better prepare for future energy challenges. Though Viet Nam 

lags behind most other member countries of the ASEAN which are already at a fairly 

advanced stage of propagating policies and measures to facilitate the development of the 

market for cogeneration, the country is very much willing to learn from their experiences and 

find appropriate solutions in line with the prevailing socio-economic conditions. 

The main purpose of the project was to launch national studies primarily to enhance the 

national capacity for identifying and assessing the potential for cogeneration. To fulfil this, 

study teams were formed in both countries, mainly consisting of researchers and 

academicians who are very much interested in the subject and who hold the promise of 

sustaining the initial efforts by continued activities in the future to popularize the concept of 

cogeneration in their countries. 

Expected outcomes of the country studies included widespread dissemination of the findings 

and results among various interest groups as follows: 

1. national authorities, policy makers, utilities, industry representatives and others for 

creating awareness regarding the numerous benefits of cogeneration; 

2. potential cogenerators, manufacturers and/or suppliers of cogeneration equipment 

(engines, turbines, pressure boilers, absorption chillers, etc.), project developers,

98 Part3: Summary of country studies – Bangladesh and Viet 

financiers, and consultants who better interact to assure the success of cogeneration 

development; 

3. potential donor countries and motivate them in launching more substantial cogenerationrelated 

bilateral projects. 

1.2 Guidelines for the Country Studies 

Based on the assumption that these cogeneration studies were first of their kinds in the 

respective countries and the time available for completing the study was limited to three 

months, simple guidelines were prepared to cover the following: 

1. overview of present energy situation, policies and strategies in the country; 

2. preliminary assessment of the potential for cogeneration; 

3. pre-feasibility studies of some identified sites with promising cogeneration potential to 

evaluate the economic (financial) and environmental benefits; 

4. conclusion and recommendations for follow-up actions. 

1.2.1 Overview of energy situation, policies and strategies in the country 

The basic requirement before going deeper into cogeneration study is to first have a clear 

perspective of the overall energy situation in the country. This includes understanding of the 

historical evolution of the energy sector, and the status as well as future prospects for 

electricity demand and supply. Other notable aspects are the share of energy use in the 

industrial and commercial sectors, the status of industrial growth, and forecasts of energy 

use in line with the target overall economic development. 

A major factor determining the financial viability of cogeneration projects is the prevailing 

costs of fuel and electricity. Therefore a good understanding of the energy pricing 

mechanism and any price distortions such as taxation and cross-subsidization is important 

for making realistic assumptions of the input parameters of the pre-feasibility studies. 

Equally important is the need to grasp the various government policies and strategies being 

formulated for encouraging private sector involvement in power generation in various forms. 

Based on the ground reality, a critical analysis of strengths and weaknesses of these 

initiatives is desirable. 

1.2.2 Preliminary assessment of the potential for cogeneration 

An evaluation of the existing cogeneration facilities helps in quantifying the share of 

cogeneration in the total power supply, and identifying the sectors where cogeneration has 

already been well accepted. Also, information gathered from the sites and discussion with 

cogenerators help to assess aspects such as the technological status, operation and 

management practices, economic and financial benefits, constraints and drawbacks in 

operating such facilities, etc. 

Preliminary assessment includes identification of industrial and commercial sectors which 

offer cogeneration potential, based on the various technical criteria such as heat-to-power 

ratio, quality of thermal energy requirements, typical demand patterns of the different forms of 

energy at the site, availability of fuels, level of system reliability needed, etc. 

Once the industrial and commercial sectors offering good potential for cogeneration are 

identified, the technical potential for cogeneration can be established on selected sample 

sites using a standard questionnaire of the type given in Appendix 1.A.


The response from the questionnaires sent and preliminary discussions with interested 

parties help to identify suitable sites where a limited number of pre-feasibility studies can be 

undertaken. 

1.2.3 Pre-feasibility study of sites with good cogeneration potential 

Pre-feasibility study involves gathering of additional technical data from the site, including the 

actual demand pattern as a function of time, minimum, maximum and average energy 

demands, annual operating hours, type of fuel in use, space constraint, etc. 

The above data allow to complete a technical evaluation of cogeneration and identification of 

cogeneration alternatives in order to proceed with the phase, economic and financial 

evaluation. Several country-specific economic and financial parameters need to be first 

gathered before the pre-feasibility study. If some data are unknown or not available, it is 

important to make realistic assumption based on discussion with the personnel of the site 

and competent authorities in the country. 

Once, preliminary financial results are obtained, it is important to conduct a sensitivity 

analysis to identify the most important parameters that are decisive to the financial viability of 

the project. 

1.2.4 Conclusion and recommendations for follow-up actions 

The results of sensitivity analysis help to first define the context and conditions where 

cogeneration should be recommended from the energy and environmental perspectives. One 

can also assess the impacts of any distortion of energy pricing and other forces that can 

adversely affect the penetration of cogeneration into the market. These can serve as 

justifications for outlining appropriate policies and strategies that may be required to assure 

the large-scale adoption of cogeneration projects in the country. 

In order to illustrate the procedure for assessing the pre-feasibility of identified sites and to 

assure consistency and uniformity of all the cases considered, a sample case study was 

developed by the lead consultant and presented to the study teams in both the countries. 

This case study was accompanied by spreadsheet-based software that can help to cut down 

the analysis time drastically. 

The sample case study consisting of pre-feasibility of cogeneration in a pulp and paper mill in 

the Philippines is elaborated in Chapter 2.

100 Part3: Summary of country studies – Bangladesh and Viet 

GENERAL INFORMATION 

Name of the Company: 

Address: 

Telephone: 

Fax: 

Contact Name: 

Position: 

SITE INFORMATION 

APPENDIX 1.A 

TYPICAL QUESTIONNAIRE FOR INITIAL APPRAISAL OF 

COGENERATION POTENTIAL AT A GIVEN SITE 

Main Activity: 

Hours of Operation: 

Working days: 

Total Annual Operating Hours: 

Period and Duration of Annual Shutdown: 

ELECTRICITY DATA (AT LEAST FOR LAST 12 MONTHS) 

Year Month Consumption 

(MWh) 

Transformer Capacity (kVA): 

Annual Peak Demand (kW/kVA): 

Any changes in the future demand patterns expected? 

THERMAL REQUIREMENTS (FOR LAST 12 MONTHS) 

Peak hours 

(MWh) 

Steam: 

Boiler Outlet Pressure (Bar) and Temperature (°C): 

Process heat requirement Pressure (Bar) and Temperature (°C): 

Hot water: 

Supply Temperature (°C): 

Return Temperature (°C): 

Cold/chilled water: 

Supply Temperature (°C): 

Return Temperature (°C): 

Year Month Steam 

(ton) 

Hot Water 

(GJ) 

Off-peak hours 

(MWh) 

Chilled Water 

(GJ)


Any changes in the future demand patterns expected? 

If available, please provide typical hourly thermal energy demand profiles for a week and a 

weekend day, during summer and winter. 

BOILER FUEL CONSUMPTION (FOR LAST 12 MONTHS) 

Year Month Nat. Gas 

(m 3 ) 

EXISTING BOILER FACILITY 

Diesel 

(litre) 

Manufacturer: 

Age: 

Capacity: 

Fuel: 

Does the boiler require retrofitting or replacement? 

FUEL SUPPLIES 

Is natural gas available at site? 

If yes, at what pressure is the gas available? 

EXISTING POWER GENERATING FACILITY 

HFO 

(litre) 

Is there any on-site power generating facility? 

If yes, 

Type of plant (Steam turbine/gas turbine/engine): 

On-site generation capacity: 

Coal 

(ton) 

Others 

(unit)

Sample case study in a pulp and paper mill 103 

CHAPTER 2: SAMPLE CASE STUDY IN A PULP AND PAPER MILL 

2.1 Project Description 

The Container Corporation of the Philippines (CCP) which uses electricity and thermal 

energy simultaneously, plans to set up a cogeneration plant. Located at Balintawak, Quezon 

City, it is a paperboard mill and converting plant. It produces various paperboards by 

recycling waste papers. CCP operates its mill 365 days a year with 24 hours a day in three 

shifts. The mill operation is stopped only due to breakdown of machines, scheduled 

maintenance of equipment, power interruption and calamities such as typhoons, fires, etc. 

This mill offers a good opportunity for cogeneration as it has steady thermal and electrical 

loads, and it requires a steady supply of energy in order to avoid production losses. Before 

deciding on making a substantial investment in this project, it is necessary to carry out a 

thorough financial analysis of the possible cogeneration alternatives. 

The method of conducting pre-feasibility of cogeneration in CCP involves a three-step 

procedure, i.e., search and identification of alternatives, estimation of costs and savings, and 

economic evaluation of all options. 

2.2 Identification of Possible Cogeneration System Alternatives 

This stage involves (1) analysis of the current energy consumption pattern of the CCP plant, 

and (2) identification of possible cogeneration candidates, and evaluation of technical 

parameters for each candidate. 

2.2.1 Current Energy Consumption 

a) Power consumption 

Electricity in the paper factory is used for board making (47 per cent), papermaking (51 per 

cent) and lighting & air-conditioning (2 per cent). Analysis of the monthly electricity 

consumption of the factory in 1996 shows the following: 

• Maximum Monthly Electricity Consumption (May): 1,377 MWh 

• Minimum Monthly Electricity Consumption (March): 740 MWh 

• Peak Power Demand: 2,430 kW 

• Base Power Demand: 2,040 KW 

• Total Electricity Consumption in 1991: 12,715 MWh 

b) Steam consumption 

CCP uses 98 per cent of the total steam production for paper drying while 2 per cent is used 

for cleaning the process equipment. Paper drying at CCP requires saturated steam at a 

pressure of 7 bar. The steam requirement is met by two boilers with capacities of 9 tons/hr 

and 13 tons/hr respectively. Bunker oil is used as fuel for boilers. 

Detailed steam and fuel consumption data were analyzed to derive monthly consumption in 

1996, daily consumption pattern during the month with high demand, hourly steam demand 

profile of the factory for sample peak days. The analysis led to the following:

104 Part3: Summary of country studies – Bangladesh and Viet Nam 

• Peak steam demand (occurred in June): 12,950 kg/hr 

• Base steam demand (occurred in November): 5,000 kg/hr 

• Total steam consumption in 1991: 5.7×10 4 tons 

• Total bunker oil consumption in 1991: 4.6×10 6 litres 

c) Power to heat ratio 

Monthly power to heat ratio in 1996 of the CCP plant varies from 64.4 MWh/TJ to 105.9 

MWh/TJ, the average value being 82.8 MWh/TJ or 0.3 kWe/kWth (see Figure 2.1). 

Power to Heat Ratio (MWh/TJ) 

110 

100 

90 

80 

70 

60 

50 

40 

Jan. 

Feb. 

Mar. 

Apr. 

May 

Jun. 

Jul. 

Month 

Figure 2.1 Monthly power to heat ratio of the CCP plant 

2.2.2 Identification of Alternative Cogeneration Options 

For the average power to steam ratio of 82.8 MWh/TJ of the factory, typical cogeneration 

system used is the steam turbine. However, reciprocating engine and gas turbine 

cogeneration systems were also included as potential alternatives because these are: 

• applicable in small-scale cogeneration systems. 

• commonly used configurations in the Philippines. 

• simple and easy-to-grasp technologies. 

a) Sizing of cogeneration system 

Based on the results of the energy demand analysis, each of the above candidate 

cogeneration systems was sized to meet either the manufacturing plant's process steam 

(thermal match) or electricity requirements (power match). From the analysis of the plant's 

electricity and steam usage pattern, base and peak process heat requirements of 5,000 

kg/hr, 13,000 kg/hr are used for thermal matching. Likewise, base and peak power 

requirements of 1,500 and 2,430 kW are investigated for power matching. 

Aug. 

Sep. 

Oct. 

Nov. 

Dec.


Table 2.1 Process steam rates and power demand used in the sizing options 

(A) Thermal Match 

Process steam (kg/hr) Annual steam generation (TJ) Heat deficit (TJ) Excess heat (TJ) 

5,000 

13,000 

103 

269 

(B) Power Match 

Power demand (kW) Annual power generation (MWh) Power deficit (MWh) Excess power (MWh) 

1,500 

2,430 

11,235 

18,200 

Notes: 1. Enthalpy of required process steam is 2,761 kJ/kg. 

2. Annual actual working period is 7,884 hours/year. 

55 

0 

1,480 

3. Total annual thermal energy requirement of CCP is 158 TJ. 

4. Total power requirement of CCP is 12,715 MWh. 

b) Technical potential evaluation 

Steam Turbine 

Fuel 

Boiler 

Figure 2.2 Backpressure steam turbine cogeneration system 

0 

0 

111 

0 

5,485 

Figure 2.2 shows a backpressure steam turbine cogeneration system. Superheated steam 

was considered for typical inlet pressures of 20, 30, 40, 50, 60 70 bars respectively. The 

power to steam ratio, the power generated by the steam turbine for a given process steam 

requirement as well as the steam generated for a given power requirement can be estimated 

by using the following formulas: 

• Power to Heat Ratio 

PHR = 

Steam 

− × η × η 

( H H ) 

in out tb gen 

H 

out 


Process 

G 

(kWe/kWth) 

Electricity


= ( ) 

− × η × η 

H H 

in out tb gen 

3 . 6 

Where, PHR = power to heat ratio 

Hin 

(kWe/(ton/hr of steam) 

= enthalpy of the turbine inlet steam, kJ/kg 

Hout = enthalpy of the turbine outlet steam, kJ/kg 

ηtb 

= turbine efficiency 

ηgen = generator efficiency 

• Power Generation (for thermal matching) 

P = 

PHR xS xHR CF 

o 

10 

Where, P = electricity generation, MWh/year 

6 

PHR = power to steam ratio, kW/(ton/hr of steam) 

So 

= process steam to be met, kg/hr 

CF = factor for continuous operation, 0.9-0.95 

HR = actual working hours per year 

• Heat Generation (for power matching) 

S = 

× 

P x H xHR xCF 

o out 

PHR x 10 

Where, S = heat generation, TJ/year 

Po 

• Fuel Consumption 

= power to be met, kW 

Hout = enthalpy of the turbine outlet steam, kJ/kg 

6 

PHR = power to steam ratio, in kW/(ton/hr of steam) 

F = 

(H - H ) x S x HR x CF 

in f 

η 

b 

′ 

× 

10 

Where, F = fuel consumed by the cogeneration system, TJ/year 

Hin 

Hf 

= enthalpy of steam at turbine inlet, kJ/kg 

= enthalpy of feedwater, kJ/kg 

S' = steam flowrate, kg/hr 

nb 

= boiler efficiency 

9


5,000 kg/hr 

Table 2.2 Results of thermal matching for the steam turbine option 

Turbine Inlet Steam Pressure = 7 bar 

Turbine Outlet Pressure (bar) 

20 30 40 50 60 70 80 

Power Generating Capacity (kW) 282 353 408 451 482 504 522 

Electricity Generation (MWh/year) 2,111 2,462 3,059 3,375 3,608 3,777 3,906 

Excess(+)/Deficit(-) Power (MWh) -10,604 -10,073 -9,656 -9,340 -9,107 -8,938 -8,809 

Fuel Consumption (TJ/year) 122 126 129 131 133 134 135 

Excess(+)/Deficit(-) Heat (TJ/year) -55 -55 -55 -55 -55 -55 -55 

13,000 kg/hr 

Power Generating Capacity (kW) 733 917 1,062 1,172 1,252 1,311 1,356 

Electricity Generation (MWh) 5,489 6,869 7,955 8,776 9,380 9,820 10,157 

Excess(+)/Deficit(-) Power (MWh) -7,226 -5,846 -4,760 -3,939 -3,335 -2,895 -2,558 

Fuel Consumption (TJ) 318 328 336 342 346 349 352 

Excess(+)/Deficit(-) Heat (TJ/year) 111 111 111 111 111 111 111 

1,500 kW 

Table 2.3 Results of power matching for the steam turbine option 

Turbine Inlet Steam Pressure = 7 bar 

Turbine Outlet Pressure (bar) 

20 30 40 50 60 70 80 

Heat Generating Capacity, kg/hr 26,607 21,262 18,360 16,642 15,571 14,873 14,380 

Heat Generation, TJ/yr 495 396 342 310 290 277 268 

Excess(+)/Deficit(-) Heat (TJ/yr) 337 238 184 152 132 119 110 

Fuel Consumption, TJ/yr 650 536 474 437 414 399 389 

Excess(+)/Deficit Power, MWh/yr -1,480 -1,480 -1,480 -1,480 -1,480 -1,480 -1,480 

2,430 kW 

Heat Generating Capacity, kg/hr 43,103 34,444 29,744 26,960 25,225 24,094 23,295 

Heat Generation, TJ/yr 802 641 554 502 470 449 434 

Excess(+)/Deficit(-) Heat (TJ/yr) 644 483 396 344 312 291 276 

Fuel Consumption, TJ/yr 1,053 868 768 708 671 647 630 

Excess(+)/Deficit Power, MWh/yr 5,485 5,485 5,485 5,485 5,485 5,485 5,485 

Reciprocating Engine 

Figure 2.3 shows a reciprocating engine cogeneration system. It uses a diesel engine as its 

prime mover together with heat recovery from the engine exhaust and engine jacket cooling 

water. It can be operated efficiently at partial load and in small sizes. Compared with steam 

turbine and gas turbine units, Diesel engine with waste heat boiler has higher power to heat 

ratio, which ranges from 2.0 to 2.6. Table 2.4 shows its typical energy distribution.


Diesel Engine 

Figure 2.3 Typical reciprocating engine cogeneration system 

The power to heat ratio for the reciprocating engine cogeneration system can be calculated 

by: 

PHR = 

Coolers 

ηengine 

η × η 

exhaust hrsg 

= ηengine 

× ( H o − H fw) 

ηexhaust × ηhrsg 

× 3. 6 

[kWe/kWth] 

[kWe/(ton/hr of Steam)] 

where, ηengine = percentage of engine electric output 

ηexhaust = percentage of exhaust heat 

ηhrsg = efficiency of heat recovery steam generator 

Ho 

Hfw 

~ 450 O C 

Oil Air Water 

Exhaust 

Heat 

= enthalpy of process steam, kJ/kg 

= enthalpy of feedwater, kJ/kg 

~ 200 O C 

Heat Recovery Steam Generator 

Table 2.4 Typical energy distribution (per cent) for reciprocating engines 

Size 60 kW 230-840 kW 1,200-2,400 kW 

Electric Output 26 33 35 

Cooling 23 30 29 

Exhaust 47 30 29 

Losses 4 7 7 

G 

Process 

Total (Fuel Input) 100 per cent 100 per cent 100 per cent 

The power generation, steam generation and fuel consumption are calculated as follows: 

Steam


• Power Generation (for thermal matching) 

P = 

PHR x S xHR CF 

o 

10 

Where, P = electricity generation, MWh/year 

6 

PHR = power to steam ratio, kW/(ton/hr of steam) 

So 

= process steam to be met, kg/hr 

CF = factor for continuous operation, 0.9-0.95 

HR = actual working hours per year 

• Heat Generation (for power matching): 

S = 

P x H xHR xCF 

o o 

PHR x10 

Where, S = heat generation, TJ/year 

Po 

Ho 

• Fuel Consumption: 

F 

= 

η 

= power to be met, kW 

= enthalpy of process steam, kJ/kg 

6 

PHR = power to heat ratio, kWe/(ton/hr of steam) 

3 . 6 

engine 

× 

× 

P 

10 3 

Where, F = fuel consumption, TJ/year 

P = power generation, MWh/year 

ηengine 

× 

= percentage of engine electric output 

Table 2.5 Summary of the results for the diesel engine 

Thermal Matching 

5,000 kg/hr 13,000 kg/hr 

Power Generating Capacity, kW 6,259 16,272 

Power Generation, MWh/year 46,876 121,877 

Excess(+)/Deficit(-) Power, MWh/year 34,161 109,162 

Excess(+)/Deficit(-) Heat, TJ/year -55 111 

Fuel Consumption, TJ/year 482 1,254 

Power Matching 

1,500 kW 2,430 kW 

Heat Generating Capacity, kJ/kg 1,198 1,941 

Heat Generation, TJ/year 25 40 

Excess(+)/Deficit(-) Heat, TJ/year -133 -118


Excess(+)/Deficit(-) Power, MWh/year -1,480 5,485 

Fuel Consumption, TJ/year 116 187 


Figure 2.4 shows a typical gas turbine cogeneration unit. Gas turbine cogeneration unit has 

the following advantages over other internal combustion engine drives: small size and high 

power to heat ratio, ability to burn a variety of fuels, clean dry exhaust and hence ability to 

meet stringent pollution standards, high reliability and easy maintenance. Table 2.6 presents 

the typical heat disposition of gas turbines. 

Electricity 

Generator 

G 

Air 


Flue 

Gas 

Fuel 

Exhaust Gas 

HRSG 

Figure 2.4 Gas turbine with heat recovery steam generator 

Table 2.6 Gas turbine heat balance 

Water 

Steam 

Small Units Medium Size Units 

Electricity 21 per cent 29 per cent 

Exhaust Heat (Theoretically Recoverable) 53 per cent 46 per cent 

Exhaust Heat (Not Recoverable) 21 per cent 20 per cent 

Generator, Oil Cooler and Radiation Losses 5 per cent 5 per cent 

Total (Fuel Input) 100 per cent 100 per cent 

Following the same way as that for reciprocating engine cogeneration unit, the power to heat 

ratio, power generation and heat generation, fuel consumption, etc., can be calculated. The 

results are shown in Table 2.7.


2.3 Calculation of Costs and Benefits 

After evaluating the technical potential of the alternative cogeneration systems, the different 

sources of revenues and expenses of the systems are determined so that the evaluation of 

the economic potential of each system could be followed. 

Table 2.7 Summary of the results for the gas turbine 

Thermal Matching 

5,000 kg/hr 13,000 kg/hr 

Power Generating Capacity, kW 2,493 6,482 

Power Generation, MWh/year 18,673 48,550 

Excess(+)/Deficit(-) Power, MWh/year 5,958 35,835 

Excess(+)/Deficit(-) Heat, TJ/year -55 111 


Power Matching 

1,500 kW 2,430 kW 

Heat Generating Capacity, kJ/kg 3,008 4,873 

Heat Generation, TJ/year 62 101 

Excess(+)/Deficit(-) Heat, TJ/year -96 -57 

Excess(+)/Deficit(-) Power, MWh/year -1,480 5,485 


2.3.1 Costs 

(a) Total installation cost 

The installation cost of each cogeneration system can be roughly estimated by the formula 

taken from the report on “Industrial and Commercial Cogeneration”, Office of Technology 

Assessment, Washington D.C., U.S.A.: 

• Steam Turbine (Oil-Fired): 

C = [962.761- (9.119 x10 -3 x M) - (1.314 x 10 -7 x M 2 ) + (2.782 x 10 -11 x M 3 )] x M x E 

• Diesel Engine: 

C = [915.14 - (6.531 x 10 -2 x M) + (4.56 x 10 -6 x M 2 ) - (1.424 x 10 -10 x M 3 )] x M x E 

Where, C = installation cost, Peso 

M = installed capacity, kW 

E = peso - dollar exchange rate, assumed 26 Peso/$ in 1996 

(b) Operating costs 

The operating costs in this case study include: 

• Fuel Costs: cost of fuel consumed by the cogeneration unit. 

• Operating and Maintenance Costs: These are taken as 2.5 per cent of the total installation 

cost of the cogeneration unit.


(c) Insurance cost 

Insurance cost reduces as the book value of equipment decreases. Here, it is taken as 5 per 

cent of the book value of the equipment. 

(d) Depreciation 

Straight-line depreciation method is adopted. The depreciation cost is calculated as: 

CD 

= (C - S)/N 

Where, S = salvage value of equipment, Peso 

N = equipment life, years 

(e) Standby charges 

If the electricity demand of the facility cannot be met by the cogeneration system, certain 

amount of electricity must be imported from the grid. In this case, tariff structure requires the 

electricity consumers to pay a standby charge depending upon the demand. The standby 

charge is computed as follows: 

CSC = SR x SC 

Where, SR = standby rate, Peso/kW 

2.3.2 Revenues 

SC = standby capacity, kW 

In this case study, revenue from a cogeneration system comes from four possible sources, 

namely, savings from displaced electricity, sale of excess electricity, boiler fuel cost savings, 

and boiler operating and maintenance cost savings. 

(a) Savings from displaced electricity 

RDE = P’ x CE 

Where, P’ = power generated by the cogeneration system, kWh 

CE 

= electricity purchase price, Peso/kWh 

(b) Revenue from sale of excess electricity 

RX 

= PX’ x (BR/100) x CE 

Where, PX’ = excess electricity, kWh 

BR 

= buy-back rate, per cent 

(c) Boiler fuel cost savings 

RF 

Where, KF 

= KF 

LHV 

x S x10 6 

= fuel purchase price, Peso/kg 

LHV = fuel lower heating value, MJ/kg 

S = amount of process steam utilized, TJ


(d) Boiler O & M cost savings 

This is the cost that would have been incurred in operating and maintaining the boiler if 

process steam was produced by a conventional boiler and not by the cogeneration system. 

2.4 Financial Analysis of the Cogeneration Alternatives 

Evaluation of the feasibility of each alternative is made by the IRR and NPV methods. Before 

calculating IRR and NPV, the costs, revenue, pre-tax profit, net profit as well as net cash flow 

are computed. Table 2.8 lists the results for selected cogeneration alternatives at the end of 

the first year of project life. Then, IRR and NPV for each candidate are calculated with the 

following assumptions: 

The service lifetime of the installed cogeneration system: 15 years 

The estimated cost escalation rate per year for fuel, electricity and O&M: 5 per cent 

Buy-back Rate: 70 per cent 

Insurance (as per cent of equipment cost): 5 per cent 

Tax Rate: 35 per cent 

Discount rate: 15 per cent 

Table 2.8 Summary of cash flows of selected alternatives for the 1 st Year 

Total 

Installation 

Cost 

Cost of 

Fuel 

STEAM TURBINE (Thermal Match) 

5,000 kg/hr 

40 Bar 

60 Bar 

80 Bar 

13,000 kg/hr 

40 Bar 

60 Bar 

80 Bar 

12,222,440 

14,401,909 

15,589,108 

31,577,708 

37,165,524 

40,203,762 

STEAM TURBINE (Power Match) 

1,500 kW 

7,281,116 

7,504,958 

7,627,024 

18,930,902 

19,512,892 

19,830,261 

Total Costs Total 

Revenue 

8,136,722 

8,513,127 

8,718,296 

21,141,377 

22,114,513 

22,644,559 

11,282,569 

12,214,331 

12,722,438 

22,813,046 

25,235,627 

26,556,705 

Pre-Tax 

Profit 

2,331,018 

2,714,077 

2,964,868 

-433,511 

643,412 

1,231,895 

Net Profit Net Cash 

Flow 

1,515,162 

1,781,700 

1,927,164 

-433,511 

418,218 

800,732 

2,329,991 

2,741,827 

2,966,438 

1,671,670 

2,895,920 

3,480,932 

80 Bar 44,407,619 21,934,763 25,043,310 28,389,132 385,314 250,454 3,210,962 

2,430 kW 

80 Bar 71,284,107 35,534,316 40,524,218 30,905,642 -14,370,849 -14,370,849 -9,618,575 

DIESEL ENGINE 

Thermal-Match 

5,000 kg/hr 

13,000 kg/hr 

Power-Match 

1,500 kW 

2,430 kW 

GAS TURBINE 

Thermal-Match 

158,679,722 

283,210,583 

48,376,832 

74,045,674 

32,761,595 

85,180,147 

7,851,944 

12,720,150 

44,662,609 

106,420,976 

11,480,242 

18,273,610 

69,541,795 

162,631,802 

20,842,550 

30,967,472 

14,300,538 

37,330,121 

6,137,187 

7,757,484 

(All Values in Pesos) 

9,295,349 

24,264,579 

3,989,171 

5,042,365 

19,873,998 

43,145,284 

7,214,293 

9,978,743


5,000 kg/hr 

13,000 kg/hr 

Power-Match 

1,500 kW 

2,430 kW 

90,828,571 

195,551,493 

58,052,199 

88,854,808 

18,270,890 

47,504,313 

10,992,722 

17,808,209 

21,449,925 

54,348,650 

13,024,584 

20,918,163 

35,980,477 

75,372,376 

23,475,928 

35,233,544 

8,475,314 

7,986,959 

6,581,197 

8,391,727 

Table 2.9 Summary of NPV and IRR 

5,508,954 

5,191,524 

4,277,778 

5,454,623 

Cogeneration Alternatives 

Steam/Power Turbine Inlet Steam NPV IRR 

Demand 

Pressure (bar) 

(%) 

Steam Turbine (Thermal Match) 

5,000 kg/hr 40 

7,340,891 

24.31 

60 

8,623,889 

24.28 

80 

9,324,957 

24.27 

13,000 kg/hr 40 

-12,394,563 

7.90 

60 

-8,832,665 

10.90 

80 

-6,956,922 

12.00 

Steam Turbine (Power Match) 

1,500 kW 80 -12,397,728 10.10 

2,430 kW 80 -122,352,173 -- 

Diesel Engine (Thermal Match) 

5,000 kg/hr --- 16,713,528 16.70 

13,000 kg/hr --- 97,294,178 20.40 

Diesel Engine (Power Match) 

1,500 kW --- 13,726,021 19.60 

2,430 kW --- 12,812,597 17.80 

Gas Turbine (Thermal Match) 

5,000 kg/hr --- 1,218,335 15.20 

13,000 kg/hr --- -46,400,865 10.60 

Gas Turbine (Power Match) 

1,500 kW --- 6,605,407 16.90 

2,430 kW --- 1,694,257 15.30 

2.5 Sensitivity Analysis 

11,564,192 

18,228,290 

8,147,925 

11,378,277 

The price escalation rates for electricity and fuel estimated in this evaluation process might 

not be exact. Similarly, the installation cost represents a large investment and changes in this 

cost can affect the results significantly. Sensitivity analysis of IRR of the feasible 

cogeneration systems is done assuming changes in each of these factors. 

The following two acceptable alternatives are taken as examples for the sensitivity analysis: 

(1) Steam Turbine, Thermal Match [STTM]: 5,000 kg/hr, Turbine steam inlet pressure: 

40 bar; 

(2) Diesel Engine, Power Match [REPM]: 1,500 kW Power Demand.


Changes in the Escalation Rate of Fuel Price 

IRR 

30% 

25% 

20% 

15% 

10% 

5% 

IRR vs. Escalation Rate of Fuel 

Price 

IRR(STTM) 

IRR(REPM) 

5% 7% 9% 11% 13% 

Escalation Rate of Fuel Price 

Figure 2.5 Sensitivity analysis of IRR for different fuel price escalation rates 

Sensitivity of IRR for the two alternatives to changes in the escalation rate of fuel prices from 

5 per cent to 13 per cent is presented in Figure 2.5. From this analysis, it may be observed 

that the diesel engine (1,500 kW) appears to be more sensitive to changes in fuel prices. For 

an escalation rate of 13 per cent, the steam turbine (thermal matching option) using 40 bar 

inlet steam is still found to be economically feasible, whereas diesel engine is no longer 

financially attractive because the IRR becomes less than discount rate which is 15 per cent. 

Changes in the Investment Cost 

IR 

R 

25% 

23% 

20% 

18% 

15% 

IRR vs. 

13% 

10% 

IRR(STTM) 

IRR(REPM) 

0% 5% 10% 15% 

% of Investment Increase 

Figure 2.6 Sensitivity analysis of IRR to increases in the investment cost 

Zero to 15 per cent increases in the investment cost are made to analyze the sensitivity of 

IRR of the two alternatives (see Figure 2.6). When the increases are less than 15 per cent, 

the IRRs of steam turbine cogeneration system using 40 bar superheated steam and diesel 

engine cogeneration system remain higher than the 15 per cent hurdle rate.


Changes in Escalation Rate of Electricity Price 

IRR 

35% 

30% 

25% 

20% 

15% 

IRR vs. Escalation Rate of 

Electricity Price 

IRR(STTM) 

IRR(REPM) 

6% 8% 10% 12% 

Escalation Rate of Electricity Price 

Figure 2.7 Sensitivity of IRR to changes in electricity price escalation rate 

From the sensitivity analysis results shown in Figure 2.7, it can be concluded that with higher 

escalation rate of electricity purchase price, higher internal rate of return of the cogeneration 

system can be achieved. This is mainly due to the increasing revenues generated from the 

displaced electricity and from the sale of excess electricity. 

2.6 Conclusion 

From the techno-economic evaluation and sensitivity analysis of the potential cogeneration 

alternatives of the paper factory, the steam turbine option meeting steam demand of 5,000 

kg/hr with superheated steam of 40 bar is found to be the most suitable cogeneration 

system. It represents an initial investment of 12.2 million Pesos, and leads to an internal rate 

of return of 24.3 per cent. 

[Reference: Techno-economic evaluation of cogeneration potential in two manufacturing 

plants in the Philippines. AIT RSPR No. ET-89-6]


APPENDIX 2.A 

SAMPLE PAGES FROM THE SPREADSHEET PROGRAMME ON 

FINANCIAL ANALYSIS OF COGENERATION PROJECTS 

Some of the sample pages of the software are given as example. These include: 

1. Flow chart of the sample case study (1 page) 

2. General data and energy data of the site (1 page) 

3. Result of steam turbine cogeneration with thermal match option (2 pages) 

4. Result of steam turbine cogeneration with power match option (2 pages) 

5. Result of reciprocating engine cogeneration with thermal match option (1 page) 

6. Result of reciprocating engine cogeneration with power match option (1 page) 

7. Result of gas turbine cogeneration with thermal match option (1 page) 

8. Result of gas turbine cogeneration with power match option (1 page) 

9. Sample results of sensitivity analyses (2 pages)


SAMPLE CASE STUDY OF COGENERATION PRE-FEASIBILITY ANALYSIS 

FLOW CHART OF THE SAMPLE CASE STUDY 

GENERAL DATA 

(1) Project Data 

(2) Energy Consumption 

Data of the Site 

Worksheet: Data 

Identification of Options 

Steam Turbine Reciprocating Engine Gas Turbine 

Thermal 

Match 

Steam(TM) 

Power 

Match 

Steam(PM) 

Thermal 

Match 

REngine(TM) 

1: Assumptions 

2 : Energy Analysis 

3: Financial Analysis 

4 : Summary 

Power 

Match 

REngine(PM) 

Steam Turbine (Thermal Match) & 

Reciprocating Engine (Power Match) 

Sensitivity Analysis 

(1) What-if Investment Cost Increases? 

(2) What-if Fuel Price Escalation Rate Increases? 

(3) What-if Electricity Price Increases? 

Worksheet: Sensitivity 

Thermal 

Match 

GasT(TM) 

Power 

Match 

GasT(PM)


(1) General Data: 

Date 

GENERAL DATA AND ENERGY DATA OF THE 

Country Philippines 

National Currency Peso 

Exchange Rate Peso/US$ 26 

Electricity Purchase Price Peso/kWh 1.7 

Electricity Buy-back % 70 

Escalation Rate for Electricity % /yr 6 

Stand-by Rate Peso/kW 0.07 

Tax Rate % /yr 35 

Discount Rate % /yr 15 

Number of Actual Working Hours Per Hours/yr 7,884 

(2) Energy Consumption Data of the Site 

Power 

Peak Power Demand kW 2,400 

Base Power Demand kW 1,500 

Annual Electricity MWh/yr 12,71 

Heat 

Peak Steam Demand kg/hr 13,00 

Base Steam Demand kg/hr 5,000 

Annual Thermal Energy TJ/yr 158.0 

Power to Heat Ratio kW e 

/kW th 

June 

0.3 

kW/(ton/hr Steam) 84.8


1. Economic and Technical Data 

(1) Economic Data 

Steam Turbine: Thermal Match 

Fuel Name Oil 

Fuel Net Calorific Value MJ/kg 39 

Unit of Fuel Purchased (e.g. kg, m 3 , litre) kg 

Fuel Purchase Price Peso/kg 2.20 

Fuel Price Escalation Rate % 5.0 

Conventional Boiler O & M Cost (% of Equipment Cost) % 5.0 

CHP O&M Costs (% of Total Installation Cost) % 2.0 

Escalation Rate for O & M Costs % 5.0 

Standby Capacity kW 500 

Insurance Cost (as % of book value of equipment) % 5.0 

Service Life of Cogeneration Facilities Years 15 

Salvage Value of Cogeneration Facilities Peso 0 

(2) Technical Data 

Heat Demand to Be Met by CHP Boiler kg/hr 5,000 

CHP Boiler Working Pressure Bar 40 

Process Steam Pressure Bar 7 

Total Installation Cost Peso 12,222,440 

2. Energy Analysis 

(1) CHP Power to Heat Ratio kW e /kW th 

(2) Power 

0.106 

kW/(ton/hr Steam) 81.7 

Site Electricity Requirement MWh/yr 12,715 

Power Generating Capacity kW 408 

Electricity Generation MWh/yr 3,059 

Deficit(-)/Excess(+ ) Power MWh/yr -9,656 

(3) Heat 

Site Heat Requirement TJ/yr 158.0 

Heat Generation TJ/yr 103.4 

Heat Utilisation TJ/yr 103.4 

Deficit(-)/Excess(+ ) Heat TJ/yr -54.6 

(4) Fuel 

CHP Fuel Consumption TJ/yr 129.1 

Fuel Saving Compared with Conventional Production % 22.2


3. Financial Analysis 

Steam Turbine: Thermal Match 

Internal Rate of Return: % 24.3 

Net Present Value Peso 7,340,891 

Discounted Pay-back Period Year 7.41 

4. Summary: Steam Turbine, Thermal Match 

Technical Parameters 



Power Generating Capacity kW 408 

Steam Generating Capacity kg/hr 5,000 

Power to Heat Ratio 0.11 

Energy Analysis Results 


Excess (+ )/Deficit (-) Power MWh/yr -9,656 

Excess (+ )/ Deficit(-) Heat TJ/yr -55 

Financial Analysis Results 

Internal Rate of Return % 24.3 



5. What-if for Various Turbine Inlet Steam Pressure 

Turbine Inlet Excess(+ )/Deficit(-) Heat &Power Power Gener. Power/Heat Ratio 

Steam Pre. (bar) Heat (TJ/yr) Power (MWh/yr) Capacity (kW) kW/(ton/hr Steam) 

20 -55 -10,604 282 56.4 

30 -55 -10,073 353 70.5 

40 -55 -9,656 408 81.7 

50 -55 -9,340 451 90.1 

60 -55 -9,107 482 96.3 

70 -55 -8,938 504 100.9 

80 -55 -8,809 522 104.3 

Heat Demand to Be Met kg/hr 5,000 

Process Steam Pressure bar 7



(1) Economic Data 

Steam Turbine: Power Match 

Fuel Name OIL 





Boiler O & M Cost (% of Boiler Cost) % 5.0 

CHP O&M Cost (% of Total Installation Cost) % 2.0 

Escalation Rate for O & M Costs) % 5.0 






Power Demand to Be Met by CHP Boiler kW 1500 





(1). CHP Power to Heat Ratio kW e /kW th 

(2). Power 

0.11 




Deficit(-)/Excess(+ ) Power MWh/yr -1,480 

(3). Heat 


Heat Generating Capacity kg/hr 18,360 



Deficit(-)/Excess(+ ) Heat TJ/yr 183.8 

(4). Fuel 


Fuel Saving Compared with Conventional Production % 22.2



Steam Turbine: Power Match 

Internal Rate of Reture: % -3.6 

Net Present Value: Peso -40,797,044 

Discounted Pay-back Period Year >Service Life 

4. Summary: Steam Turbine, Power Match 




Power Generating Capacity kW 1,500 






Excess (+ )/ Deficit(-) Heat TJ/yr 184 


Internal Rate of Return % -3.6 

Net Present Value Peso -40,797,044 

Discounted Pay-back Period Year >Service Life 

5. What-if for Various Turbine Inlet Steam Pressure 

Turbine Inlet Excess(+ )/Deficit(-) Heat &Power Heat Gener. Power/Heat R 

Steam Pre. (bar) Heat (TJ/yr) Power (MWh/yr) Cap. (kg/hr) kW/(ton/hr Stm) 

20 337 -1,480 26,607 56.4 

30 238 -1,480 21,262 70.5 

40 184 -1,480 18,360 81.7 

50 152 -1,480 16,642 90.1 

60 132 -1,480 15,571 96.3 

70 119 -1,480 14,873 100.9 

80 110 -1,480 14,380 104.3 

Power Demand to Be Met kW 1500 

Process Steam Pressure bar 7



(1). Economic Data 

RECIPROCATING ENGINE: THERMAL MATCH 

Fuel Name Diesel 






CHP O&M Cost (% of Installation Costs) % 2.5 

Escalation Rate for O&M Costs % 5.0 






Heat Demand to Be Met by CHP Boiler kg/hr 5,000 

Steam Process Pressure Steam Pressure Bar 7 

Heat Recovery Steam Generator Efficiency % 65 



(1). CHP Power to Heat Ratio kW e /kW th 1.86 

(2). Power 

kW/(ton/hr Steam) 1,252 




Deficit(-)/Excess(+ ) Power MWh 34,161 

(3). Heat 




Deficit(-)/Excess(+ ) Heat TJ/yr -54.6 

(4). Fuel 


Fuel Saving Compared with Conventional Production % 30.3 



Net Present Value: Peso 16,712,528 


4. Summary: Reciprocating Engine, Thermal Match 








Excess (+ )/Deficit (-) Power MWh/yr 34,161 





Discounted Pay-back Period Year 12.73




RECIPROCATING ENGINE: POWER MATCH 














Power Demand to Be Met by CHP kW 1,500 


Heat Recovery Steam Generator Efficiency % 65 



(1). CHP Power to Heat Ratio 

(2). Power 

kW e /kW th 

1.86 




Deficit(-)/Excess(+) Power MWh -1,480 

(3). Heat 





Deficit(-)/Excess(+) Heat TJ/yr -133.2 

(4). Fuel 







4. Summary: Reciprocating Engine, Power Match 

















GAS TURBINE: THERMAL MATCH 














Heat Demand to be Met by CHP Boiler kg/hr 5,000 


Waste Heat Boiler Efficiency % 65.0 



(1) CHP Power to Heat Ratio kW e /kW th 0.74 

(2). Power 





Deficit(-)/Excess(+ ) Power MWh 5,958 

(3). Heat 

Site Heat Requirement TJ/yr 158 

Heat Generation TJ/yr 103 

Heat Utilisation TJ/yr 103 

Deficit(-)/Excess(+ ) Heat TJ/yr -55 

(4). Fuel 







4. Summary: Gas Turbine, Thermal Match 








Excess (+)/Deficit (-) Power MWh/yr 5,958 

Excess (+)/ Deficit(-) Heat TJ/yr -55 








GAS TURBINE: POWER MATCH 














Power Demand to be Met by CHP kW 1,500 


Waste Heat Boiler Efficiency % 65.0 



(1) CHP Power to Heat Ratio 

(2). Power 

kW e /kW th 

0.74 




Deficit(-)/Excess(+) Power MWh -1,480 

(3). Heat 





Deficit(-)/Excess(+) Heat TJ/yr -95.8 

(4). Fuel 







4. Summary: Gas Turbine, Power Match 















SENSITIVITY ANALYSIS 

STTM Steam Turbine, Thermal Match, Heat Being Met: 5000 kg/hr 

REPM Reciprocating Engine, Power Match. Power Being Met: 1500 kW 

Sensitivity Analysis 1: What-If the Investment Cost (IC) Increases? 

Increment Step 2.50% 

% Increase 0.0% 2.5% 5.0% 7.5% 10.0% 12.5% 15.0% 

STTM IC(Peso) 12222440 12528001 12833562 13139123 13444684 13750245 14055806 

IRR(STTM) 24.3% 23.7% 23.1% 22.6% 22.1% 21.5% 21.1% 

REPM IC(Peso) 48376832 49586253 50795674 52005095 53214516 54423936 55633357 

IRR(REPM) 19.6% 19.0% 18.5% 18.0% 17.6% 17.1% 16.7% 

Sensitivity Analysis 2: What-If the Fuel Price Increases? 

STTM 

REPM 

IRR 

28% 

25% 

23% 

20% 

18% 

15% 

13% 

10% 


IRR vs. Investment Cost 

IRR(STTM) 

IRR(REPM) 

0% 5% 10% 15% 20% 

% of Investment Increase 

Escalation Rate 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% 11.0% 12.0% 13.0% 

IRR(STTM) 24.3% 24.0% 23.6% 23.2% 22.7% 22.2% 21.7% 21.0% 20.3% 

IRR(REPM) 19.6% 19.1% 18.6% 18.1% 17.4% 16.7% 15.9% 14.9% 13.8% 

IRR 

30% 

25% 

20% 

15% 

10% 

5% 

IRR vs. Escalation Rate of Fuel Price 

IRR(STTM) 

IRR(REPM) 

5% 7% 9% 11% 13% 15% 

Escalation Rate of Fuel Price


SENSITIVITY ANALYSIS 

STTM Steam Turbine, Thermal Match, Heat Being Met: 5000 kg/hr 

REPM Reciprocating Engine, Power Match. Power Being Met: 1500 kW 

Sensitivity Analysis 3: What-If the Electricity Price Increases? 

STTM 

REPM 


Escalation Rate 6.0% 7.0% 8.0% 9.0% 10.0% 11.0% 12.0% 

IRR(STTM) 24.3% 25.6% 26.8% 28.0% 29.2% 30.4% 31.5% 

IRR(REPM) 19.6% 21.0% 22.3% 23.6% 24.9% 26.2% 27.5% 

IRR 

30% 

25% 

20% 

15% 

10% 

IRR vs. Escalation Rate of Electricity Price 

IRR(STTM) 

IRR(REPM) 

6% 8% 10% 12% 14% 

Escalation Rate of Electricity Price

Summary of country study – Bangladesh 131 

CHAPTER 3: SUMMARY OF COUNTRY STUDY - BANGLADESH 

3.1 Overview of Energy Situations, Policies & Strategies 

3.1.1 Overview of energy situation in Bangladesh 

The known conventional energy sources of Bangladesh are natural gas, coal, peat, oil, 

hydropower and biomass fuels. 

Natural gas 

Out of the non-renewable resources of energy, only natural gas is being extracted 

commercially. According to Bangladesh natural gas statistics as of October 1998, the total 

reserve of gas is 23.093 tcf (trillion cubic feet) of which 13.737 tcf is recoverable; 2.855 tcf 

had been extracted up to January 1977. During the last thirty years the Government has 

made consistent efforts in expanding the use of natural gas. Its share in total primary 

commercial fuels increased from 30.7 to 61.4 per cent during the period 1973 to 1997 

whereas the share of petroleum fuel consumption has decreased from 67.7 to 37.6 per cent 

for the same period. During the preparatory stage of formulation of the National Energy 

Policy, the constraints of natural gas supply beyond 2010 were highlighted to draw the 

attention of policy makers. Subsequently the government accepted the findings and allowed 

the participation of International Oil Companies (IOCs) in the exploration and development of 

hydrocarbon sector. 

Coal 

Coal resource deposits of about 1,782 million tons have been discovered in three locations. 

Total coal reserve at Jamalgonj is about 1,054 million tons whose extraction has not yet 

been found to be economically viable. About 285 million tons of coal deposit has been 

discovered in Dinajpur. Another coal reserve of 400 million tons has been discovered in 

Rangpur. Though there is no power plant operating with coal as fuel at present, coal mining 

from Barapukuria will probably take a significant part in electricity generation after 2000. 

More than 80 per cent of coal from Barapukuria is expected to be used in a 250 MW coalbased 

power plant. Total peat reserves of Bangladesh have been estimated as 600 million 

tons. In some rural areas, locally extracted peat is used for domestic cooking and in small 

industries. 

Oil 

A small oil deposit has been discovered in Haripur (Sylhet) with an estimated recoverable 

reserve of 1.6 million tons of crude oil. Indigenous oil supply makes very little contribution in 

meeting the total demand of petroleum fuels that is met from imported resources. 

Bangladesh Petroleum Corporation (BPC) is responsible for overall management of 

petroleum fuels in the country. 

Electricity 

Bangladesh Power Development Board (BPDB) is fully responsible for the electricity 

generation and distribution network in Bangladesh, except Dhaka city area and some rural 

areas which are managed by Dhaka Electric Supply Authority (DESA) and Rural 

Electrification Board (REB). Though the installed capacity is 3,091 MW, maximum 

generation on 28 July 1997 was only 1,600 MW against the maximum demand of 2,168 MW. 

On average, there is a shortfall of between 300 and 450 MW. Only about 19 per cent of total 

population are electrified at present. The demand for electricity is expected to rise at a rate 

of 15 per cent annually. Gas-based generation (especially combined cycle power plants) has


the least cost compared to other sources mentioned above, whereas the long-term 

perspective of alternative energy sources contributing to meet the power demand needs to 

be further studied. 

Hydropower 

Hydropower potential is still quite low in Bangladesh, because rivers are mostly on flat 

surfaces with low gradients. Presently, the only hydroelectric plant in the country (Karnafuli) 

has a capacity to produce 230 MW of electricity. There is a potential to produce 250 MW of 

power at Sangu and Matamuhuri river, though the cost of new storage is very high; such 

projects are not encouraged by the government considering their adverse environmental and 

social impacts. Fifteen prospective sites have been identified as having potential for on-site 

small hydropower generation. 

Solar 

Solar power utilization is being accepted gradually, but its slow progress is due to high initial 

cost, low daily operation time, and lower output level. Bangladesh is ideally located for 

tapping solar energy effectively (3 - 6 kWh/m 2 per day). Solar energy has been used in 

Bangladesh for drying crops and fishes since many decades. Bangladesh Atomic Energy 

Commission (BAEC) has commissioned pilot project for beacon lighting, refrigeration for 

vaccines storage, and water pumping. The Rural Electrification Board (REB) has introduced 

solar photovoltaic electricity in Narsingdi District. Government has waved duty and taxes on 

solar and other renewable energy applications to encourage both public and private sectors. 

Bangladesh University of Engineering Technology, Bangladesh Centre for Scientific and 

Industrial Research, Dhaka University and a few other organizations are continuing efforts to 

improve solar utilities in Bangladesh. 

Biomass and biogas 

Most of the rural people are fully dependent on biomass energy for their daily energy needs. 

It is estimated that as much as 70 per cent of total energy requirement in Bangladesh is met 

by biomass. Different forms of biomass-use include rice husk (26 per cent), cow dung (19 

per cent), rice straw (16 per cent), twigs and leaves (14 per cent), badges (7 per cent), fuel 

wood (5 per cent), and jute sticks (4 per cent). Because of the high rate of biomass use at 

present, there is serious concern about preservation of limited forests in the country and 

striking a balance between ecological, social and environmental needs. 

About 400 biogas plants have already been installed in different parts of the country. Limited 

success has resulted from high capital cost, insufficient supply of raw material and lack of 

maintenance support. 

3.1.2 Status and future prospect of electricity demand and supply 

BPDB with its meagre per capita generated capacity and limited coverage area had been 

serving its consumers fairly satisfactorily until 1990, after which the reserve margin fell, 

ultimately reaching a very low level in 1994. Though the 1985 Power System Master Plan 

Study called for addition of new generation to keep in pace with load growth, due to the 

unsatisfactory commercial operation, international donors virtually suspended all new 

lending to BPDB from 1990. On the other hand many of the power stations have outlived 

their economic life while some others are not functioning due to lack of timely maintenance. 

The problem was further aggravated with the gas supply constraint. There was a shortfall of 

about 300-450 MW during the summer of 1997, resulting in severe load shedding during 

peak hours. Real improvement of gas situation is expected when Sangu gas field will go in 

operation along with salna. Overall power supply situation is now gradually improving with 

the implementation of rehabilitation programme of old power stations. A number of private 

and public sponsored power plants are coming up to overcome the crisis.


3.1.3 Share of electricity use in industrial and commercial sectors 

Industrial and domestic sectors are the major consumers of electricity, accounting for 46 and 

38 per cent respectively in 1996-97, whereas the commercial sector has had a steady share 

of around 11 per cent over the last decade. With the industrialization, the share of industries 

has gone up from 39 to 46 per cent while that of domestic sector has gone down from 44 to 

38 per cent over a 10-year period. 

3.1.4 Status of industrial development and growth in energy Use 

The industrial development and growth of energy use is shown in Figure 3.1. Industrial 

development is expressed as industrialization ratio, which refers to share of value added of 

manufacturing and mining sectors to GDP at current prices (1992). Industrialization ratio of 

the country increased from 1975 to 1983, declined from 1983 to 1987 and has an increasing 

trend from the year 1989. Per capita energy consumption has increased continuously over 

the years. 

kgOE 

70 

60 

50 

40 

30 

20 

10 

0 

1973 75 77 79 81 83 85 87 89 91 

Per Capita Energy, (kgOE) Industrialization Ratio (%) 

Figure 3.1 Annual growth of energy use and industrialization ratio 

3.1.5 Prevailing costs of energy 

The different energy tariffs are summarized in Table 3.1. The industrial and commercial 

electricity tariffs given here do not include minimum charge, demand charge, service and 

other taxes. 

3.1.6 Government policies and strategies for private power generation 

In comparison to the 11,666 GWh electricity generated annually at present, the Power 

System Master Plan (PSMP) projects a requirement of 16,500 GWh in 2000 and 24,160 

GWh in 2005. This implies an increase in the peak demand from 2,200 MW presently to 

3,150 MW by 2000 and 4,600 MW by 2005 for which capacity addition of about 3,350 MW 

will be required by 2005. Hence, an average of 300 MW of generation capacity has to be 

added every year from 1998. At present load shedding has risen to the level of 300 MW 

causing more than 20 per cent of working hours to be wasted in the industries. This indicates 

the necessity of power generation in private sector. 

15 

10 

5 

0 

%


Table 3.1 Prevailing tariff for primary fuels and electricity 

Primary Fuels Electricity 

Type of fuel Market price (Taka)* Type of users Price (Taka/kWh) 

Natural gas 

1.68/m 

Furnace oil 

LDO 

HSD 

SKO 

Fuel wood 

3 

Small industries: 

flat rate 

4.51/litre off-peak hours 

peak hours 

11.89/litre Commercial: 

flat rate 

12.41/litre off-peak hours 

12.41/litre 

peak hours 

General use (11 kV): 

2/kg (average) 

flat rate 

off-peak hours 

peak hours 

* Exchange rate (1998): 1 US$ = 48 Taka 

3.30 

2.55 

4.75 

4.45 

3.10 

7.10 

3.10 

2.50 

5.75 

The Government is restructuring the power sector and promoting private sector participation 

in the generation of electricity for attaining higher economic efficiency. The Government is 

strongly committed to attract private investment for installing new power generation capacity 

on a Build-Own-Operate (BOO) basis. A Power Cell under the Ministry of Energy and 

Mineral Resources (MEMR) was created in 1995 to facilitate promotion, development, 

implementation, commissioning and operations of private power generation projects. The 

modalities for implementing private power project are as follows. 

Financing regulation 

The funds for the private power projects will be raised without any direct sovereign 

guarantee of repayment. The project sponsor(s) must look to the revenues earned by the 

sale of electricity for their returns on equity and debt servicing. Minimum requirement for 

equity investment will be 20 per cent. A Private Sector Infrastructure Development Fund 

(PSIDF) will be established and money would be available at market-based interest rates 

with extended maturity periods. As corporate debt securities market is essential for raising 

local financing for power development projects, provisions for corporate bonds, shares and 

tax facilities with the recognition by Securities and Exchange Commission (SEC) will be 

allowed. 

Security package 

Model Implementation Agreement (IA), Power Purchase Agreement (PPA) and Fuel Supply 

Agreement (FSA) will be prepared for private power projects to eliminate the need for 

protracted negotiations. The government will guarantee power purchase agreement for 

performance obligations of the concerned utilities and the performance of the fuel supplier, 

which is a public sector organization. For private power projects, protection will be provided 

against specific force major risk and changes in certain taxes and duties. 

Allocation of project/plant site and provision of fuel 

The government will select project/plant site in consultation with the investor/project sponsor, 

and determine the fuel, keeping in view the preference for indigenous resources but the use 

of imported fuels may also be allowed. Investors may be asked to bid for projects based on 

renewable and/or non-conventional sources of energy.


Tariff for bulk purchase of power at busbar 

The tariff structure would consist of two parts. In the solicited bids, the bidders shall offer 

bulk power tariff based on the capacity payment and energy payment and also provide the 

equivalent levelized tariff. The capacity payment will be made in Bangladeshi currency 

(Taka), but denominated in both Dollars and local currency. This will cover debt service, 

return on equity, fixed operation and maintenance cost, insurance and other fixed cost. The 

energy payment will be denominated in local currency to the extent to which the variable 

costs are in local currency. This will cover the variable costs of operation and maintenance, 

including fuel. 

Interconnection of IPP to transmission system: The power will be purchased from the IPP at 

a specified voltage and frequency at the outgoing terminal of the substation of the power 

plant. The cost of interconnecting facilities up to outgoing terminals of the private power 

project will be borne by the private power producers. 

Fiscal incentives 

The private power companies shall be exempted from corporate income tax for 15 years. 

Repatriation of equity along with dividends will be allowed freely. Income tax will be 

exempted for foreign companies. The foreign investors will be free to enter into joint ventures 

but this is optional and not mandatory. The companies will be allowed to import plant and 

equipment without payment of customs duties, VAT and any other surcharges. Private 

power companies will be exempted from the requirements of obtaining 

insurance/reinsurance only from the national Insurance Company and exempted from duty 

payments. Power generation companies are eligible for all concessions that are available to 

industrial projects. Private parties may raise local and foreign finance in accordance with 

regulations applicable to industrial projects as defined by the Board of Investment (BOI). 

Local engineering and manufacturing companies shall be encouraged to provide 

indigenously manufactured equipment of international standard to private power plants. 

Other facilities and incentives for foreign investors: Several other incentives extended by the 

government include tax exemption on royalties, technical assistance fees, and facilities for 

their repatriation; tax exemption on interest on foreign loans; tax exemption on capital gains 

from transfer of shares by the investing company; avoidance of double taxation in case of 

foreign investors on the basis of bilateral agreements; exemption of income tax for up to 3 

years for the expatriate personnel employed by the industry, etc. 

Starting from 1997, the government is considering to install a capacity of 1,500 MW through 

IPPs. Four agreements have so far been made, two of which are being implemented while 

several other projects are in the pipeline. An Independent Power Producer (IPP) is generally 

required to sign four contract agreements. These are the Power Purchase Agreement with 

BPDB; Implementation Agreement with the Government; Fuel Supply Agreement with the 

buyer and the supplier of fuel; Land Lease Agreement with the buyer. 

Many special features included in the IPP contract are very much in favour of the IPP, and 

are not extended to BPDB which is working presently with an installed generating capacity of 

2,900 MW. The tariff charges in some cases are above the international price.


3.2 Technical Potential for Cogeneration 

3.2.1 Identification of sub-sectors with cogeneration potential 

Industrial cogeneration is a vital part of any strategy designed to reduce emissions of carbon 

dioxide. The advantage of cogeneration is that it is available now, a true “no-regrets” 

technology justified in many applications on economic grounds alone. Cogeneration is a 

well-tried technology in Bangladesh, already meeting around 10 per cent of the total 

electricity requirements of Bangladesh. These include mainly industrial plants like fertilizer 

factories, sugar mills, paper mills, textile spinning mills, etc. 

Cogeneration of process steam and electricity is widely recognized to be one of the most 

important single measures for achieving energy savings in the industrial/commercial sector. 

After extensive site visits and surveys the following industrial and commercial sectors of the 

country were identified with cogeneration potential. 

Industrial Sectors: pharmaceutical industry, edible oil refinery, paper recycling mill, textile 

processing mill, textile spinning mill, jute mill, tobacco curing, food processing, tea estate, 

tannery plant, knitting and hosiery plant, soap and chemical industry, cement plant, food 

industry, ceramic industry, distillery plant, and industrial estate. 

Commercial Sectors: hotel, hospital, cinema hall, housing complex, shopping complex, and 

office complex. 

3.2.2 Existing cogeneration facilities in the country 

Cogeneration in textile spinning mill 

The company analyzed here is one of the largest spinning mills in Bangladesh, with a 

capacity to produce 70,230 spindles. It went into production in July 1992. At present the 

turnover is nearly 1,480 million Taka. The mill operates 24 hours a day, for 360 days a year. 

The mill requires both electrical energy and thermal energy for production. There are seven 

Waukesha Gas Generators in the mill, with a total generation capacity of 6.4 MW. Each 

generator has an electricity generation capacity of 920 kW. Electrical energy is mainly used 

to run different 3-phase motors. Besides, there are a few single-phase motors, fans, lights, 

heaters, etc. 

There is only one fire-tube boiler operating with natural gas as fuel, with a rated capacity to 

produce 1.5 ton/hour of steam at around 5 bar for the process. 

The mill opted for cogeneration due to the following reason. The ambient temperature in the 

processing section was very high, at around 40-45°C, making it difficult for people to work 

continuously at high temperatures. Moreover the quality of the product was affected as the 

machines were not running properly at high temperatures. On the other hand, the 

temperature of the exhaust gases from gas engine generator was around 500°C. The 

management of the mill incorporated two waste heat boiler so that about 5 ton/hour of steam 

generated at 6 bar is used to drive vapour absorption chillers. The chilled water produced 

with no energy cost decreases the air temperature in the production section from 42°C to 

20°C. As a result, total energy cost is reduced while ensuring reliability of power supply, 

reducing environment pollution and increasing overall efficiency. 

The power output from the generators and the cooling capacity of the two chillers as 

functions of time are presented in Figure 3.2 and 3.3.


kW 

5000 

4500 

4000 

3500 

3000 

2500 

2000 

1500 

1000 

500 

0 

6 

8 

10 

12 

14 

16 

18 

20 

22 

Time of the Day 

Figure 3.2 Power generation at the textile mill as a function of time 

Ton of Refrigeration 

590 

570 

550 

530 

510 

490 

470 

450 

6 

8 

10 

12 

14 

16 

Chiller-1 

Chiller-2 

18 

20 

Time of the Day 

Figure 3.3 Cooling provided by chillers as a function of time 

The management of the mills cites several advantages of the cogeneration plant, such as 

primary fuel savings, reduced energy costs, enhanced reliability of power supply, and 

reduced environment pollution. Following are the benefits from the process side: reduced 

lapping, reduced end breakage, improved product quality due to cleaner environment, 

reduced burnout of the motors. Moreover, turnover of technical staff has reduced 

considerably, workers feel less fatigued and there is reduced absenteeism. As a result, there 

is 30 per cent increase in overall productivity. 

The gas engine generator with vapour absorption chillers is found to be an effective 

performance enhancement option. The result of this specific study should encourage other 

process industries to look seriously into the prospects of opting for cogeneration in their 

respective plants. This will not only be rewarding to them, but also to the country as a whole 

22 

24 

24 

2 

2 

4 

4


since the indigenous energy sources will be exploited more rationally and the national power 

utility would have a lower burden of coping with the ever-increasing power demand. 

Cogeneration in sugar mill 

There are 15 sugar mills in Bangladesh. These mills are owned by the government but 

controlled and managed by 'Bangladesh Sugar and Food Industries Corporation (BSFIC)'. 

Sugarcane required by each mill is collected from its surrounding areas. The industry meets 

the major requirement of country's sugar. Sugar mills also produce molasses and bagasse, 

two very important by-products that are used as raw materials in distilleries and paper 

industry respectively. Bagasse is also the main fuel for sugar mill boilers, producing steam 

that is required in the manufacturing process of the mill. In 1993-94, these mills crushed 2.7 

million tons of cane, producing close to a million tons of bagasse. 

Data on installed capacity, cane crushed, turbine capacity, on-site power generation, power 

purchased, are shown in Table 3.2. 

Table 3.2 Data of sugar mills in Bangladesh for the milling season 1993-94 

No Sugar mills Installed 

capacity 

Cane 

crushed 


generating 

capacity 

Annual 

operation 

Power 

generated 

Power 

purchased 

(TCD) (ton) kW Days MWh MWh 

1 Panchagar 1,016 143,952 2,000 150 2,967 678 

2 Thakurgan 1,524 200,213 3,000 148 3,878 538 

3 Setabganj 1,250 135,872 4,000 114 3,838 631 

4 Shyampur 1,016 125,111 2,000 138 2,897 510 

5 Rangpur 1,321 154,421 2,600 131 3,879 462 

6 Jaypurhat 2,032 220,294 2,500 136 3,586 1,121 

7 Rajshahi 2,000 234,072 3,500 162 5,519 1,462 

8 Natore 1,500 263,941 4,000 167 5,972 786 

9 North Bengal 1,500 270,979 2,000 166 4,159 1,487 

10 Kushtia 1,524 162,325 3,000 130 3,104 855 

11 Carew 1,150 185,752 3,000 175 3,446 2,778 

12 Mobarakganj 1,500 218,985 2,000 156 1,888 736 

13 Faridpur 1,016 171,431 2,000 160 299 648 

14 Zeal Bangla 1,016 143,091 2,000 155 3138 739 

15 Deshbandu 300 16,674 500 67 564 178 

Total 19,665 2,647,113 38,100 49,134 13,610 

As most sugar mills have similar configurations, one of them is described here with more 

details. This mill has three water tube boilers, each with a steam generating capacity of 16 

ton/hr. The pressure and temperature of the steam are 15 kg/cm 2 and 246°C respectively. 

Bagasse is the primary source of which is burnt in boiler furnace to generate steam which in 

turn is used to drive steam turbine generators for electricity generation required for motor 

drives, driving mill drive turbines and for meeting process steam needs. One steam turbine 

generator is normally operated during milling season to meet the entire electric demand. 

One standby diesel generator is also available and run during emergency. Electricity is 

purchased from Bangladesh Power Development Board (BPDB) as required during cleaning 

days and during off-season. There are also two crusher drive steam turbines, each of 580 

HP capacity and two steam turbine generators, each of 1 MW capacity. 

About 30 tons/hour of steam is produced in the boiler that has an average efficiency of 56 

per cent. High-pressure steam is mainly used for steam turbine generator and crusher drive 

turbines. An automatic pressure reduction valve reduces steam from 15kg/cm 2 pressure to 3 

kg/cm 2 that is mainly used in centrifugals for purging molasses and washing/cleaning


heaters, evaporators and pans, etc. Turbine exhaust steam is used in processing juice, i.e. 

mainly heating purposes. Another automatic steam reduction valve reduces 3 kg/cm 2 steam 

to 1 kg/cm 2 to supply make up steam. Totally 80 per cent of the condensate is recovered 

and about 20 per cent make up water is needed for the boiler. During plant visit, it was 

observed that steam used in heating air of 6 forced air supply units of sugar dryer was being 

operated with an open bypass valve of traps causing live steam discharge to drains. 

Though all sugar mills have cogeneration facilities, they operate only during the season, i.e. 

150 days per year. If they can be operated during off-season by applying Balancing, 

Modernization, Rehabilitation & Expansion (BMRE) Programme, more power generated can 

alleviate the power shortage in the country. 

Most sugar factories have low-pressure (15 bar) boilers. By installing high-pressure boilers, 

these can produce more power efficiently. The choice of boiler pressure of 64 kg/cm 2 and 

above appears inevitable for mills intending to sell power to the national grid. Typically, a 

well-designed 2,500 tons crushed/day plant can sell 10 MW of power to national grid. 

There are several technical financial and institutional impediments to the use of energy 

efficient sugar mills, the most important ones being the policy initiatives and shortage of 

financial resources. In most sugar factories, there is a lack of sound technical management 

to maintain high-pressure boilers. The existing low-pressure boiler is itself not being 

maintained satisfactorily in most cases with the result that there are interruptions in crushing 

sugar cane. In any event, sugar being still a highly regulated industry, the management is 

occupied with sugar cane farmers, and the financial and administrative problems of 

producing and selling, and very few have the time to take up the additional responsibility of 

electricity cogeneration. 

Cogeneration with improved technology should be seriously considered in sugar factories of 

Bangladesh as it offers the following advantages: 

• It causes no pollution as the bagasse does not produce flash, or sulphur compared to coal 

used in a thermal plant; 

• It needs no foreign exchange as the machinery needed for cogeneration boilers, turbines, 

etc., is indigenously available; 

• It has a low gestation period of two years compared with four to six years of construction 

period for a coal-based thermal plant; 

• It has a much lower installation and recurring cost compared with a conventional fossil fired 

power plant; 

• It is small in size and is invariably in the rural area, so the transmission and distribution 

losses are minimal compared with any centralized plant requiring long lines of distribution; 

• It places no financial and administrative burden on the utility as it is executed and managed 

by the sugar factory; 

It improves the financial position of the sugar factory. 

Cogeneration in paper mill 

A newsprint paper mill having a steam turbine cogeneration facility is covered here. The mill 

presently generates 13.1 MW and purchases 2.5 MW from the utility grid to meet all the 

electrical energy needs of the site, including the residential zones. Furnace oil is used in 

boilers for steam generation. 

Steam generated at 42 bar and 400°C in three boilers with a total installed capacity of 161 

ton/hour, is mainly used in three backpressure turbines to generate electricity. After partial


expansion of the steam in turbine a significant amount of steam at 6 bar is used by paper 

machine and autoclaves. Presently, 13.1 MW is self-generated and a 2.5 MW is bought from 

the national grid to run the factory and provide residential lighting. The electrical and thermal 

energy data of the factory for the year 1994 are shown in Figures 3.4 and 3.5. 

MWh (Thousand) 

12 

10 

8 

6 

4 

2 

0 

Jan 

Feb 

Self Power Generation Purchased power 

Mar 

Apr 

May 

Jun 

Jul 

Month 

Figure 3.4 Electricity consumption data of the paper mill in 1994 

Thermal Energy (GJ) 

3500 

3000 

2500 

2000 

1500 

1000 

500 

0 

Jan 

Feb 

Mar 

Apr 

May 

Jun 

Jul 

Month 

Figure 3.5 Thermal energy consumption data of the paper mill in 1994 

Cogeneration in fertilizer plant 

This fertilizer factory is one of the largest in the country, with a capacity to produce over 1.8 

million tons of urea per year. Main energy source used in this fertilizer factory is natural gas 

that is used in boilers as fuel. Most of the electrical energy used in the fertilizer factory is 

self-generated and there is provision for buying electricity from the national grid. 

Aug 

Aug 

Sep 

Sep 

Oct 

Oct 

Nov 

Nov 

Dec 

Dec


The fertilizer factory has two boilers with capacities to produce 180 tons/hr and 171 ton/hr of 

steam, respectively. The steam generated at 60 bar and 510°C is mainly used in two 

backpressure steam turbines to generate up to 11 MW of electricity. After partial expansion 

in the turbine, steam at 10 bar is used for processing. Self-power generation and thermal 

energy consumption data of the factory are given in Figures 3.6 and 3.7, respectively. 

Self Power Gen. (MWh) 

8000 

7000 

6000 

5000 

4000 

3000 

2000 

1000 

0 

Jan 

Feb 

Mar 

Apr 

May 

Jun 

Jul 

Month 

Figure 3.6 Self-power generation data of the fertilizer factory in 1997 

Thermal Energy (GJ) 

700000 

600000 

500000 

400000 

300000 

200000 

100000 

0 

Jan 

Feb 

Mar 

Apr 

May 

Jun 

Jul 

Month 

Figure 3.7 Thermal energy consumption data of the fertilizer factory in 1997 

3.2.3 Assessment of the technical potential on the basis of questionnaire 

A survey of the different manufacturing and commercial facilities in the country using 

technical criteria as defined by ESCAP’s preliminary assessment questionnaire allowed to 

make a very rough estimation of the technical cogeneration potential in the different subsectors 

(see Table 3.3), which amounted to almost 1,000 MW. More precise determination 

would require more time and resources, which was beyond the scope of this study. 

Aug 

Aug 

Sep 

Sep 

Oct 

Oct 

Nov 

Nov 

Dec 

Dec


3.2.4 Identification of suitable sites for pre-feasibility study 

For the purposes of this pre-feasibility study, major energy consuming enterprises were 

identified in the following areas: industries (pharmaceutical, chemical, tobacco, edible oil, 

pulp and paper, textile processing and spinning, jute) and commercial buildings (hotel, 

hospital, cinema hall, housing and shopping complex, office). 

Information on their thermal and electrical energy consumption was collected through site 

visits and survey using a questionnaire. The selection process was based on screening and 

analysis of the energy usage pattern. The energy usage was analyzed in detail before 

assessing the pre-feasibility of cogeneration. Results of selected enterprises are presented 

in the following section. 

Table 3.3 Industrial and commercial cogeneration potential in Bangladesh 

No. Type of Activity No. of Assumed Average Installation Total 

Mills Potential of the Plant (MW) (MW) 

1 Textile Spinning Mills 50 2 100 

2 Textile Processing Mills 50 1 50 

3 Knitting & Hosiery Plant 50 0.6 30 

4 Jute Mills 70 1.5 105 

5 Paper Recycling Mills 14 3 42 

6 Soup & Chemical Industry 20 0.8 16 

7 Tannery 50 0.6 30 

8 Cement Mills 10 0.8 8 

9 Ceramic Industry 20 1.5 30 

10 Tea Gardens 180 0.9 162 

11 Food Industry 15 1 15 

12 Distillery 10 0.6 6 

13 Sugar Mills 

15 10 150 

(surplus generation) 

14 Industrial Estate 5 5 25 

15 Hotel 50 0.5 25 

16 Hospital 150 0.5 75 

17 Housing Complex 10 1 10 

18 Office Complex 150 0.5 75 

19 Export Processing Zone 5 5 25


3.3 Pre-feasibility Studies at Selected Industrial and Commercial Sites 

For the purpose of economic analysis, the total installed costs of the cogeneration plants 

were assumed as follows: steam turbines: US$ 1,200/kWe; gas turbines: US$ 1,000/kWe; 

and reciprocating engines: US$ 900/kWe. Some common financial data gathered or 

assumed before conducting the pre-feasibility studies are summarized in Table 3.4. 

Table 3.4 Financial data used for the pre-feasibility study 

Parameters Unit Value 

Exchange rate Taka/US$ 48.00 

Tax rate Per cent/year 35.00 

Discount rate Per cent/year 15.00 

Cogeneration plant service life Year 15.00 

Electricity purchase price Taka/kWh 3.60 

Electricity buy-back rate Per cent of purchase price 80 per cent 

Fuel price escalation rate Per cent/year 5.00 

Electricity price escalation rate Per cent/year 6.00 

Electricity stand-by rate Taka/kW.month 80.00 

Fuel purchase price (natural gas) Taka/m 3 

1.68 

3.3.1 Recycled paper mill 

This factory operates 24 hours a day and 350 days a year. Natural gas is used in boiler 

furnace for steam generation. The electrical energy is required to drive the motors. The rate 

of production is maintained up to the target level. 

Analysis of the monthly electricity and steam consumption in 1997 led to the following: 


• Maximum Electricity Demand: 3,100 kW 

• Minimum Electricity Demand: 2,750 kW 

• Total Steam Consumption in 1997: 69,386 tons 

• Maximum Steam Demand: 9.65 ton/hr 

• Minimum Steam Demand: 7.15 ton/hr 

The average power-to-heat ratios were found to be 0.52 in 1997. Typical cogeneration 

system for this site would be based on steam turbine. However, reciprocating engine, gas 

turbine cogeneration systems were also considered as potential alternatives. Results of the 

feasibility study are summarized in Table 3.5. 

Obviously, the steam turbine option does not seem feasible: (i) with steam turbine thermal 

match (STTM), less than 25 per cent of the power requirement is generated; (ii) with steam 

turbine power match (STPM), too much excess heat is generated. 

With the reciprocating engine thermal match (RETM) option, 200 per cent excess power is 

generated. The project profitability will depend on the buy-back rate. This may not be a good 

option as the purpose is not to earn from electricity sale. Reciprocating engine power match 

(REPM) option seems feasible as almost all the power needed can be met though an 

auxiliary boiler will be necessary to make up for the 30 per cent shortfall in the heat supply.


Table 3.5 Summary of pre-feasibility study of the recycled paper mill 

Major Parameters Steam Turbine Gas Engine Gas Turbine 

Thermal 

Match 

Power 

Match 

Therm 

al 

Match 

Power 

Match 

Therm 

al 

Match 

Power 

Match 

Installed power (kW) 582.00 2,750.00 9,047.00 2,750.00 3,872.00 2,750.00 

Fuel consumption (TJ/year) 197.00 930.20 856.90 260.50 444.90 316.00 

Electricity generated (MWh) 4,647.00 21,945.00 72,197.00 21,945.00 30,889.00 21,945.00 

Heat generated (TJ/year) 157.90 745.90 157.90 48.00 157.90 112.20 

Excess/deficit(-) power (MWh/year) -18,765.00 -1,467.00 48,785.00 -1,469.00 7,487.00 1,467.00 

Excess/deficit(-) heat (TJ/year) -4.10 509.30 -4.10 -114.00 -4.10 -49.80 

Equipment power-to-heat ratio 0.106 0.11 1.87 1.87 0.80 0.80 

Total investment (million Taka) 33.54 158.40 390.84 118.80 185.86 132.00 

Net present value (million Taka) 43.28 68.05 56.20 225.05 273.09 213.44 

IRR (per cent) 34.00 21.70 35.90 41.90 36.30 38.30 

With gas turbine thermal match (GTTM) option, about 30 per cent excess electricity is 

generated which may be acceptable. Gas turbine power match (GTPM) option is also good 

as the 30 per cent deficit in the heat supplied can be met by auxiliary natural gas firing in the 

recovery boiler. 

Accordingly, sensitivity analysis done to see the impacts of the increase in the investment, 

fuel and electricity price escalation, was limited to REPM, GTTM and GTPM options. 

What if the investment cost increases? 

What if the fuel price escalates faster? 

Int 

er 

na 

l 

42% 

40% 

Ra(IR 

38% 

te R) 36% 

of 

Re 

tur 

34% 

32% 

REPM 

GTPM 

n 30% 

1% 3% 5% 8% 10% 13% 15% 

Internal Rate of Return 

(IRR) 

40.0% 

35.0% 

30.0% 

25.0% 

5. 

0 

% 

% of Increase Investment Cost 

6. 

0 

% 

7. 

0 

% 

REPM 

GTPM 

GTTM 

8. 

0 

% 

9. 

0 

% 

10 

.0 

% 

11 

.0 

% 

Fuel Price Escalation Rate 

12 

.0 

% 

13 

.0 

%


What if the electricity price escalates faster? 


50% 

45% 

40% 

35% 

30% 

REPM 

GTPM 

GTTM 

6% 7% 8% 9% 10% 11% 12% 13% 

Electricity Price Escalation Rate 

From the sensitivity analysis of the potential cogeneration alternatives for the recycled paper 

mill, the reciprocating engine power match option meeting power requirement of 2750 kW is 

found to be the most suitable cogeneration system. It represents an initial investment of 118 

Million Taka and leads to an internal rate of return of 41.9 per cent. 

3.3.2 Vegetable oil refinery 

This factory operates 24 hours a day and 340 days a year. Natural gas is used in boiler to 

generate steam that is required for the process. Energy alone accounts for 35 per cent of the 

production cost. 

Analysis of the monthly electricity and steam consumption in 1997 led to the following: 


• Maximum Electricity Demand: 650 kW 

• Minimum Electricity Demand: 510 kW 

• Total Steam Consumption in 1997: 12,260 tons 

• Maximum Steam Demand 1.68 ton/hr 

Minimum Steam Demand: 1.43 ton/hr 

The average power-to-heat ratio was 0.53 in 1997. Typical cogeneration system for this site 

would be based on steam turbine, though its size will be quite small. However, reciprocating 

engine, gas turbine cogeneration systems were also considered as potential alternatives. 

Results of the feasibility study are summarized in Table 3.6. 

Obviously, the steam turbine option does not seem feasible: (i) with steam turbine thermal 

match (STTM), less than 20 per cent of the power requirement is met; (ii) with steam turbine 

power match (STPM), 300 per cent excess heat is generated. 




(REPM) option seems feasible as almost all the power needed can be met though an 

auxiliary boiler will be necessary to make up for the 30 per cent shortfall in the heat supply.


Table 3.6 Summary of pre-feasibility study of the vegetable oil refinery 


Thermal 

Match 

Power 

Match 

Thermal 

Match 

Power 

Match 

Thermal 

Match 

Power 

Match 

Installed power (kW) 101.00 520.00 1,804.00 520.00 772.00 520.00 


Electricity generated (MWh) 771.00 3,984.00 13,819.00 3,984.00 5,914.00 3,984.00 


Excess/deficit(-) power (MWh/year) -3,458.00 -245.00 9,950.00 -245.00 1,685.00 -245.00 

Excess/deficit(-) heat (TJ/year) 1.60 112.00 1.60 -19.90 1.60 -8.30 




IRR (per cent) 31.90 18.30 34.30 40.30 34.40 36.80 


generated which may be acceptable. Gas turbine power match (GTPM) option is also good 

as the 30 per cent deficit in the heat supplied can be met by auxiliary natural gas firing in the 

recovery boiler. 

Accordingly, the sensitivity analysis carried out to see the impacts of the increase in the 

investment, fuel and electricity price escalation, was limited to REPM, GTTM and GTPM 

options. 


45% 

40% 

35% 

30% 

25% 



REPM 

GTPM 

GTTM 

20% 

1% 2.50% 5% 7.50% 10% 12.50% 15% 

Internal Rate of Return (IRR) 

45% 

40% 

35% 

30% 

% of Increase Invesrment Cost 

REPM 

GTPM 

GTTM 

25% 

5% 6% 7% 8% 9% 10% 11% 12% 13% 

Escalation Rate of Fuel Price



Internal Rate of Return (IRR) 

50% 

45% 

40% 

35% 

30% 

6% 7% 8% 9% 10% 11% 12% 13% 

Escalation Rate of Electricity Price 

From the sensitivity analysis of the potential cogeneration alternatives for the vegetable oil 

refinery, the reciprocating engine power match option meeting power requirement of 520 kW 

is found to be the most suitable cogeneration system. It represents an initial investment of 22 


3.3.3 Textile spinning mill 

This factory operates 24 hours a day and 350 days a year. Natural gas is used in boiler to 

generate steam that is required for the process. The production is greatly affected by any 

fluctuations or micro-cuts in the power supply. 

Analysis of the monthly electricity and steam consumption data of 1997 led to the following: 




• Total Thermal Energy Consumption in 1997: 66 TJ 



The power-to-heat ratio of the site was estimated as 1.1 for 1997. Typical cogeneration 

system for this site would be based on reciprocating engine. However, steam turbine and 

gas turbine cogeneration systems were also considered as potential alternatives. Results of 

the feasibility study are summarized in Table 3.7. 

As expected, the steam turbine option is not suitable: (i) with steam turbine thermal match 

(STTM), less than 10 per cent of the power requirement is met; (ii) with steam turbine power 

match (STPM), 770 per cent excess heat is generated. 




(REPM) option seems feasible as almost all the power requirement can be met though the 

heat generated is largely inadequate to meet the demand. An auxiliary boiler will be 

necessary to make up for over 65 per cent shortfall in the heat supply. 

REPM 

GTPM 

GTTM


Table 3.7 Summary of pre-feasibility study of the textile spinning mill 


Therm 

al 

Match 

Power 

Match 

Therm 

al 

Match 

Power 

Match 

Therm 

al 

Match 

Power 

Match 

Installed power (kW) 263.00 2,350.00 4,080.00 2,350.00 1,746.00 2,350.00 



Heat generated (TJ/year) -17,974.00 -1,316.00 12,486.00 -1,316.00 -6,136.00 -1,316.00 

Excess/deficit(-) power (MWh/year) 71.20 637.40 71.20 41.00 71.20 95.90 

Excess/deficit(-) heat (TJ/year) 5.20 507.60 5.00 -25.00 5.20 29.90 




IRR (per cent) 32.80 19.90 38.40 41.90 38.10 37.40 

With gas turbine thermal match (GTTM) option, about 30 per cent less electricity are 

generated. Gas turbine power match (GTPM) option takes care of all the power and heat 

needs but around 46 per cent of excess heat are generated which has no commercial value. 


investment, fuel and electricity price escalation, was limited to REPM and GTPM options. 



(IRR) 

42% 

40% 

38% 

36% 

34% 

32% 

30% 



41% 

40% 

39% 

38% 

37% 

36% 

35% 

REPM 

GTPM 

1% 3% 5% 8% 10% 13% 15% 


REPM 

GTPM 

5% 6% 7% 8% 9% 10% 11% 12% 13% 

Fuel Price Escalation Rate




(IRR) 

49% 

47% 

45% 

43% 

41% 

39% 

37% 

35% 

REPM 

GTPM 

6% 7% 8% 9% 10% 11% 12% 13% 

% of Increase Fuel Price Escalation Rate 

From the sensitivity analysis of the potential cogeneration alternatives for the textile spinning 

mill, the reciprocating engine power match option meeting power requirement of 2,350 kW is 

found to be the most suitable cogeneration system. It represents an initial investment of 102 


3.3.4 Textile processing mill 

This factory operates 24 hours a day, for 340 days a year. Natural gas is used in boiler to 

generate steam that is required for the process. The production process is sensitive to any 

fluctuations in the power supply or power failures. 





• Total Thermal Energy Consumption in 1997: 89.3 TJ 



The power-to-heat ratio of the site was estimated as 0.3 for 1997. Typical cogeneration 

system for this site would be based on steam turbine. However, reciprocating engine and 

gas turbine cogeneration systems were also considered as potential alternatives. Results of 

the feasibility study are summarized in Table 3.8. 

The steam turbine option is found to be not suitable: (i) with steam turbine thermal match 

(STTM), less than 20 per cent of the power requirement is met; (ii) with steam turbine power 

match (STPM), 90 per cent excess power and 170 per cent excess heat are generated. 




(REPM) option seems feasible as almost all the power needed can be met though the heat 

generated meets up to 80 per cent of the demand. An auxiliary boiler will be necessary to 

make up for the remaining 20 per cent shortfall in the heat supply.


Table 3.8 Summary of pre-feasibility study of the textile spinning mill 


Ther 

mal 

Match 

Powe 

r 

Match 

Therma 

l Match 

Powe 

r 

Match 

Therm 

al 

Match 

Powe 

r 

Match 

Installed power (kW) 238.00 875.00 4,157.00 875.00 1,843.00 875.00 





Excess/deficit(-) heat (TJ/year) -16.30 151.80 -16.30 -73.90 -16.30 -54.60 




IRR (per cent) 33.20 21.30 34.10 40.80 33.40 37.20 


generated. Gas turbine power match (GTPM) option takes care of all the power needs 

though heat deficit is as high as 60 per cent. This will require the adoption of auxiliary natural 

gas firing in the recovery boiler. The total installation cost of GTPM is 50 per cent less than 

that for GTTM. 





(IRR) 

42% 

40% 

38% 

36% 

34% 

32% 

30% 



41% 

40% 

39% 

38% 

37% 

36% 

35% 

REPM 

GTPM 

1% 3% 5% 8% 10% 13% 15% 


REPM 

GTPM 

5% 6% 7% 8% 9% 10% 11% 12% 13% 





(IRR) 

49% 

47% 

45% 

43% 

41% 

39% 

37% 

35% 

REPM 

GTPM 

6% 7% 8% 9% 10% 11% 12% 13% 


From the sensitivity analysis of the potential cogeneration alternatives for the textile 

processing mill, the reciprocating engine power match option meeting power requirement of 

875 kW is found to be the most suitable cogeneration system. It represents an initial 

investment of 37 Million Taka and leads to an internal rate of return of 40.8 per cent. 

3.3.5 Hospital 

This hospital operates throughout the year without any stop. Electricity is required for 

lighting, air conditioning and motors whereas as a lot of thermal energy is needed in the form 

of steam for various applications. 





• Total Thermal Energy Consumption in 1997: 91.5 TJ 



The power-to-heat ratio of the site was calculated to be 0.68 for 1997. Typical cogeneration 

system suitable for this site would be based on gas turbine. However, reciprocating engine 

and steam turbine cogeneration systems were also considered as potential alternatives. 



(STTM), less than 30 per cent of the power requirement is generated and the hospital will 

have to depend heavily on the utility grid; (ii) with steam turbine power match (STPM), 119 

per cent excess heat are generated which has no commercial value. 




(REPM) option seems feasible as almost all the power needed can be met though there will 

be small (16 per cent) shortage in the heat supply. There is no need for an auxiliary boiler as 

this shortfall can be easily made up by auxiliary natural gas firing in the recovery boiler.


Table 3.9 Summary of pre-feasibility study of the hospital 


Ther 

mal 

Match 

Power 

Match 

Thermal 

Match 

Power 

Match 

Therm 

al 

Match 

Powe 

r 

Match 




Heat generated (TJ/year) 89.50 22,308.00 89.50 14.60 89.60 34.00 


Excess/deficit(-) heat (TJ/year) -2.00 109.60 -2.00 -76.90 2.00 -57.60 

Equipment power-to-heat ratio 0.107 0.11 1.870 1.87 .80 0.80 



IRR (per cent) 35.20 26.00 35.90 43.50 34.80 39.80 


generated, which has to be sold as in the RETM option. Gas turbine power match (GTPM) 

option takes care of all the power needs though heat deficit is as high as 60 per cent. This 

will require the adoption of auxiliary natural gas firing in the recovery boiler. 





(IRR) 

42% 

40% 

38% 

36% 

34% 

32% 

30% 



41% 

40% 

39% 

38% 

37% 

36% 

35% 

REPM 

GTPM 

1% 3% 5% 8% 10% 13% 15% 


REPM 

GTPM 

5% 6% 7% 8% 9% 10% 11% 12% 13% 





(IRR) 

49% 

47% 

45% 

43% 

41% 

39% 

37% 

35% 

REPM 

GTPM 

6% 7% 8% 9% 10% 11% 12% 13% 


From the sensitivity analysis of the potential cogeneration alternatives for the hospital, the 

reciprocating engine power match option meeting power requirement of 800 kW is found to 

be the most suitable cogeneration system. It represents an initial investment of 35.6 Million 

Taka and leads to an internal rate of return of 43.5 per cent. 

3.3.5 Hotel 

This hotel operates throughout the year. Electricity is required for lighting, air conditioning 

and motors, and a lot of steam is required for various applications. 





• Total Thermal Energy Consumption in 1997: 137 TJ 



The power-to-heat ratio of the site was calculated to be 0.23 for 1997. Typical cogeneration 

system suitable for this site would be based on steam turbine. However, reciprocating 

engine and gas turbine cogeneration systems were also considered as potential alternatives. 



(STTM), less than 65 per cent of the power requirement is generated and the hotel will have 

to depend on the utility grid; (ii) with steam turbine power match (STPM), only a small 

amount of excess heat is generated. 




(REPM) option seems good as almost all the power needed can be met though there will be 

small (15 per cent) shortage in the heat supply. There is no need for an auxiliary boiler as 

this shortfall can be easily made up by auxiliary natural gas firing in the recovery boiler.


Table 3.10 Summary of pre-feasibility study of the hotel 


Ther 

mal 

Match 

Powe 

r 

Match 

Therm 

al 

Match 

Powe 

r 

Match 

Therm 

al 

Match 

Powe 

r 

Match 


Fuel consumption (TJ/year) 230.00 317.50 1,001.50 88.90 520.00 107.90 



Excess/deficit(-) power (MWh/year) -3,149.00 -1,090.00 75,796.00 -1,090.00 27,532.00 -1,090.00 

Excess/deficit(-) heat (TJ/year) 47.00 92.10 47.60 -120.60 47.60 -98.70 




IRR (per cent) 31.20 28.00 34.90 43.50 32.60 39.80 


generated, which has to be sold as in the RETM option. Gas turbine power match (GTPM) 

option takes care of all the power needs though heat deficit is as high as 60 per cent. This 

will require the adoption of auxiliary natural gas firing in the recovery boiler. 


investment, fuel and electricity price escalation, was limited to STPM, REPM and GTPM 

options. 



(IRR) 

42% 

40% 

38% 

36% 

34% 

32% 

30% 



41% 

40% 

39% 

38% 

37% 

36% 

35% 

REPM 

GTPM 

1% 3% 5% 8% 10% 13% 15% 


REPM 

GTPM 

5% 6% 7% 8% 9% 10% 11% 12% 13% 





(IRR) 

49% 

47% 

45% 

43% 

41% 

39% 

37% 

35% 

REPM 

GTPM 

6% 7% 8% 9% 10% 11% 12% 13% 


From the sensitivity analysis of the potential cogeneration alternatives for the hospital, the 

reciprocating engine power match option meeting power requirement of 800 kW is found to 

be the most suitable cogeneration system. It represents an initial investment of 35.6 Million 

Taka and leads to an internal rate of return of 43.5 per cent.


3.4 Conclusions and Recommendations for Follow-up Actions 1 

Conclusion 

From the pre-feasibility study of the selected sites, one can conclude that thanks to the 

availability of natural gas distribution network in some economic areas, gas-based 

cogeneration is found to be the most cost-effective option for Bangladesh. In view of the 

present national power situation, cogeneration in sites having a steady need for heat and 

power, and access to natural gas, can improve the production reliability and efficiency while 

reducing the burden on the already stressed national grid. Moreover, natural gas-based 

cogeneration will reduce the dependency on imported fuel and will have less adverse impact 

on the environment. 

Power demand in many sites is not very high, ranging from 0.5 to 2 MW. These sites are 

ideal for gas-based reciprocating engines that already have a good presence in the local 

market. The internal rates of return in all the cases were found to be quite high (above 40 

per cent) for the best feasible options, mainly due to the low price of gas prevailing in the 

country. 

In spite of the significant techno-economic potential for cogeneration applications in 

Bangladesh, cogeneration has not been widely adopted in the country due to several 

reasons. The foremost among them is the low level of awareness at all levels about the 

technological alternatives, economic merits, environmental benefits and business 

opportunities related to the application of cogeneration as an efficient energy use option. No 

systematic study has been undertaken so far to assess cogeneration potential by taking into 

account factors such as energy demand patterns, plant size, power-to-heat ratio, access to 

gas pipeline, etc. There is practically no interaction between the energy utilities and the 

energy users to explore the cogeneration option though the government is serious about 

encouraging private investment in the power sector. 

Recommendation for follow-up actions 

Since cogeneration development seems to be very promising, the hurdles (institutional 

structure, policy and planning, energy pricing and tariff, investment and financing etc.) in this 

sector may be removed for its further propagation. 

Regulatory measures are needed for the sale of excess electricity to the grid or third party, 

and back-up power supply from the grid as and when necessary. 

The establishment of a national interagency co-ordinating committee may be seriously 

considered. Government may also initiate demonstration projects using advanced 

technologies in selected public sector enterprise in the industrial estates/export processing 

zones/satellite city centres. 

State energy suppliers (electricity and gas companies) may play a greater role in the 

propagation of cogeneration by establishing partnership with potential cogenerators, public 

or private, in making investment, guaranteeing operation and maintenance, and sharing 

costs and benefits in the process. 

1 These conclusions and recommendations are based on the deliberations of participants in the 

South Asia Sub-Regional Seminar organized at Dhaka on 14 and 15 November 1998. The 

programme details of the Seminars are included in Appendix 3A.


Alternative financing may include third-party participation, leasing, soft loan, bilateral and 

international funds targeted towards global environmental protection (e.g. clean development 

mechanism, joint implementation, special environmental Yen loan, global environmental 

fund). 

More incentives such as quick depreciation, soft loan, tax benefits, etc., should be extended 

to those cogeneration projects that satisfy well-specified technical, economic and 

environmental criteria. 

An energy conservation act may be established with a view to emphasizing on use of 

cogeneration and development of energy efficient technologies. To promote cogeneration 

technology, there should be a separate cell under the Ministry of Energy and Mineral 

Resources who will look after and will publish information regarding cogeneration regularly. 

There is a need for introducing courses on renewable energy and cogeneration in the 

curriculum of technical education in Bangladesh for development of long-term human 

resources. Large-scale training programme may be contemplated for involvement of national 

institutions on different aspects of cogeneration. Workshops, seminars and information 

exchanges are necessary on specialized topics, such as feasibility study, site selection, 

equipment design, financing and resource management. 

A comprehensive survey and pre feasibility study should be undertaken for developing an 

implementation plan. Feasibility studies for cogeneration should be made immediately for all 

the identified schemes and priorities should be set for their implementation. A cogeneration 

programme should be incorporated with all suitable existing future projects in Bangladesh. 

International cooperation through bilateral agreements for technical and financial assistance 

would be helpful and should be sought.


APPENDIX 3.A 

Programme of the South Asia Sub-Regional Seminar on 

ROLE OF COGENERATION IN THE NATIONAL ENERGY SCENARIO: 

PERSPECTIVES FOR ENERGY POLICY 

Date: Saturday, 14 November 1998 

Place: Bangladesh University of Engineering Technology (BUET), Dhaka, 

Bangladesh 

Organiser: Centre for Energy Studies and Mechanical Engineering Department (BUET), 

in Collaboration with Economic and Social Commission for Asia and the 

Pacific (ESCAP) 

Sponsor: Government of Japan 

08h00-08h45 Registration 

08h45-09h30 Official opening 

“Message from ESCAP” 

Mr. Pranesh C. Saha (Chief of Energy Resources Section, ESCAP) 

09h30-10h00 “Economic and Environmental Benefits of Cogeneration Applications” 

Dr. B. Mohanty (Cogeneration expert) 

10h00-10h30 “Use of Cogeneration in Japanese Industries” 

10h30-10h50 Tea Break 

Mr. Akira Ishiyama (JICA/ESCAP Expert on Energy Conservation) 

10h50-12h00 “Potential for Use of Cogeneration in the Industrial Sector in Bangladesh” 

National Study Team of Bangladesh 

12h00-12h45 “Regulatory Framework for Promoting Cogeneration” 

Panel discussion with policy makers and industry representatives 

12h45-14h30 Prayer and Lunch 

14h30-16h00 “Experiences with Promotion of Cogeneration in South Asia” 

Mr. A. S. Bakshi (Ministry of Power, India) 

Mr. R. Ghimire (Water and Energy Commission, Nepal) 

16h00-16h30 Summary and Conclusion 


17h00-18h00 Tour of the exhibition on Energy Technology


Programme of the South Asia Sub-Regional Seminar on 

Date: Sunday, 15 November 1998 

BUSINESS OPPORTUNITIES IN COGENERATION 

Place: Bangladesh University of Engineering Technology (BUET), Dhaka, 

Bangladesh 

Organiser: Centre for Energy Studies and Mechanical Engineering Department (BUET), 

in Collaboration with Economic and Social Commission for Asia and the 

Pacific (ESCAP) 




Introductory Statement by ESCAP 


09h30-10h00 “Business Potentials and Trends in Use of Cogeneration in Industry” 


10h00-11h00 “Results of Pre-feasibility Studies in Selected Industries in Bangladesh” 


National Study Team from Bangladesh 

11h30-13h00 “Cogeneration Case Studies from South Asian Countries” 

Mr. A. S. Bakshi (Ministry of Power, India) 

Mr. R. Ghimire (Water and Energy Commission, Nepal) 

13h00-13h30 “Prospects for Cogeneration Development in Bangladesh” 

Discussions and Conclusion 

13h30-15h00 Prayer and Lunch 

15h00-16h30 Optional: “Individual Consultations” 

Potential cogenerators from industries, manufacturers, suppliers, 

developers, financiers, consultants, etc.

Summary of country study – Viet Nam 

CHAPTER 4: SUMMARY OF COUNTRY STUDY – VIET NAM 

4.1 Overview of Energy Situations, Policies & Strategies 

4.1.1 Overview of energy situation in Viet Nam 

Viet Nam is endowed with considerable primary energy resources. However, the government 

now faces with the severe problem of the lack of investment capital for exploitation and 

production of energy from the available resources. 

Energy is an infrastructure sector that requires certain priority for investment. Presently, this 

sector is mostly under the management of the government. 

Oil and gas sector 

Since there is no refining facility in the country, all the crude oil is now exported and the 

domestic demand for oil products is satisfied by import. 

Natural gas is considered the strategic fuel for power generation in the future. Most of 

exploited natural gas is now used for power generation. It is planned to develop the LPG and 

petrochemical industry with gas as input fuel. 

Coal 

Only in recent years, the output of coal has been increased to reach the designed capacity of 

10 million tons per annum. The main consumers of coal are the process industries, followed 

by the power sector. The future development of the sector will depend heavily on alternative 

sources of energy (notably, natural gas) for power generation, as well as on Viet Nam’s ability 

to obtain a greater share in world market through a cost reduction in coal transportation. 

Power sector 

The current situation of the power sector in Viet Nam can be summarized as follows: 

• The actual demand for electricity has been growing at a much more rapid rate than that 

forecasted; 

• The unbalance between power sources development and power network development 

contributes partially to the low power supply reliability; 

• The big share of hydroelectricity in total electricity generation leads to poor power supply 

security in the dry season; 

• The thermal power plants have low efficiencies, of the order of 25-26 per cent; 

• Transmission and distribution losses are high, representing approximately 20 per cent of 

the total power output. 

Because of power shortage in dry season, gas turbine combined cycle (GTCC) power plants 

were urgently introduced in 1992 and in early 1994. Power generation in period 1991-1997 

experienced high growth rate of 13 per cent per annum on an average. The generation from 

gas turbine (GT) grew fastest due to the policy to reduce the share of hydropower. 

161


4.1.2 Status and future prospect of electricity demand and supply 

Electricity shortage is now a big problem in the power sector. Many industrial consumers 

have prepared themselves for power interruptions with stand-by self-generating units; in 

some cases, even independent power plants have been commissioned for big industrial 

consumers such as centralized industrial zones (CIZ) or export processing zones (EPZ). 

In the period up to 2010, new power plants will be of different types in each region: coal (and 

hydro) in the North, gas (combined cycle) in the South, and hydro in the Central region. To 

alleviate the burden of investment capital on the government, the two considered ways are 

purchasing electricity from independent power producers (IPP) or using electricity from Build- 

Operate-Transfer (BOT) schemes. 

Despite efforts by the Government, according to a prediction made by the Electricity of Viet 

Nam (EVN), a serious electricity shortage, estimated to range from 400 GWh to 1 TWh, will 

take place in 1999 in Viet Nam. The EVN planned to buy approximately 100 GWh of electricity 

from industrial factories as well as centralized industrial parks (CIP) or industrial processing 

zones (IPZ). Thus, the capacity deficit could be estimated as between 200 and 500 MW. 

4.1.3 Prevailing Costs of Energy 

In Viet Nam, the prices of coal and electricity have been lower than their costs of production, 

mainly due to the subsidy extended by the government. 

The government has followed a strategy of fixing maximum bulk and retail prices of oil and oil 

products on the basis of CIF cost of imported products, plus a distribution margin and taxes. 

Oil and oil products prices depend strongly on the exchange rate variation. 

The retail price of electricity in industry has been adjusted recently with the introduction of the 

Value Added Tax (VAT) from January 1999 (see Table 4.1). However, the electricity tariff 

applied to foreign companies is higher, US$0.11/kWh. The capacity charge is so far not 

applied in Viet Nam although there is a registered capacity charge for big industrial 

consumers. The factory should not have a greater demand than the registered capacity 

during the peak period to avoid any power cut-off. 

The time-of-day tariff has just been introduced in the industry and commercial sector in Viet 

Nam but is not widely practised. Before January 1999, the price of electricity during the utility 

peak period was double that of the normal period whereas the price during off-peak period 

was 25 per cent lower than that of the normal period. However, with the introduction of VAT, 

the new time-of-day tariff is being adjusted and the power company EVN has yet to make a 

clear announcement. 

Table 4.1 Electricity tariff before and after introduction of VAT 

Price before VAT Price after VAT Price of 1998 

VND/kWh* VND/kWh VND/kWh 

1. Normal period (110 kV) 636 699.6 700 

2. Normal period (20 kV to


4.1.4 Government policies and strategies for private power generation 

According to the Ministry of Planning and Investment, the private power generation that is 

considered as an infrastructure development activity, is given a favoured status and is 

promoted by the government. The power generation sector can get the priority of foreign 

currency exchange for the purpose of transfer of profits made by foreign investors. 

In Viet Nam, big power plants can be developed through various forms of investment: Build- 

Operate-Transfer, credit from supplier, self-development by Vietnamese companies (e.g. 

EVN and VINACOAL) in collaboration with foreign companies. 

However, the development of big private power plant is quite complicated and there is a lot of 

competition. Small and medium scale private power generating units, including cogeneration 

plant, inside industrial parks, export-processing zones or combined with industrial factories 

seem to be more suitable for Viet Nam. 

Security Package 

For the big power plants, the international conditions and practices are respected. Model 

Implementation Agreement, Fuel Supply Agreement are prepared. The Government 

guarantees power purchase agreement obligations of the concerned utilities. For small and 

medium-scale private power plants, there is no such fixed model now. So far, EVN has 

bought electricity from some sugar mills and is negotiating to buy excess electricity from 

paper mills on the basis of energy charge alone (without any payment for capacity charge). 

Tariff for bulk purchase of power at busbar 

The selling price of electricity from small and medium private power plants varies from one 

case to another. 

EVN can now accept to buy off excess electricity from small power producers with a daily 

spot tariff as follows: US$ 0.05/kWh during peak load, US$ 0.04/kWh during normal hours 

and US$ 0.03/kWh during off-peak hours. However, the capacity charge is not mentioned. 

For big power plants, EVN and the National Committee of Price must approve the purchase 

tariff of electricity. Small and medium scale plants can sell electricity directly to factories or 

industrial park but the Provincial Authority must approve the tariff. The electricity produced in 

excess can be sold to EVN at a negotiated price, without capacity charge, which is often 

around 70 per cent of EVN’s electricity selling price. In some existing cases, EVN accepts a 

price of around US$ 0.043/kWh. In an interview done in Mekong Delta, the Provincial 

Electricity Company consented to buy electricity at around 600 VND/kWh. 

So far, there is no effective legal system in Viet Nam to oblige electricity utilities to purchase 

power from small/decentralized power producers. 

163


4.2 Technical Potential for Cogeneration 

4.2.1 Identification of sub-sectors with cogeneration potential 

Since the textile industry has quite a steady need for various types of energy for its process, 

including thermal, refrigeration, and electricity, it is suitable for cogeneration applications. 

Unfortunately, no textile factory has so far adopted cogeneration although some of them have 

diesel power generation units of large capacities. 

The chemical industry, particularly rubber, consumes a lot of electric and thermal energy. In 

Viet Nam, most of rubber factories are very old with outdated energy equipment. As it is time 

for their process equipment to be replaced, this provides a good opportunity for adopting 


Hotels and office buildings in the commercial sector are big energy consumers. There has 

been considerable investment received from foreign companies for their development. These 

buildings use electricity to operate cooling systems. They are often poorly designed from 

energy aspects since investors have the habit of copying the designs from abroad without 

giving due consideration to the local climatic conditions. 

Some foreign direct investment companies in the food-processing sector such as Foremost 

milk processing factory, Walls ice cream factory, meet their power demand by selfgeneration. 

They can easily upgrade their existing energy generation system to operate in 

cogeneration mode. 

4.2.2 Existing cogeneration facilities in the country 

There are several industrial factories in Viet Nam which already have cogeneration facilities 

such as the Bai Bang paper factory in northern region, and sugar mills. The Cogido paper 

mill, in Southern region, used to have a cogeneration capacity of 9,000 kVA. Installed since 

the first commissioning of the mill in 1959, this unit can no longer be used now. Therefore, 

the cogeneration technology seems to be familiar to the paper & pulp and sugar sub-sectors 

in Viet Nam. 

A study sponsored by EC-ASEAN Programme has estimated the total potential of power 

generation from sugar mills in Viet Nam to be 250 MW. However, in reality only a few mills 

can sell their excess electricity to the utility grid and several others are going through the 

negotiation phase. Most of the factories have big difficulty in handling the excess bagasse. 

Industries where cogeneration has been in use are pulp and paper, sugar and nitrogen 

fertilizer. A paper mill in the north is equipped with fluidized circulating bed boiler of a capacity 

to generate 145 tons of steam per hour at 73 bar and 450°C. The plant also has a recovery 

boiler fired by the waste from the process, producing 36 tons of steam per hour at the same 

temperature and pressure. The steam from the boilers is passed through 2 turbines: one is a 

back-pressure turbine producing 12 MW of electricity and the steam leaves at 3 bar for 

processes, and the other is a condensing turbine designed to generate 16 MW of electricity. 

Though the mill is quite large in size and is equipped with relatively modern technology, the 

performance of the cogeneration plant has deteriorated substantially after 20 years of 

operation and poor maintenance. 

Another paper mill in the Southern region, Dong Nai province, has an oil-fired boiler with a 

capacity to produce 40 tons of steam per hour. The cogeneration facility includes an 

extraction-condensing turbine of 5 MW capacity. However, the unit is not used since the mill 

can get electricity from grid easily. With some modification, the existing unit can be easily 

modified to operate as a cogeneration facility in this mill.


There is one big nitrogen fertilizer plant in Viet Nam, located in Habac province. The plant was 

put into operation 30 years ago. The cogeneration plant consists of five coal-fired boilers: two 

large boilers with capacity to produce 75 tons/hour each, and three smaller ones, each with a 

capacity to produce 35 tons/hour. Steam produced at 40 bar and 450°C is partly supplied 

directly to the processes, and partly through a 6 MW backpressure turbine. In addition, there 

are two condensing turbines to meet the plant’s electricity demand, each with a capacity to 

produce 6 MW of electricity. Like in the case of most other plants, the performance of the 

cogeneration plant has degraded after long periods of operation and lack of proper 

maintenance. Presently, the boilers have efficiencies ranging from 70 to 75 per cent whereas 

the turbine efficiency varies from 24 to 26 per cent only. Though there is plan to rehabilitate 

and upgrade the existing facilities, implementation is delayed mainly due to financial 

constraints. 

The first unique cogeneration system in commercial sector in Viet Nam was brought into 

operation on 18th August 1998 in CORA super-market, a member of Bourbon group, in Dong 

Nai province. It consists of two diesel generators, each capable of producing 1200 kW. In 

addition, there are two absorption chillers, each of 600 kW cooling capacity, and two electric 

chillers, each of 400 kW cooling capacity. The main reason for setting up this cogeneration 

system is the necessity for reliable power supply. The company is keen to synchronize its 

cogeneration plant to the national power grid for system stabilization. 

4.2.3 Identification of suitable sites for pre-feasibility study 

The main criteria followed for the selection of sites for pre-feasibility study are the following: 

• important consumers of electricity and heat; 

• acceptable heat-to-power ratios; 

• willingness of the management to apply cogeneration technology; 

• user has plans for renovation or expansion of the existing facilities; 

• management is aware of the benefits of energy conservation and efficiency. 

Up to now, no study has been done on the sectoral power demand in Viet Nam as well as 

their load shapes as a function of time. In this report, the identification of potential study sites 

is based on the list of consumers (provided by the power utility) which have a demand 

exceeding 1000 kW, combined with the list of boiler owners (provided by the Regional 

Departments of Industrial Safety, Ministry of Industry). 

Rough estimation of the steam and electricity demand patterns had to be done in most cases 

as majority of factories lack instrumentation and do not have regular energy monitoring and 

recording facilities. 

After the identification and direct contact, eight sites including factories and commercial 

buildings were chosen for the pre-feasibility study. 

During on-site visits of those establishments, questionnaires were filled out and direct 

discussions were held with the factory management. 

165


4.3 Pre-feasibility Studies at Selected Industrial and Commercial Sites 

For the purpose of economic analysis, the total installed costs of the cogeneration plants 

were assumed as follows: steam turbines - US$ 1,200/kWe; gas turbines - US$ 1,000/kWe; 

and reciprocating engines - US$ 900/kWe. Some common financial data gathered or 

assumed before conducting the pre-feasibility studies are summarized in Table 4.2. 

Table 4.2 Financial data used for the pre-feasibility study 

Parameters Unit Value 

Exchange rate VND/US$ 14,000 

Tax rate Per cent/year 5 

Discount rate Per cent/year 15 

Hurdle rate per cent/year 17 

Cogeneration plant service life Year 15 

Electricity purchase price VND/kWh EVN tariff 

Electricity buy-back rate per cent of purchase price Up to 70 

Fuel price escalation rate per cent/year 5 

Electricity price escalation rate per cent/year 5 

Fuel purchase price 

- natural gas 

- heavy fuel oil 

- diesel 

- coal 

VND/m 3 

VND/kg 

VND/litre 

VND/ton 

1,430 

1,800 

3,580 

280,000 

The fuel prices used are those based on the prices prevailing in the domestic market at 

present. Coal and natural gas prices are taken from EVN’s bidding documents. The purchase 

price of electricity is the tariff applied to Vietnamese industries. Based on information from 

Power Company 2, the buy-back rate is generally taken as 450 VND/kWh. The purchase 

price has to be negotiated between the cogenerators and Power Companies; in any case, 

buy-back rate will not be higher than 70 per cent of the selling price. 

The actual working period for the pre-feasibility study is considered as 306 days/year. Except 

for the case of the paper mill “E”, the boiler pressure of 40 Bar is chosen for steam turbine 

alternatives. In paper mill “E”, the existing boiler pressure is 74 Bar, which is used to assess 

the viability of the steam turbine alternative. 

4.3.1 Textile mill “A” 

This is one of the largest textile mills in Viet Nam. It was put into operation in 1959. The 

company has an average production of 12 million meters of fabric per annum. With 3,350 

employees, the company is contributing effectively to the unemployed reduction of the city. 

Electricity is used for machines, lighting and air conditioning. The company has a centrifugal 

chiller of 200 kW, which has been out of order. In the analysis, it is assumed that the 

company has a process cooling demand equivalent of 200 kWe. So far, the factory does not 

have any record of steam consumption due to lack of measuring equipment. The steam 

consumption is estimated from the fuel oil consumption in the boiler.


Figures derived from the analysis of the electricity and fuel bills are summarized below: 

• Total Electricity Consumption (8/97 to 7/98): 33,157.00 MWh 

• Maximum Electricity Demand: 6.50 MW 

• Minimum Electricity Demand: 4.30 MW 

• Total Fuel Consumption (8/97 to 7/98): 4.22 million litres 



Assuming the cooling was provided by a vapour absorption chiller, the average power-to-heat 

ratios would be 0.65. Typical cogeneration system for this site would be based on gas 

turbine. However, reciprocating engine, steam turbine cogeneration systems were also 

considered as potential alternatives. Altogether five alternatives are analyzed and the results 

of the feasibility study are summarized in Table 4.3. 

Table 4.3 Summary of pre-feasibility study of the textile mill “A” 

Cogeneration Alternatives ALT.1 ALT.2 ALT.3 ALT.4 ALT.5 

Configuration S.T. R.E. G.T. 

Chiller (200 kW Comp. Absorption 

Fuel type H.F.O. N.G. 

Fuel price (VND) 1,800/kg 37,100/GJ 

Electricity purchase price 

(VND/kWh) 

800 

Buy-back rate (as % of purchase price) 56 

Electricity price escalation rate 

(%/year) 

5 

Number of actual working hours per 

year 

7.344 

Heat generating capacity (kg/h) 9,058 10,820 3,370 10,820 8,459 

Power generating capacity (kW) 776 895 4,247 5,381 4,247 

Electricity consumption (MWh/year 33,158 29,348 

Thermal energy requirement (TJ/year) 173 208 

Excess (+)/Deficit(-) heat (TJ/year) 0 -143 0 -45 

Excess(+)/Deficit(-) power(MWh/year) -27,745 -23,101 0 8,192 0 

IRR (%) 19.9 19.9 26.4 24.2 27.6 

Total installation cost (million VND) 12,377 14,359 50,210 60,887 50,211 

Net present value (million VND) 3,677 4,223 35,673 33,985 39,373 

Pay back period (year) 10 10 7 8 6 

Note: S.T.: Steam Turbine; R.E.: Reciprocating Engine; G.T.: Gas Turbine 

The first two alternatives could satisfy the steam demand of the factory. Their IRR is higher 

than the hurdle rate and their total investment are the lowest among considered alternatives. 

However, the company would have to purchase most of its electricity needs from the utility 

grid. 

The alternatives 3, with reciprocating engine configuration, can be considered as the best 

option as it gives a favourable IRR. However, the investment cost is very high in comparison 

with the first two alternatives. 

167


Natural gas seems to be the most attractive fuel for cogeneration as the small deficit in 

steam demand can be made up by auxiliary fuel firing in the recovery boiler. However, gas is 

presently not available at the site. 

As there are several other factories in the vicinity having demand for both heat and power, 

one could envisage a bigger cogeneration plant for the industrial zone. 

4.3.2 Textile company “B” 

With an average annual production of 15 million meters of fabric, this is the biggest textile 

company in southern Viet Nam. It is located in a planned centralized Industrial park in a 

suburb district of Ho Chi Minh City where natural could be available in future. 

With an average annual electricity and steam consumption of 42 GWh and 91,000 tons, 

respectively, this company is a good candidate for cogeneration. Moreover, it has a process 

cooling demand of 1,000 RT. The company has two chillers, one is centrifugal with 300 RT 

cooling capacity, and the other a 750 RT absorption chiller. In alternative 2 of this analysis, it 

is assumed that absorption chillers, running with steam from heat recovery boiler provide all 

the cooling. About 4.5 kg/hour of steam would be necessary in a double-effect chiller to 

supply a RT of cooling. 

Data obtained from the electricity and fuel bills are summarized here: 

• Total Electricity Consumption (12/97 to 11/98): 41,662 MWh 



• Total Annual Fuel Oil Consumption: about 6 million litres 

• Average Steam Demand: 12.4 ton/hr 

The average power-to-heat ratio is 0.6, for which gas turbine cogeneration seems suitable. 

Four alternatives are considered for the analysis, including steam turbine and reciprocating 

engine. The results of the analysis for this company are shown in Table 4.4. 

Table 4.4 Summary of pre-feasibility study of the textile mill “B” 

Cogeneration Alternatives Alt. 1 Alt. 2 Alt. 3 Alt. 4 

Configuration S.T. R.E. (TM) R.E. (PM) G.T. 

Use of compression chiller (RT) 350 0 

Absorption chiller (RT) 750 1,100 

Fuel price (VND) 1,800/kg 1,430/m 3 


Electricity purchase price (VND/ kWh) 800 

Buy-back Rate (as % of purchase price) 56 

Electricity price escalation rate (%/ year) 5 

Number of actual working hours per year 7,344 

Heat generating capacity (kg/hr) 15,027 12,400 4,959 16,807 

Power generating capacity (kW) 1,287 15,366 6,145 8,296 

Electricity consumption (MWh/year) 41,662 40,000 

Thermal energy requirement (TJ/year) 287 321 

Excess(+)/Deficit(-) heat (TJ/year) 0 -50 -192 0 

Excess(+)/Deficit(-) power (MWh/year) -32,682 65,541 1,210 17,882 

IRR (%) 20.0 20.1 27.7 24.8 

NPV (million VND) 6,267.1 36,858 53,871 50,525.8


Total installation cost (million VND) 20,561 121,748 67,409 84,443 

Pay back period (year) 10 10 7 7 

Note: TM: Thermal Match; PM: Power Match 

The first alternative, with boiler and steam turbine configuration, has the lowest investment 

cost among the four considered options and an acceptable IRR. 

The alternative 2 would lead to generation of more than 150 per cent excess electricity. Its 

IRR is almost the same as that of alternative 1 but it requires the highest investment among 

the four considered options. The alternative 3 seems to be the most attractive with the 

highest IRR but its investment cost is three times higher than that of alternative 1. 

The alternative 4 could also be attractive but natural gas is presently not available at the site. 

4.3.3 Textile mill “C” 

Built in the 1960s, the Textile Company “C” is one of the biggest companies in the North of 

Vietnam. In 1997, 4,400 tons of cotton yarns, 16 million metres of raw fabric and 18 million 

metres of finished fabrics were produced in the mill. 

Currently energy represents 16 per cent of production cost. Electricity is used for machines, 

lighting and air conditioning. Steam for process is generated in coal fired boilers. The 

application of the cogeneration technique for this company is suitable, since the company 

wants to reduce the annual electricity and energy costs. 

Results of the analysis of data gathered from the electricity and fuel bills are summarized 

below: 

• Total Annual Electricity Consumption: 31,000 MWh 

• Maximum Electricity Demand: 5 MW 


• Total Annual Coal Consumption: about 315,000 tons 

• Maximum Steam Demand: 20 tons/hr 

• Minimum Steam Demand: 12 ton/hr 

Table 4.5 Summary of pre-feasibility study of the textile mill “C” 

Cogeneration Alternatives Alt.1 Alt.2 Alt.3 Alt. 4 


Chiller (110 kW x 6) Electric 

Fuel type Coal H.F.O. N.G. 

Fuel price (VND) 350/kg 1,800/kg 3,710/GJ 

Electricity purchase price (VND/kWh) 800 


Electricity price escalation rate (%/year) 5 

Number of actual working hours per year 7344 

Heat generating capacity (kg/h) 18,594 54,985 3,986 8,891 


Electricity consumption (MWh/year) 31,000 

Thermal energy requirement (TJ/year) 359 

Excess(+)/Deficit(-) heat (TJ/year) 0 596 -282 -187 

Excess(+)/Deficit(-) power (MWh/year) -20,517 0 3,884 0 

169


IRR (%) 31.7 17.1 25.2 27.9 

NPV (million VND) 26,224 8,897 36,288 42,189 



The average power-to-heat ratio is 0.275, for which steam turbine cogeneration seems 

suitable. Four alternatives are considered for the analysis, including steam turbine using coal, 

reciprocating engine using fuel oil, and gas turbine using natural gas. The results of the 

analysis for this company are shown in Table 4.5. 

Alternative 1 seems to be the most attractive option since its IRR and investment cost are the 

lowest among the four alternatives considered. The main advantage of this alternative is 

derived from the use of coal, which is a cheap fuel. However, it can satisfy a little more than 

30 per cent of the company’s electricity demand. Alternative 2 can take care of all the power 

and heat demands of the factory but its IRR is the lowest and its investment cost is the 

highest among the four alternatives. 

Alternative 3 is also very attractive but its IRR is lower and investment cost is higher than 

those for the first alternative. 

The alternative 4 can also meet all the energy needs of the site and has a fairly high IRR but 

natural gas is presently not available at the site. 

4.3.4 Paper mill “D” 

This is a big paper mill in Dông Nai province, with a capacity to produce 170 tons of paper per 

day. The factory has a condensing steam turbine power generator but it is not used. The 

company functions during 3 shifts per day, 300 days per year. It is presently connected to the 

national grid to take care of all its power needs. The power supply reliability is essential for 

the company for its production process. Self-generation with interconnection to the national 

grid could be a good solution for the company in the existing difficult situation of the power 

sector. 

Analysis of the electricity and steam consumption data allows to conclude the following: 




• Total Annual Fuel Oil Consumption: 13.8 million litres 

• Total Annual Steam Use: 164,721 tons 

• Maximum Steam Demand: 29.1 tons/hr 


With an average power-to-heat ratio of 0.39 for the factory, the steam turbine cogeneration 

configuration seems the most suitable. The analysis for the Paper Company “D” was done 

with three configurations, including steam turbine, reciprocating engine and gas turbine, in 

order to make a comparison. The results of the analysis for this company are shown in Table 

4.6. 

Among the above four alternatives, Alternative 2 seems to be the best since it gives a high 

IRR and taking fuel supply availability into consideration. The alternative 4 with natural gas as 

fuel seems to be the most attractive option but natural gas is not presently available at the 

site.


Table 4.6 Summary of pre-feasibility study of the paper mill “D” 

Cogeneration Alternatives ALT.1 ALT.2 ALT.3 ALT.4 



Fuel price (VND) 1,800/ kg 3,710/GJ 





Thermal energy requirement (TJ/yr.) 450 



Steam generating capacity (kg/hr) 24,147 5,770 24,147 14,410 

Excess(+)/Deficit(-) heat (TJ/year) 0 -342 0 -180 

Excess(+)/Deficit(-) power (MWh/year) - 34,149 0 32,444 0 

IRR (%) 19.8 29.4 24.8 30.7 


Net present value (million VND) 9,842 75,280 64,618 74,992 


Alternative 1 could be a suitable solution in the present situation of capital shortage for 

investment; it requires the lowest investment cost among the four alternatives. However, it 

can only meet 25 per cent of the annual electricity demand of the factory. 

Alternative 3 seems to be able to cover all electricity and heat demands of the company. Its 

IRR is also quite acceptable but the investment required is the highest among the four 

alternatives. Furthermore, natural gas is presently not available at the site. 

4.3.5 Pulp and paper mill “E” 

The company “E”, sponsored by the Government of Sweden, was constructed in 1980 with 

the purpose of satisfying the paper demand of the northern region. It is located in a province 

where trees can be obtained as the primary material for making pulp and paper. The main 

products of the company are paper and packaging paper. The existing capacity is 55,000 

tons per year. For the next two years, its capacity is planned to go up to 100,000 tons per 

year, and to 200,000 tons for the year 2005. Therefore the company projects to invest heavily 

on its extension, as well as the energy supply system. This study however focuses only on 

the existing plant. 

Results of the analysis of data gathered from the electricity and fuel bills in 1997 are 

summarized below: 




• Total Annual Coal Consumption: 82,080 tons 


• Minimum Steam Demand: 97 ton/hr 

171



configuration seems the most suitable. The analysis for the Paper Company “D” was done 

with three configurations, including steam turbine, reciprocating engine and gas turbine, in 

order to make a comparison. The cogeneration systems that give favourable IRR values are 

listed in Table 4.7. 

Table 4.7 Summary of pre-feasibility study of the pulp and paper mill “E” 

Cogeneration Alternatives ALT.1 ALT.2 ALT.3 ALT.4 ALT.5 


Fuel type Coal H.F.O. N.G. 

Fuel price (VND) 280/kg 1,800/kg 1,430/m 3 

Electricity purchase price (VND/kWh) 0.87 


Electricity price escalation rate 

(%/year) 

5 


Heat generating capacity (ton/hr) 101.37 129.85 101.37 10.125 25.42 

Power Generating Capacity (kW) 9,989 12,795 9,989 12,795 12,795 


Thermal energy requirement (TJ/year) 1,931 

Excess (+)/Deficit (-) heat (TJ/year) 0 295 0 -1,738 -1,447 

Excess (+)/Deficit (-) power (MWh/year) -19,197 0 -19,197 0 

IRR (%) 37.1 34.9 24.6 40.5 42 

Total installation cost (million VND) 148,729 189,778 148,729 193,166 113,442 

Net Present Value (million VND) 220,326 246,662 89,537 113,443 204,056 

Pay back Period (year) 5 5 8 4 4 

As shown in the above summary table, IRR of all five considering alternatives are all very 

high. 

However, the alternative 4 with the reciprocating engine using heavy fuel oil can be 

considered as the best option considering the IRR and the availability of fuel supply. 

Alternatives 1 and 3 need the same investment but IRR of the alternative 1 is higher than that 

of the alternative 3. Alternative 5 is the most profitable option with the highest IRR and the 

lowest investment cost but natural gas is presently not available at the site. 

4.3.6 Rubber factory “H” 

Located in a District of Hanoi, the Company belongs to the Complex Light Industrial “Rubber- 

Detergent-Tobacco” Zone. The plant has been in operation since 1960’s and the annual 

production of the company is more than 1 million sets of car tires, 50 million sets of bike tires 

and 100 millions of bicycle air tubes. The product quality of the factory meets the standards 

of many countries in the South East Asian region. 

The company has plans to expand its production and increase its export earnings. Moreover, 

the existing boilers operating with coal as fuel have been in operation for 30 years. The 

company has high demand for both electricity and thermal energy, and would like to reduce 

its annual energy bill that is over 9.3 billion VND.


Due to the lack of instrumentation, there is no measurement of the steam consumed in the 

factory. The steam consumption pattern is established on the basis of the coal consumption 

data of the boilers. Analysis of data gathered from the electricity and fuel bills shows the 

following: 




• Total Annual Coal Consumption: 23,500 tons 


• Minimum Steam Demand: 8 tons/hr 


configuration seems the most suitable. The analysis for the rubber factory was done with 

three configurations, including steam turbine, reciprocating engine and gas turbine, in order to 

make a comparison. The cogeneration systems that lead to acceptable IRR values are listed 

in Table 4.8. 

Table 4.8 Summary of pre-feasibility study of the rubber factory “H” 

Cogeneration Alternatives Alt.1 Alt. 2 Alt. 3 Alt. 4 

Configuration S.T. G.T. R.E. (TM) R.E. (PM) 

Fuel type Coal N.G. H.F.O. 

Fuel price (VND) 280/kg 1,430/m 3 

1,800/kg 







Electricity consumption (MWh/yr.) 12,000 


Excess (+)/Deficit (-) heat (TJ/yr.) 0 -193 0 -234 

Excess (+)/Deficit (-) power (MWh/yr.) -4,047 0 105,751 0 

IRR (%) 30.9 22.1 21.2 20.5 


Net present value (million VND) 19,348 10,259 44,698 7,905 


As shown in the above summary table, the alternative 1 can be considered as the best option 

for cogeneration application in this factory as it gives the highest IRR and requires the lowest 

capital investment cost which may be financially acceptable to the company. IRR of the three 

other alternatives vary around 21 per cent. However, the alternative 4 seems to be attractive 

because of its low investment cost. Alternative 3 can cover all heat and electricity demands 

of the factory but its investment cost is the highest among all the four alternatives. 

4.3.7 Hotel “F” 

This hotel is located in the centre of Ho Chi Minh City. Originally, brought into business in 

1995 as a joint venture between a foreign company and Ho Chi Minh City Tourist Company, 

the hotel occupies an area of 3,000m 2 . Its total operation area is 37,468 m 2 with 542 rooms. 

The hotel operates 24 hours a day and 365 days a year. 

173


Presently, it does not operate full capacity due to the Asian financial crisis. Consequently, 

energy consumption has become an increasing burden on the hotel management. 

Cogeneration appears to be one of the good solutions to reduce the high-energy bills of the 

hotel. 

Analysis of the electricity consumption of the hotel shows that main electricity consumer is 

the air conditioning system, consisting mainly of chillers. The electricity tariff applied is very 

high as the hotel is classified in the commercial and service sector category. The hotel has 

already installed stand-by generators to provide enough electricity to satisfy its present 

requirement. The cost of power generation with the diesel generators is found to be even 

higher than the purchased electricity. A small amount of steam is required mainly for cooking 

and washing purposes. 

A possible alternative at this site would be the use of vapour absorption chillers that can 

operate with the steam generated by recovering heat from the exhaust gases of the diesel 

engine. The total electricity demand will thus be reduced because of the cooling supplied by 

the absorption chiller. 

Analysis of data gathered from the electricity and fuel bills in 1997 shows the following: 




• Total Annual Steam Consumption: 7,245 tons 

• Maximum Steam Demand: 1.6 tons/hr 

• Minimum Steam Demand: 1.16 tons/hr 

The power-to-heat ratio of the hotel is found to be 2.3, which is not suitable for any 

cogeneration configuration. However, this can be changed by incorporating the absorption 

cooling option that increases the steam demand to 7.5 ton/hour. The steam turbine and 

reciprocating engine options are taken into consideration in the pre-feasibility study, and the 

results are presented in Table 4.9. 

Table 4.9 Summary of pre-feasibility study of the hotel “F” 

Cogeneration Alternatives ALT.1 ALT.2 ALT.3 ALT.4 

Configuration S.T. R.E. 

Fuel type H.F.O. D.O. 

Fuel price (VND) 1,800/kg 3,580/litre 

Electricity purchase price (VND/kWh) 1,500 


Electricity price escalation rate (%/yr.) 5 




Electricity consumption (MWh/yr.) 12,882 


Excess (+)/Deficit (-) heat (TJ/yr.) 0 84 -5 -259 

Excess (+)/Deficit (-) power (MWh/yr.) -2,171 0 114,199 17 

IRR (%) 25.6 20.2 29.6 27.5 

Total installation cost (million VND) 38,480 42,617 139,668 39,385


Net present value (Million Dong) 25,897 13,687 129,808 31,015 


As shown in the table, all options give favourable IRR. This can be explained by the fact that 

the electricity price charged by the utility to the factory is very high. Currently, the hotel has to 

pay 0.11 US$ / kWh due to its commercial and service classification. 

The diesel engine cogeneration system with thermal matching option seems to be most 

attractive if excess electricity can be sold to the grid. It requires an initial investment of about 

140 billion VND (equivalent to 10 million US$), including the investment required for the 

absorption chiller system, and leads to an internal rate of return of 29.6 per cent. 

4.3.8 Summary of the pre-feasibility studies 

The results obtained with different prime movers are summarized below: 

Steam turbine 

The steam turbine cogeneration appears to be an attractive option because of the favourable 

IRR obtained for the different projects. 

Table 4.10 Summary of results for steam turbine cogeneration 

Factory Fuel type Excess heat Excess power IRR 

(TJ/year) (MWh/year) ( per cent) 

Textile mill “A” H.F.O. 0 -27,745 19.9 

H.F.O. 0 -23,101 19.9 

Textile mill “B” H.F.O. 0 -32,682 20.0 

Textile mill “C” Coal 0 - 20,517 31.7 

Coal 596 0 17.1 

Paper mill “D” H.F.O. 0 -34,149 19.8 

Paper mill “E” Coal 0 -19,197 37.1 

Coal 295 0 34.9 

H.F.O. 0 -19,197 24.6 

Rubber factory “H” Coal 0 - 4,047 30.9 

Hotel “F” H.F.O. 0 -2,171 25.6 

H.F.O. 84 0 20.0 

As shown in Table 4.10, fuel type strongly affects the project attractiveness. Coal is the most 

suitable fuel type because of its low price. Considering thermal match with coal as fuel, the 

IRR can exceed 30 per cent, whereas it is only around 20 per cent with fuel oil. 

The financial performance also varies from one industrial sub-sector to another. In textile and 

paper sub-sectors, IRR is around 20 per cent for the fuel oil fired boilers. Because of the high 

electricity tariff applied by the utility to the commercial and service sector, the IRR can 

exceed 25 per cent. 

The highest IRR (37 per cent) is obtained for the paper sub-sector with coal fired boiler. 

175


Reciprocating engine 

The configuration of reciprocating engine with heat recovery boiler, using heavy fuel oil as 

fuel, appears to be best suited as it leads to very high IRR; moreover, the availability of fuel 

supply is not a problem at any of the sites. The IRR of the different projects varies in a wide 

range, from 20 per cent to 44 per cent (see Table 4.11). 

Table 4.11 Summary of results for reciprocating engine cogeneration 

Reciprocating Engine 

Factory Excess heat Excess power Elec. Price IRR 

(TJ/year) (MWh/year) 

Textile 

(VND/kWh) ( per cent) 

Textile mill “A” -143 0 800 26.4 

Textile mill “B” -50 65,541 800 20.1 

-192 1,210 800 27.7 

Textile mill “C” -282 3,884 800 25.2 

Paper 

Paper mill “D” -342 0 800 29.4 

Paper mill “E” -1,738 0 800 40.5 

Others 

Rubber factory “H” 0 105,751 780 21.2 

-234 0 780 20.5 

Hotel “F” -5 114,199 1,540 29.6 

-259 0 1,540 27.5 

Building “J” 16 2,473 1,540 23.1 

19 3,845 1,540 17 

29 8,102 1,540 30.6 

16 2,473 1,540 44.4 

The attractiveness of this option also varies with industrial sub-sectors. In textile industry, IRR 

is around 26 per cent. In paper industry, IRR is high ranging from 29 to 40 per cent. In the 

commercial sector, with diesel oil fuelled engine, IRR varies from 23 to 30 per cent; but with 

engines using heavy fuel oil, the IRR is much higher, varying from 30 to 45 per cent. 

4.3.9 Sensitivity Analysis 

Following the techno-economic analysis of the different sites, sensitivity analysis is carried 

out to identify the impact of some of the important parameters on the economics of the 

project. The hurdle rate for accepting a project is assumed as 17 per cent. 

Increase in the investment cost 

Here, the investment is increased (from zero to 15 per cent) to see at which point the IRR 

reaches the hurdle rate. The results are given in Table 4.12. 

With steam turbine alternative, the coal fired boiler option always has IRRs higher than the 

hurdle rate. In many cases, the IRR of the fuel oil fired boiler option reaches the hurdle rate 

when the investment is increased by 15 per cent.


With the option of reciprocating engine operating with heavy fuel oil, the IRR is generally 

above the hurdle rate for the industry sector. This can be explained by the low price of heavy 

fuel oil. In some cases, the hurdle rate is reached with 11 to 15 per cent increases in the 

initial investment. Due to the high price of electricity charged to the commercial and service 

sector, the changes of investment cost do not have much effect on the IRR. 

Table 4.12 Impact of the increase (up to 15 per cent) in investment on IRR 


Site Alternative Fuel type Elect. Price 

(VND/kWh) 

% Increase in 

investment (a) 

177 

IRR % 

Textile mill “A” S.T.(TM) H.F.O. 800 15.0 19.9 

Textile mill “B” S.T.(TM) H.F.O. 800 15.0 20.0 

Textile mill “C” S.T.(TM) Coal 800 + 31.7 

Paper mill “D” S.T.(TM) H.F.O. 800 15.0 19.8 

Paper mill “E” S.T.(TM) Coal 870 + 37.1 

S.T.(PM) Coal 870 + 34.9 

S.T.(TM) H.F.O. 870 + 24.6 

Rubber factory “H” S.T.(TM) Coal 780 + 30.9 

H.F.O. 780 + 21.2 


Textile mill “A” R.E.(PM.) H.F.O. 800 11.8 26.4 

Textile mill “B” R.E.(TM.) H.F.O. 800 15.0 20.1 

R.E.(PM.) H.F.O. 800 + 27.7 

Textile mill “C” R.E.(PM) H.F.O. 870 + 25.2 

Paper mill “D” R.E.(TM.) H.F.O. 800 + 29.4 

Paper mill “E” R.E.(PM) H.F.O. 870 + 40.5 

Rubber factory “H” R.E.(TM.) H.F.O. 780 + 21.2 

R.E.(PM.) H.F.O. 780 15.0 20.5 

Hotel “F” R.E.(TM) D.O 1,540 + 29.6 

R.E.(PM) D.O 1,540 + 27.5 

Note: 

(a): It is the percentage increase when the IRR value reaches the hurdle rate (17 per cent) 

(+ means the IRR always remains above the hurdle rate; and – means the IRR always 

remains below the hurdle rate) 

TM: Thermal match; PM: Power match. 

Fuel price escalation 

In this analysis, the escalation of fuel price is varied from zero and 15 per cent per annum to 

see its impact on the IRR. The results are given in Table 4.13. 

With steam turbine cogeneration, the escalation rate of fuel price does not have any adverse 

effect the financial attractiveness of the coal fired boiler option. This can be explained by the 

low price of coal. On the other hand, when fuel oil is used in the boiler, an escalation rate of 

over 8 per cent will tend to lower the IIR below the hurdle rate. At the fuel price escalation rate 

of 9.5 per cent, the oil fuelled boiler option does not seem to be acceptable. 

With reciprocating engine cogeneration, although heavy fuel oil is much cheaper than diesel, 

many projects have IRRs below the hurdle rate with more than 10 per cent increase in the 

fuel price escalation rate. In the textile “B”, even an increase of 6.6 per cent in fuel price 

escalation rate can render the project unfeasible. Diesel as a fuel for reciprocating engines is 

acceptable only for applications in the commercial sector where the purchased price of 

electricity can be as high as 1,500 VND/kWh.


Table 4.13 Impact of fuel price escalation rate (0-15 per cent per year) on IRR 


Site Alternative Fuel type Elect. Price % escalation 

(VND/kWh) in fuel price (b) 

IRR % 

Textile mill “A” S.T.(TM) H.F.O. 800 7.0 19.9 

Textile mill “B” S.T.(TM) H.F.O. 800 8.0 20.0 


Paper mill “D” S.T.(TM) H.F.O. 800 8.0 19.8 


S.T.(PM) Coal 870 + 34.9 

S.T.(TM) H.F.O. 870 12.0 24.6 



Textile mill “A” R.E.(PM.) H.F.O. 800 + 26.4 


R.E.(PM.) H.F.O. 800 12.0 27.7 

Textile mill “C” R.E.(PM) H.F.O. 870 10.8 25.2 

Paper mill “D” R.E.(TM.) H.F.O. 800 12.9 29.4 


Rubber Co. “H” R.E.(TM.) H.F.O. 780 + 21.2 

R.E.(PM.) H.F.O. 780 15.0 20.5 

Hotel “F” R.E.(TM) D.O 1,540 + 29.6 

Note: 

R.E.(PM) D.O 1,540 + 27.5 

(b): It is the percentage escalation when the IRR value reaches the hurdle rate (17 per cent) 



Electricity price escalation 

In this analysis, the escalation of electricity price is varied from zero and 15 per cent per 

annum to see its impact on the IRR. The results are summarized in Table 4.14. 

As it would have been expected, if the electricity price escalation rate goes up, the value IRR 

also increases accordingly. 

Table 4.14 Impact of electricity price escalation rate (0-15 per cent per year) on IRR 


Factory Alternative Fuel Elect. Price % escalation in 

type (VND/kWh) electricity price (c) 

IRR % 

Textile mill “A” S.T.(TM) H.F.O. 800 + 19.9 

Textile mill “B” S.T.(TM) H.F.O. 800 + 20.0 


Paper mill “D” S.T.(TM) H.F.O. 800 + 19.8 


S.T.(PM) Coal 870 + 34.9 

S.T.(TM) H.F.O. 870 + 24.6 

Rubber factory “H” S.T.(TM) Coal 780 + 30.9




Textile mill “B” R.E.(TM.) H.F.O. 800 + 20.1 

R.E.(PM.) H.F.O. 800 + 27.7 





R.E.(PM.) H.F.O. 780 + 20.5 

Hotel “F” R.E.(TM) D.O 1,540 + 29.6 

R.E.(PM) D.O 1,540 + 27.5 

(c): It is the percentage escalation when the IRR value reaches the hurdle rate (17 per cent) 



Changes in the income tax rate 

The income tax is varied from 5 to 35 per cent to see its impact on the profitability of the 

project, in terms of IRR. The results are given in Table 4.15. 

Table 4.15 Impact of increase in income tax rate (5-35 per cent per year) on IRR 


Factory Alternative Fuel type Elect. Price % increase in 

(VND/kWh) tax rate (d) 

IRR % 

Textile mill “A” S.T.(TM) H.F.O. 800 + 19.9 

Textile mill “B” S.T.(TM) H.F.O. 800 25% 20.0 


Paper mill “D” S.T.(TM) H.F.O. 800 23% 19.8 

Paper mill “E” S.T.(TM) Coal 870 35% 37.1 

S.T.(PM) Coal 870 + 34.9 

S.T.(TM) H.F.O. 870 + 24.6 





R.E.(PM.) H.F.O. 800 + 27.7 





R.E.(PM.) H.F.O. 780 15% 20.5 

Hotel “F” R.E.(TM) D.O 1,540 + 29.6 

R.E.(PM) D.O 1,540 + 27.5 

(d): It is the percentage increase when the IRR value reaches the hurdle rate (17 per cent) 



In the case of steam turbine, an increased tax rate does not affect the IRR much. All coal 

fired boiler options are attractive with the IRR being higher than the hurdle rate. The heavy 

fuel oil fired boiler option is also attractive up to a tax rate of 23 to 25 per cent beyond which 

the IRR falls below the hurdle rate. So far, there has not been any official document on 

taxation of energy generated from unconventional plants. However, higher than 20 per cent 

179


tax rate seems highly unlikely for the energy generation sector. Therefore, the steam turbine 

option with oil fired boilers should be very much feasible. 

Projects with reciprocating engines operating with heavy fuel oil do not seem to be affected 

adversely by high tax rates. Only one case of a textile industry will have IRR below the hurdle 

rate if the tax rate exceeds 25 per cent, and in another case of rubber factory, the threshold of 

tax rate is 15 per cent. Again, these tax rates seem high for the energy sector.


4.4 Conclusions and Recommendations for Follow-up Actions 1 

Conclusion 

Cogeneration is an important issue in the National Energy Conservation & Efficiency Master 

Plan of Viet Nam. Cogeneration can be applied in big and medium scale factories, centralized 

industrial estates and commercial building complexes where power, heating and cooling are 

required. Beside, Cogeneration can be applied also in agriculture for post-harvest 

processing. The wide application of Cogeneration technology can bring positive effects on 

energy conservation, production cost reduction, and environment protection of the country as 

well as the region. 

Cogeneration technology has been employed in Viet Nam since a very long time (Viêt Trì and 

Hà Bác industrial zones, Cogido paper mill, sugar mills) but it has not been widely 

propagated. Cora supermarket has recently set up a cogeneration facility in order to generate 

high quality and reliable power as well as meet the cooling demands. 

Results of the techno-economic and sensitivity studies undertaken for selected sites show 

that the financial viability of a cogeneration project is strongly affected by the energy demand 

pattern, system configuration and fuel type. The purchase price of electricity also strongly 

affects the IRR. It can be considered as a key-factor in the consideration of alternatives. 

The IRRs of steam turbine option vary from 20 per cent for oil fired boilers to above 30 per 

cent with coal-fired boilers. The IRR of coal fired steam turbine cogeneration is not affected 

by the change of investment cost whereas the oil fired option can be unfeasible if there is 

more than 15 per cent increase in the investment. 

The heavy fuel oil would be the most suitable fuel for reciprocating engine option since it can 

lead to very high IRR. 

The escalation in fuel price does not have any adverse impact on coal-fired steam turbine 

cogeneration, but the IRR of oil fired option is sensitive to hikes in fuel prices. 

Tax rates beyond 25 per cent can affect some of the cogeneration projects, but these rates 

can be considered too high for the energy sector in Viet Nam. Therefore, enterprises opting 

for cogeneration presently need not give importance to the effect of tax rate on their project’s 

financial feasibility. There is so far no official document about taxation on energy generated by 

unconventional plants. 

Recommendation for follow-up actions 

The first objective to consider for effective promotion of cogeneration in Viet Nam is to satisfy 

the energy demand of the cogenerator. The sale of excess electricity is important but it 

should not be considered as the first priority. 

By taking care of their energy demand through self-generation and cogeneration, big energy 

consumers can reduce a part of the burden on the electricity sector. 

Most of industrial factories in Viet Nam is out-dated and are in the process of renovating their 

facilities. There are a lot of new investment projects in industrial and commercial sectors that 

provide an ideal occasion for promoting cogeneration. 

1 These conclusions and recommendations are based on the deliberations of participants in the 

South-East Asia Sub-Regional Seminar organized at Ho Chi Minh City on 9 November 1998 and at 

Hanoi on 10 and 11 November 1998. The programme details of the Seminars are included in Appendix 

4A. 

181


Co-ordination among the users, suppliers, financiers, developers, etc., is very important and 

there is a need to have a facilitator or an intermediary. Cogeneration promotion activities 

should be combined with energy conservation and efficiency activities. In other countries, 

promoting cogeneration is one of the activities of the National Energy Conservation Agency. 

Clear official taxation policies related to profit from energy saving and efficiency improvement 

are imperative for the cogeneration promotion. 

The long run marginal tariffs for purchased electricity and selling of excess electricity to the 

grid are key factors for the cogeneration promotion. It should be issued under price formula 

being based on capacity charge and energy charge separately, particularly for long term 

contracts. 

The official synchronization regulation for small scale decentralized power plant should be 

studied and issued. 

As natural gas is being recognized universally as the most appropriate fuel for cogeneration, 

setting up of local natural gas supply stations, with underground storage tanks, in centralized 

industrial parks or export processing zones should be considered. 

Institutionally, the support from the Government is necessary in the following areas: 

• Interconnection with the national power grid; 

• Fixing of tariff for sale of excess power; 

• Favourable credit for rehabilitation of existing cogeneration facilities and development of 

new cogeneration utilities. 

Bilateral and international support should be channelled for setting up cogeneration 

demonstration projects using modern technologies in various sectors of activities in order to 

achieve rational use of energy.


APPENDIX 4.A 

Programme of the South East Asia Sub-Regional Seminar on 


Date: Monday, 9 November 1998 

Place: New World Hotel, Ho Chi Minh City, Viet Nam 

Organiser: Ministry of Education and Training (MOET) of Viet Nam, in Collaboration with 

Economic and Social Commission for Asia and the Pacific (ESCAP) and Asian 

Institute of Technology (AIT) 


Supporters: EC-ASEAN COGEN Programme (COGEN) and French Environment and Energy 

Management Agency (ADEME) 







10h10-10h40 “Business potential for cogeneration in Agro-industrial sector in ASEAN” 


Dr. L. Lacrosse (Technical Adviser, EC-ASEAN Cogen Programme) 

11h00-12h30 “Results of Pre-feasibility Studies in Selected Vietnamese Industries” 

12h30-14h00 Lunch 

Vietnamese National Study Team 

14h00-15h15 “Prospects for Cogeneration Development in Viet Nam” 


Discussion and Conclusion 

15h30-16h30 Optional: “Individual Consultations” 

Potential cogenerators from industries, manufacturers, suppliers, 

developers, financiers, consultants, etc. 

183



ROLE OF COGENERATION IN THE NATIONAL ENERGY SCENARIO: 

Date: Tuesday, 10 November 1998 

PERSPECTIVES FOR ENERGY POLICY 

Place: Hanoi University of Technology, Hanoi, Viet Nam 









“Message from ESCAP” 


09h00-09h30 “Economic and Environmental Benefits of Cogeneration Applications” 


09h30-10h00 “Use of Cogeneration in Japanese Industries” 


Mr. Akira Ishiyama (JICA/ESCAP Expert on Energy Conservation) 

10h20-11h30 “Potential for Use of Cogeneration in the Industrial Sector in Viet Nam” 


11h30-12h15 “Regulatory Framework for Promoting Cogeneration” 

12h15-13h45 Lunch 

Panel discussion with policy makers and industry representatives 

13h45-15h15 “Experiences with Promotion of Cogeneration in South East Asia” 


Mr. P. Marpuang (Ministry of Energy and Mines, Indonesia) 

Mr. F. X. Jacob (Ministry of Energy, Telecommunications and Posts, 

Malaysia) 

Mr. A. M. Nabong (Department of Energy, Philippines) 

Mr. P. Srisovanna (Energy Conservation Center of Thailand) 

15h30-16h30 “Round table discussion, policy recommendations and conclusion”




Date: Wednesday, 11 November 1998 

Place: Hanoi University of Technology, Hanoi, Viet Nam 













09h40-10h10 “Business potential for cogeneration in Agro-industrial sector in ASEAN” 


Dr. L. Lacrosse (Technical Adviser, EC-ASEAN Cogen Programme) 

10h30-12h00 “Results of Pre-feasibility Studies in Selected Vietnamese Industries” 

12h00-14h00 Lunch 


14h00-15h15 “Cogeneration Case Studies from South East Asian Countries” 


Mr. P. Marpuang (Ministry of Energy and Mines, Indonesia) 

Mr. F. X. Jacob (Ministry of Energy, Telecommunications and Posts, 

Malaysia) 

Mr. A. M. Nabong (Department of Energy, Philippines) 

Mr. P. Srisovanna (Energy Conservation Center of Thailand) 

15h30-16h30 “Prospects for Cogeneration Development in Viet Nam” 

Discussion and Conclusion 

185

part 1: overview of cogeneration and its status in asia - Fire

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