PROPOSED DESIGN OF 600 MW COAL – FIRED POWER PLANT

LOCATED AT BRGY. BALANGA, LEMERY, BATANGAS

MERCADO, BRYAN V.
PANOPIO, VINCE LEMUEL B.
RIVERA, LEMUEL ARNEL A.
ME – 5302

17 JULY 2019

i
 EXECUTIVE SUMMARY

The design of the proposed project 600 MW Coal – Fired Power Plant
owned by MRP Power Generation Corporation consists of two steam turbines
which both provide a 300MW capacity. The plant capacity was based on the
increasing power demand of the Philippines particularly in the Luzon grid. The
power plant will be located in Brgy. Balanga, Lemery, Batangas. The location
is in a vacant lot distanced from commercial establishments such as resorts,
but is strategically located along the shore line of Balayan Bay. Balayan Bay
will serve as the water source for plant operations

Three design options were analyzed and logically calculated in terms of

technical parameters, environmental parameters, and economic parameters.
Several factors were considered in the installment of the power plant to
ensure that the operation of the power plant will be successful in the specified
timeframe. Each of the design underwent different categories of analysis
regarding the plant efficiency and economic considerations. Each design
underwent analysis regarding with the efficiency and economic viability. The
best efficiency is suitable in order to help deal with the increasing electrical
demand of the province. The economic viability was considered to determine
if the venture will be profitable for the company and if it can be a suitable
source of income for workers.

Among the three design options, the most beneficial one was selected.
Design option 2 was selected as it gave the best efficiency of 31.9% without
sacrificing economic viability.

Proper equipment was selected with regards to the safe operating

conditions of the plant as well as the economic considerations. Engineering
codes and standards, environmental effects, health and safety issues, political
factors, and ethical factors were considered for the design.

ii
 TABLE OF CONTENTS
Page No.
EXECUTIVE SUMMARY ii
TABLE OF CONTENTS iii
LIST OF TABLES v
LIST OF FIGURES vii

CHAPTER
I INTRODUCTION
Introduction 1
Subject of the Report 2
Capitalization 2
Ownership 2
Organizational Set-up with Technical Organization 3
Location Map 3
Load Projection 7

II REPORT PROPER
Theoretical Consideration 8
Scope of the Design of a 600 MW Coal –Fired 9
Power Plant
Design Options 10
Design Option 1 10
Design Option 2 11
Design Option 3 12
Design Data 13
Summary of Calculations 15
Design Options 15
Design Option 1 15
Design Option 2 18
Design Option 3 22
Fuel and Boiler Efficiency 26
Coal Transport and Storage 28
Chimney 29
iii
 Cooling Water Requirement 29
Environmental Parameters 30
Equipment Selection 30
Components of a Coal-Fired Power Plant 34
Process/Schematic/System Diagram 38
Environmental Impact Assessment (EIA) 40
Environmental Impact Mitigation Measures 43

III ECONOMIC ANALYSIS

Power Demand Analysis 47
Power Demand and Supply Balance 48
Economic Cost 53
Siemens SST 5000 53
Sensitivity Analysis 55
Siemens SST 4000 58
Sensitivity Analysis 60
GE STF D650 62
Sensitivity Analysis 64
Economic Analysis of the Three Catalogues 67

IV OBSERVATION, COMMENTS AND RECOMMENDATIONS

Observation 68
Comments and Recommendations 69

V BIBLIOGRAPHY
Bibliography 70

APPENDICES
A. Computations 72
B. Catalogue 121
C. Project Documentation 129

iv
 LIST OF TABLES
Table No. Title Page No.
1 Comparison of Parameters of the Three Locations 4

2 Projected load in MW from 2019-2044 7

3 Ambient Condition in Brgy, Balanga, Lemery, Batangas 13

4 Steam Cycle Operating Conditions 14

5 Operating Conditions for Design Option 1 15

6 Mass and Heat Balance for each State Point of Design 16

Option 1
7 Summary of Calculation of Mass Balance of Design Option 1 17

8 Summary of Individual Turbine Work for Design Option 1 17

9 Summary of Pump Work for Design Option 1 18

10 Operating Conditions for Design Option 2 18

11 Mass and Heat Balance for each State Point of Design 19

Option 2
12 Summary of Calculation of Mass Balance of Design Option 2 20

13 Summary of Individual Turbine Work for Design Option 2 21

14 Summary of Pump Work for Design Option 2 21

15 Operating Conditions for Design Option 3 22

16 Mass and Heat Balance for each State Point of Design 23

Option 3
17 Summary of Calculation of Mass Balance of Design Option 3 24

18 Summary of Individual Turbine Work for Design Option 3 25

19 Summary of Pump Work for Design Option 3 25

20 Summary of Design Calculations 26

21 Summary of Calculations for Heat Losses in the Boiler 26

22 Summary of Fuel Properties 28

23 Summary of Calculations for the Fuel Flow Rate 28

24 Summary of Calculations for the Chimney 29

25 Summary of Calculated Emissions of the Three Design 30

Options

v
26 Summary of Calculations for SST 5000, SST 4000, and STF 31
D650 based on Design Option 2
27 Equipment Selection 32

28 Summary of Equipment 33

29 Monthly System Peak Demand as of 2018 (in MW) 47

30 Power Generation by Grid as of 2018 (in GWh) 48

31 Power Consumption by Sector as of 2018 (in GWh) 49

32 Power Generation by Source in GWh, Total Philippines 49

(2018)
33 Installed Generating Capacity in MW (2018) 50

34 Dependable Generating Capacity in MW (2018) 51

35 Peak Demand at Batangas 52

36 Power Consumption by Sector as of 2018 in Batangas (in 52

MWh)
37 Power Demand Analysis (SIEMENS SST 5000) 53

38 Depreciation (SIEMENS SST 5000) 54

39 Return of Investment (SIEMENS SST 5000) 54

40 Payback Period (Siemens SST 5000) 55

41 Sensitivity Analysis (SIEMENS SST 5000) 56

42 Power Demand Analysis (SIEMENS SST 4000) 58

43 Depreciation (Siemens SST 4000) 58

44 Return of Investment (Siemens SST 4000) 59

45 Payback Period (Siemens SST 4000) 59

46 Sensitivity Analysis (Siemens SST 4000) 60

47 Power Demand Analysis (GE STF D650) 62

48 Depreciation (GE STF D650) 63

49 Return of Investment (GE STF D650) 63

50 Payback Period (GE STF D650) 64

51 Sensitivity Analysis (STF D650) 64

52 Economic Analysis of the Three Catalogues (Design Option 67

2)

vi
 LIST OF FIGURES
Table No. Title Page No.
1 Organizational Chart 3

2 Proposed Location of the Coal-Fired Power Plant 5

3 Plant location showing the target municipalities to be 5
supplied by the coal-fired power plant
4 Schematic Diagram of Design Option 1 10

5 T – S Diagram of Design Option 1 Cycle 10

6 Schematic Diagram of Design Option 2 11

7 T – S Diagram of Design Option 2 Cycle 11

8 Schematic Diagram of Design Option 3 12

9 T – S Diagram of Design Option 3 Cycle 12

10 SST 5000, SIEMENS 35

11 Two Pass Boiler, GE 35

12 Condenser, GE 36
13 Gigatop Generator. GE 36

14 SPX Heater, Energyen 37

15 Deaerator, Eurowater 37

16 Flue Gas Treatment System 39

17 Ash Handling System 39

18 Water Treatment System Diagram 40

19 Break-Even Graph (Case 1/ SST 5000) 56

20 Break-Even Graph (Case 2/ SST 5000) 57

21 Break-Even Graph (Case 3/ SST 5000) 57

22 Break-Even Graph (Case 1/SST 4000) 60

23 Break-Even Graph (Case 2/SST 4000) 61

24 Break-Even Graph (Case 3/SST 4000) 62

25 Break-Even Graph (Case 1/ STF D650) 65

26 Break-Even Graph (Case 2/ STF D650) 66

27 Break-Even Graph (Case 3/ STF D650) 67

vii
 CHAPTER I

INTRODUCTION

Electricity is a major contributor to developing countries. In modern

technology, it serves as the fuel that utilizes technological advances and
without it most of the technologies that the people use every day would not
function as intended.

According to an article written by Ver, A. A. (2018), entitled Policy

Framework for the Electric Power Industry in the Philippines’ NIC-hood: Quo
Vadis? For the Inquirer Journal, in the next ten years, new power plants will
need to generate at least 82.10 percent of the installed capacity.

In an April 30, 2019 interview of MERALCO president Rogelio Singson,

he stated that “DOE is right in saying that we need 600 MW every year,”.
Meralco issued at least eight red alerts for the month of April (meaning energy
demand exceeds the power supply) causing its subsidiaries to rotate
brownouts.

Power shortages were caused primarily by unplanned power plant

outages. Most power shortages happen in Luzon, which consumes up to 70%
of the country’s demand for electricity.

Business World's senior researcher, Amoguis M.T, reported the

following results on June 17, 2019: there are at least 126 power plants
working within the Luzon grid, according to DOE. However, studies from the
Energy Regulatory Commission (ERC) concluded that 72% of those power
plants are at least 16 years or older in operation and contribute to the power
deficiency of the Luzon grid.

In line with the articles reported, it was determined that building a new
power plant in the Luzon grid will be both beneficial and profitable. This study
proposes a 600 MW coal-fired power plant.

1
The subject of the Report

This project study focused mainly on the design of a 600 MW Coal-

Fired Power Plant located at Brgy. Balanga, Lemery, Batangas. This research
includes the basic foundations and fundamental factors concerning the place
of the plant as well as the design of the plant layout taking into account the
Codes and Standards for Engineering, Environmental and Economic Effects,
Manufacturability, Sustainability, Health and Safety Issues, Ethical
Considerations, etc. The research also involves critical operational condition-
based criteria. The current plant profiles are evaluated in order to establish
the plant layout and place as the reference data. The research will include the
financial assessment for the design project cost overview, cost calculation and
complete cost calculation of the power plant. The study's observation,
conclusion, and recommendation will also be available.

Capitalization

Sufficient financing is considered for the installation and operation of

the plant. Securing the plant's financing may come from the plant's operator
or owner, and public funding. Fifty percent of the funding provided will come
from the owner or operator of the plant, thirty percent of the total cost will be
retained through public financing and the remaining twenty percent will come
from bank loans.

Ownership

The owner of the proposed coal-fired power plant as per the

completion of the project will be the MPR Power Generation Corporation. This
company is a coal-fired power plant and will use sub-bituminous coal as the
primary fuel. The organization in the company will be the one who has the
power and authority to decide where the suggested coal-fireded energy plant
will be located. All facility equipment, utilities, and infrastructure belong to the
said company.

2
Organizational Set-up with Technical Organization

This is the MPR Power Generation Corporation technical organization

Figure 1. Organizational Chart

This figure shows the flow of power from the skilled worker up to the
professional worker. It shows how every worker relates to each other, who
has a higher position.

Location Map

For the location of the power plant, three municipalities in Batangas

were considered: Mabini, Lemery, and Nasugbu. The available areas were all
located near bodies of water needed to provide water for the plant operations.
The location in Nasugbu however, seemed to conflict with the neighboring
commercial resorts as it would affect their business. This narrows the options
to Lemery and Mabini. For both options, the topography of the land area of
Mabini is less beneficial as the landscape is craggy. Additional labor will be
required to flatten the landscape. Therefore it was concluded that the location
in Lemery is the most applicable option among the three. The location in
Lemery can also be easily reached by road via a national highway. Several
3
parameters were also considered to compare the three possible locations.
The location must be determined first before arriving at a final conclusion. The
parameters are given by:

Table 1
Comparison of Parameters of the Three Locations

Location 1 Location 2 Location 3

Parameters
(Mabini) (Lemery) (Nasugbu)

Surrounding
Present Present Present
bodies of water
Vast open area Present Present Present
Nearness to the
Near Near Near
grid
ambient air
27.75oC 27oC 29oC
temperature
Forestation and
Disturbances Forestation Many Resorts
Excavation
Elevated by
Topography Flat Flat
100m
Factors that are Seaside and Seaside and the
Seaside and sea
being protected the sea sea
Cost of Land Area PHP1800.00 PHP1500.00 PHP1650.00
Access to
Easy Easy Easy
transportation

Table 1 shows the different parameters used to determine the plant

location. All of the locations are vast open areas suitable for the construction
of large facilities. The locations are strategically located near bodies of water.
The location in Mabini is located along the coast of Batangas Bay, the location
in Lemery is located along Balayan Bay, and the Nasugbu location is along
the shore of Nasugbu Bay.

The researchers decided to install the plant in Brgy. Balanga, Lemery

Batangas due to its strategic location with regards to the nearness to the grid,
availability of water, cost of land, and fuel transport via sea. The vicinity will be
4
less affected compared to the other locations. The chosen location will
provide electricity to the different municipalities in the province of Batangas.

The construction of the power plant will not only benefit the corporation
but will also provide career opportunities for the community. The power plant
will help in the economic development and industrialization of Brgy. Balanga,
Lemery.

Lemery is a 1st class urban municipality in the province of Batangas

with an ambient temperature of 27%. The municipality is located in the west-
central part of Batangas between the distribution utilities BATELEC I and
BATELEC II. Lemery has a land area of 110 square kilometers constituting
3.5% of the land area in Batangas. According to the 2015 census, Lemery has
a population of 93,157 people.

Brgy Balanga is located along the coast near the municipality of

Calaca. Brgy Balanga’s Philippines Standard Geographic Code is 041012006.
The population of the Brgy. In 2014 constitutes 1.1% of the total population of
Lemery with 1050 people. The specific location of the power plant is at 13°5"
North and 120°52'16.1" East of the Philippines.
Below is the proposed plant location located at Brgy. Balanga, Lemery,
Batangas.

Figure 2. Proposed Location of the Coal-Fired Power Plant (Google

Map, 2019)

5
 Figure 2 shows the location of the proposed plant site. The proposed
coal-fired power plant is to be constructed in Brgy. Balanga, Lemery,
Batangas with a land area of 0.325 square kilometers.

Figure 3. Plant location showing the target municipalities to be supplied by

the coal-fired power plant (Google Map, 2019)

Figure 3 shows that the proposed power plant will provide energy
primarily for the province of Batangas with the help of the distribution units of
BATELEC I BATELEC II, First Bay Power Corporation (FBPC) and Ibaan
Electric Engineering Corporation (IEEC). BATELEC distributes electricity in
the municipalities of Nasugbu, Lian, Calatagan, Tuy, Balayan, Calaca,
Lemery, Agoncillo, San Nicolas, Sta. Teresita, and San Luis. BATELEC II
distributes electricity to the municipalities of Laurel, Talisay, Tanauan, Malvar,
Balete, Lipa, Cuenca, San Jose, Alitagtag, Mabini, Tingloy, Padre Garcia,
Rosario, Taysan, Lobo, and San Juan. Additional power produced can be
exported to other provinces connected to the Luzon grid such as MERALCO
which supplies the greater Manila area. Reports have shown that the country
is faced with problems regarding energy demand especially the Luzon grid.

6
Load Projection
The following data necessary for the load projection were gathered from the
Department of Energy (DOE) distribution utility profile particularly the
distribution utilities operating in Batangas Province: BATELEC I, BATELEC II,
FBPC, and IEEC. The Manila Electric Company (MERALCO) was also added
to the load projection. The data were gathered to determine the forecast of the
electrical consumption of the target locations.

Table 2
Projected load in MW from 2019-2044
Year BATELEC I BATELEC II FBPC IEEC MERALCO TOTAL
2019 69.93958701 165.59 9.44 4.75 7372.97 7622.7
2020 72.7511584 172.41 9.37 4.90 7608.91 7868.3
2021 75.67575497 179.52 9.30 5.06 7852.39 8121.9
2022 78.71792032 186.91 9.23 5.22 8103.67 8383.7
2023 81.88238072 194.61 9.16 5.39 8362.98 8654
2024 85.17405242 202.63 9.09 5.56 8630.60 8933.1
2025 88.59804933 210.98 9.02 5.74 8906.78 9221.1
2026 92.15969092 219.67 8.95 5.92 9191.80 9518.5
2027 95.86451049 228.72 8.89 6.11 9485.93 9825.5
2028 99.71826381 238.14 8.82 6.31 9789.48 10142
2029 103.726938 247.96 8.75 6.51 10102.75 10470
Source: Department of Energy

The data gathered from DOE showed the projected load from 2015-
2029 for BATELEC I, BATELEC II, IEEC, and MERALCO. At 2019 the total
projected load is equal to 7622.7MW and after 10 years the projected load will
increase to 10470MW. The power demand has an average growth rate of
9.64% starting from 245.65 MW to 327 MW averaging 309.21 MW for 10
years.
Assuming no other power plants will provide the additional demand, the
proposed 600 MW power plant will reach its capacity within the next 2 years
of operation upon the finishing of construction within the next 10 years.

7
 CHAPTER II
REPORT PROPER
This chapter is composed of the report proper and design calculations
considered in the proposed 600 MW Coal-Fired Power Plant.

Theoretical Consideration
A steam power plant is used to generate electricity by the use of steam
turbine. The major components of this power plant are boiler, steam turbine,
condenser and water feed pump.

Coal is shipped to the port area where it will be conveyed in the coal
yard for storage prior to being transported to the main power generating units.
The first process of this power plant is where the pulverized coal is fed into
the boiler and it is burnt in the furnace. The flue gasses and ash formed
during combustion will be treated accordingly. The water present in the boiler
drum changes to high pressure steam. From the boiler the high-pressure
steam passed to the super heater where it is again heated up to its dryness.
This super-heated steam strikes the turbine blades with a high speed and the
turbine starts rotating at high speed. A generator is attached to the rotor of the
turbine and as the turbine rotates it also rotates with the speed of the turbine.
The generator converts the mechanical energy of the turbine into electrical
energy. The electrical energy will be amplified by a transformer and will then
be transferred to the switch yard. After striking on the turbine the steam
leaves the turbine and enters into the condenser. The steam gets condensed
with the help of cold water from the cooling tower. The condensed water with
the feed water enters into the economizer. In the economizer the feed water
gets heated up before entering into the boiler. This heating of water increases
the efficiency of the boiler. The exhaust gases from the furnace pass through
the super heater, economizer and air pre-heater. The heat of this exhaust
gases is utilized in the heating of steam in the super heater, feed water in the
economizer and air in the air pre-heater. After burning of the coal into the
furnace, it is transported to ash handling plant and finally to the ash storage.
The electricity produced by the generator are then stored at transformers
before distributing it to the consumers.
8
Scope of the Design of a 600 MW Coal Fired Power Plant

The main objective of this project is to design a coal-fired power plant

having a plant capacity of 600 MW located at Brgy. Balanga, Lemery,
Batangas. Specifically, this study aims to:

1. Present and evaluate the design and development of the projected 600
MW coal fired power plant taking into account of the following
considerations:

1.1. Energy Balance

1.2. Overall Efficiency

1.3. Work Output

2. Provide technical design specifications for the different components of

the coal fired power plant, presenting the proper data for the plant
calculations, schematic diagrams, process flow diagrams, plant lay-out,
and particular type of plant components considering the required
engineering codes, standards and appropriate specifications to be
utilized as a part of the advancement of the proposed coal-fired power
plant.

3. Evaluate the economic viability of the three proposed design options as

well as the comparison of equipment through calculations of economic
indicators:

3.1. Payback period

3.2. Rate of Return/Rate of Investment

4. Evaluate the proposed design considering the environmental impact

and elaborating the socio-economic benefits and outcomes of the
project,

5. Establish a detailed project construction execution plan of the selected

best design.

9
Design Calculation

1. Design Options

Design Option 1

The schematic and T-S diagram of design option 1 is shown as follows.

Figure 4. Schematic Diagram of Design Option 1

Design option 1 operates with a reheat regenerative rankine cycle. The

system consists of 5 regenerative processes with 1 open feed water heater
and 4 closed feed water heater, and reheating. The design option obtained
a thermal efficiency of 30.6%

Figure 5. T – S Diagram of Design Option 1 Cycle

The figure above shows the thermodynamic relationship with in the

design. The cycle consists of 20 state points with 7 operating pressures.

10
Design Option 2

The schematic and T-S diagram of design option 1 is shown as follows.

Figure 6. Schematic Diagram of Design Option 2

The system consists of 6 regenerative processes with 1 open feed

water heater and 5 closed feed water heater , and reheating. The design
option obtained a thermal efficiency of 31.9%.

Figure 7. T – S Diagram of Design Option 2 Cycle

The figure above shows the thermodynamic relationship with in the

design. The cycle consists of 23 state points with 8 operating pressures.

11
Design Option 3

The schematic and T-S diagram of design option 1 is shown as follows.

Figure 8. Schematic Diagram of Design Option 2

The system consists of 6 regenerative processes with 1 open feed

water heater and 5 closed feed water heater , and reheating. The design
option obtained a thermal efficiency of 31.6%.

Figure 9. Schematic Diagram of Design Option 3

The figure above shows the thermodynamic relationship with in the

design. The cycle consists of 26 state points with 9 operating pressures.

12
2. Design Data
The design data includes the ambient conditions in the proposed
location in Brgy. Balanga, Lemery, Batangas and the steam cycle operating
conditions used in the calculation of technical parameters of the design
options.

Table 3
Ambient Condition in Brgy, Balanga, Lemery, Batangas
Ambient Condition

Pressure mbar 1014

Humidity % 61

Temperature

o
Design Temperature C 27
o
Max. Temperature C 34
o
Min. Temperature C 22

The data from table 3 shows the ambient weather conditions for Brgy.
Balanga, Lemery, Batangas. The atmospheric pressure is 101.4 mbar. The air
has a relative humidity of 61%. The chosen design temperature is 27 oC as
the historic maximum and minimum temperatures are 34 oC and 22 oC
respectively.

13
 Table 4
Steam Cycle Operating Conditions
Parameter Design 1 Design 2 Design 3 Value
High Pressure Turbine
Pressure 20 20 20 Mpa
1st Extraction
- 10 10 Mpa
Pressure
Temperature 0
540 540 540 C
(inlet)
Intermediate Pressure Turbine
Pressure / Reheat
7.5 7.5 7.5 MPa
Pressure
Reheat Temp. 0
540 540 540 C
(inlet)
2nd Extraction
7.5 7.5 7.5 MPa
Pressure
3rd Extraction
5 5 3.5 MPa
Pressure
4th Extraction
2 2 1.5 MPa
Pressure
5th Extraction
0.5 0.5 0.5 MPa
Pressure
6th Extraction
0.1 0.1 0.2 MPa
Pressure
7th Extraction
- - 0.05 MPa
Pressure
Condenser
Pressure 0.005 0.005 0.005 Mpa

The table above shows the operating conditions of the three different
design options. The pressure in the heat generating unit is 540 oC, the
maximum pressure in the superheater is 20Mpa, and the condenser pressure
is 0.005 Mpa.

14
3. Summary of Calculations

The summary of calculations is composed of calculations for the three

design options, the calculations for the fuel and boiler efficiency, calulations
for turbine selection, and the environmental parameters

A. Design Options

Summary of Calculations for Design Option 1

Table 5
Operating Conditions for Design Option 1

Parameter Unit Value

High Pressure Turbine
Pressure 20 20
Temperature (inlet) 540 540
Intermediate Pressure Turbine

Pressure / Reheat Pressure 7.5 MPa

0
Reheat Temperature (inlet) 540 C

First Extration Pressure 7.5 MPa

Second Extraction Pressure 5 MPa

Third Extraction Pressure 2 MPa

Fourth Extraction Pressure 0.5 MPa

Fifth Extraction Pressure 0.1 MPa

Condenser
Pressure 0.005 0.005

Table 5 shows the operating pressure and temperature conditions

necessary for calculations.

15
 Table 6

Mass and Heat Balance for each State Point of Design Option 1

State Pressure
Temp. (oC) Enthalpy (kJ/kg) Masssteam (kg/s)
Point (Mpa)
1 20 540 3366.370 419.910
2 7.5 375.498 3080.280 36.005
3 7.5 540 3502.650 384.223
4 5 469.812 3363.980 348.218
5 2 330.068 3092.920 307.504
6 0.5 163.635 2775.750 278.926
7 0.1 99.6059 2498.250 237.867
8 0.005 32.8743 2119.920 237.867
9 0.005 32.8743 137.749 384.223
10 0.1 32.8768 137.845 307.504
11 0.1 99.6059 417.504 76.719
12 0.5 99.6335 417.921 307.504
13 0.5 151.831 640.085 28.578
14 2 151.999 641.724 307.504
15 2 212.377 908.498 40.715
16 5 212.935 912.028 307.504
17 5 263.941 1154.640 419.910
18 7.5 284.692 1157.856 419.910
19 7.5 290.535 1292.930 36.005
20 20 295.439 1310.326 419.910

Table 6 shows the obtained temperature, enthalpy, and steam flow for
the operating conditions in design option 2. Values were obtained from
SteamTab Companion software from ChemicaLogic Corporation. The actual
enthalpies were obtained using a turbine efficiency of 53% and a pump
efficiency of 85%.

16
 Table 7

Summary of Calculation of Mass Balance of Design Option 1

Symbol Equation Value Unit

m ( )= 35.68721014 kg/s

m 36.00473013 kg/s

m 40.71466011 kg/s

m 28.5777881 kg/s

m 41.05895598 kg/s

m ∑ 6.6 kg/s

Table 7 shows the mass balance calculations for design option 1. The
work produced by the turbine is 300MW and the total mass of steam required
to produce the output is 356.6383313 kg/s

Table 8

Summary of Individual Turbine Work for Design Option 1

Symbol Equation Value Unit

W 53.28022109 MW

W 50.02568176 MW

W 72.45438297 MW

W 6 71.91183431 MW

W6 76.51916214 MW

W 53.28022109 MW

W MW

17
 Table 8 shows the calculations used to obtain the work of the turbine in
design option 1 from individual state points and also the total output which is
300 MW.

Table 9

Summary of Pump Work for Design Option 1

Symbol Equation Value Unit

WP 0.026726847 MW

WP 1.317484306 MW

WP 1.344211154 MW

Table 9 enlists the calculations used for the work of the condensate
pump and the open feedwater pump. The total pump work is 1.344211154
MW.

Summary of Calculations for Design Option 2

Table 10
Operating Conditions for Design Option 2

Parameter Unit Value

High Pressure Turbine
Pressure 20 MPa

First Extraction Pressure 10 Mpa

0
Temperature (inlet) 540 C
Intermediate Pressure Turbine

Pressure / Reheat Pressure 7.5 MPa

0
Reheat Temperature (inlet) 540 C

Second Extraction Pressure 7.5 MPa

Third Extraction Pressure 5 MPa

18
 Fourth Extraction Pressure 2 MPa

Fifth Extraction Pressure 0.5 MPa

Sixth Extraction Pressure 0.1 MPa

Condenser
Pressure 005 MPa

Table 10 shows the operating pressure and temperature conditions

necessary for calculations.

Table 11

Mass and Heat Balance for each State Point of Design Option 2

State Pressure Enthalpy Mass of Steam

Temp. (oC)
Point (Mpa) (kJ/kg) (kg/s)
1 20 540 3366.370 402.439
2 10 454.945 3255.865 27.381
3 7.5 404.933 3162.805 375.058
4 7.5 540 3502.650 348.708
5 5 497.647 3429.155 317.278
6 2 401.112 3250.791 282.359
7 0.5 268.311 2999.019 254.752
8 0.1 128.437 2733.612 221.856
9 0.005 32.8743 2397.241 221.856
10 0.005 32.8743 137.749 317.278
11 0.1 32.886 137.802 317.278
12 0.1 45.8063 417.921 95.423
13 0.5 81.3169 421.677 317.278
14 0.5 81.3169 640.085 31.430
15 2 155.419 656.473 317.278
16 2 212.377 908.498 34.919
17 5 219.887 943.801 317.278

19
 18 5 263.941 1154.640 402.439
19 7.5 271.543 1192.475 402.439
20 7.5 290.535 1292.930 27.607
21 10 310.997 1299.771 402.439
22 10 310.997 1408.060 32.897
23 20 316.545 1425.491 402.439

Table 11 shows the obtained temperature, enthalpy, and steam flow for
the operating conditions in design option 2. Values were obtained from
SteamTab Companion software from ChemicaLogic Corporation. The actual
enthalpies were obtained using a turbine efficiency of 53% and a pump
efficiency of 85%.

Table 12
Summary of Calculation of Mass Balance of Design Option 2
Symbol Equation Value Unit

m ( )= 27.38094375 kg/s

m 26.34971427 kg/s

m 31.43026046 kg/s

m 34.9187646 kg/s

m 27.60703378 kg/s

( )=
m6 32.89675604 kg/s

m ∑ 419.9103376 kg/s

20
 Table 12 shows the mass balance calculations for design option 2. The
work produced by the turbine is 300MW and the total mass of steam required
to produce the output 419.9103376 kg/s

Table 13

Summary of Individual Turbine Work for Design Option 2

Symbol Equation Value Unit

44.47152311 MW

34.90292266 MW

25.62835541 MW

55.96860863 MW

70.21184978 MW

66.6873736 MW

73.45226665 MW

Table 13 shows the calculations used to obtain the work of the turbine
in design option 2 from individual state points and also the total output which
is 300 MW.

Table 14

Summary of Pump Work for Design Option 2

Symbol Equation Value Unit

MW

MW

MW

21
 Table 14 enlists the calculations used for the work of the condensate
pump and the open feedwater pump. The total pump work is 1.344211154
MW.

Summary of Calculations for Design Option 3

Table 15
Operating Conditions for Design Option 2

Parameter Unit Value

High Pressure Turbine
Pressure 20 Mpa
First Extraction Pressure 10 Mpa
0
Temperature (inlet) 540 C
Intermediate Pressure Turbine

Pressure / Reheat Pressure 7.5 MPa

0
Reheat Temperature (inlet) 540 C

Second Extraction Pressure 7.5

Third Extraction Pressure 3.5 MPa

Fourth Extraction Pressure 1.5 MPa

Fifth Extraction Pressure 0.5 MPa

Sixth Extraction Pressure 0.2 MPa

Seventh Extraction Pressure 0.05 MPa

Condenser
Pressure 0.005 Mpa

Table 15 shows the operating pressure and temperature conditions

necessary for calculations.

22
 Table 16

Mass and Heat Balance for each State Point of Design Option 3

State Pressure Enthalpy Masssteam

Temp. (oC)
Point (Mpa) (kJ/kg) (kg/s)
1 20 540 3366.370 406.494
2 10 454.945 3255.865 27.657
3 7.5 404.933 3162.805 378.837
4 7.5 540 3502.650 345.311
5 3 467.83 3384.948 324.697
6 1.5 385.178 3224.385 314.426
7 0.5 274.7936 3012.732 255.134
8 0.25 187.826 2843.513 227.089
9 0.1 99.6059 2597.888 190.685
10 0.005 32.8743 2351.307 190.685
11 0.005 32.8743 137.749 324.697
12 0.1 32.886 137.802 324.697
13 0.1 99.6059 417.504 134.012
14 0.25 99.6163 417.660 324.697
15 0.25 127.411 535.245 36.405
16 0.5 127.434 535.612 324.697
17 0.5 151.831 915.290 59.292
18 1.5 198.287 916.383 324.697
19 1.5 198.287 844.557 10.270
20 3 198.535 846.288 324.697
21 3 233.853 1008.340 406.494
22 7.5 244.823 1060.900 406.494
23 7.5 290.535 1292.930 36.405
24 10 292.171 1299.771 406.494
25 10 310.997 1408.060 33.526
26 20 316.545 1425.491 406.494

23
 Table 16 shows the obtained temperature, enthalpy, and steam flow for
the operating conditions in design option 3. Values were obtained from
SteamTab Companion software from ChemicaLogic Corporation. The actual
enthalpies were obtained using a turbine efficiency of 53% and a pump
efficiency of 85%.

Table 17
Summary of Calculation of Mass Balance of Design Option 3
Symbol Equation Value Unit

m ( )= 27.65681659 kg/s

m 33.52580983 kg/s

m 20.61445805 kg/s

m 10.27033512 kg/s

m 59.29194521 kg/s

( )=
m6 28.04492697 kg/s

m 36.40490734 kg/s

m ∑ 402.4390128 kg/s

Table 17 shows the mass balance calculations for design option 2. The
work produced by the turbine is 300MW and the total mass of steam required
to produce the output is 402.4390128 kg/s

24
 Table 18

Summary of Individual Turbine Work for Design Option

Symbol Equation Value Unit

W 44.91958968 MW

W 35.25458214 MW

W 40.64394569 MW

W 52.1340169 MW
6

W6 66.5492868 MW

W 43.17374351 MW

W 55.7787587 MW

W 47.01927295 MW
0

W 300 MW

The table above shows the calculations used to obtain the work of the
turbine in design option 3 from individual state points and also the total output
which is 300 MW.

Table 19

Summary of Pump Work for Design Option 2

Symbol Equation Value Unit

WP 0.011611988 MW

WP 13.1933806 MW

WP 13.20499259 MW

25
 Table 19 enlists the calculations used for the work of the condensate
pump and the open feedwater pump. The total pump work is 13.20499259
MW.

Table 20
Summary of Design Calculations

Parameters Design Option 1 Design Option 2 Design Option 3

Heat Added 973.9748222 MW 899.5922049 MW 917.7009625 MW

Work of
300 MW 300 MW 300 MW
Turbine
Work of
1.344211154 MW 13.20499259 MW 1.543884 MW
Pump

Net Work 298.6557888 MW 286.7950074 MW 289.9592642 MW

Thermal
0.306636046 0.318805366 0.315962689
Efficiency

The table above shows the computed values needed to determine the
thermal efficiency. The calculations show that design option 2 has the most
desirable thermal efficiency of 31.8805572%.

B. Fuel and Boiler Efficiency

Table 21
Summary of Calculations for Heat Losses in the Boiler

Heat Loss Equation Symbol Value Unit

( )
Dry flue gas loss %

( )
Moisture loss %

( )
Humidity loss %

26
 Unburnt loss %

Radiation 1 %
loss
Unaccountable 10 %
loss
Total Boiler ∑ %
Loss
Gross efficiency ∑ %
of boiler

Table 21 shows the calculations of different losses factored in determining

the overall efficiency of the boiler. These losses are chimney loss, unburnt
loss, radiation loss, and unaccountable loss. The overall efficiency of the
boiler is 84.99167046%.

Fuel Computations

The fuel to be used will be sub-bituminous coal from Semirara Coal

and Mining Corporation. The data below shows the ultimate analysis of
sub-bituminous coal from Semirara. Through the data gathered, the
researchers were able to determine the properties that may affect the
overall plant operations. It also pictures the possible emissions from the
combustion or utilization of the said coal as fuel.

Hydrogen = 4.318%

Carbon = 56.556%

Nitrogen = 1.038%

Sulfur = 0.752%

Oxygen = 16.336%

Ash = 21%

27
 Table 22
Summary of Fuel Properties

Parameter Equation Value

HHV ( ) 22479.4704 kJ/kg

HHVactual 19105.5794 kJ/kg

A/Ftheo ( ) 7.321496 kgair/kgfuel

A/Factual 8.98519387 kgair/kgfuel

The higher heating value was obtained using Dulongs Formula with the
given fuel contents. The boiler efficiency was computed to determine the
actual heating value for operations. The theoretical air-fuel ratio was
determined. The excess air fuel ratio and the humidity of the air was
considered in determining the actual air fuel ratio.

Table 23
Summary of Calculations for the Fuel Flow Rate

Equation Design Option 1 Design Option 2 Design Option 3

50.97855458 kg/s 47.08531399 kg/s 48.0331396 kg/s

The calculations for the fuel flow rate shows that design option 2 has
the least fuel requirement reducing the fuel costs for operation.

C. Coal Transport and Storage

The coal consumption for 1 day is 8136.34 tons and requires coal
transport of 66, 3000 ton capacity barges per month.
In case of unexpected hindrances with the transport of coal, the plant
has a coal storage capacity good for 1 month with a total area of
2x260mx125m.

28
D. Chimney Calculations
Table 24
Summary of Calculations for the Chimney

Parameter Equation Value

9.98519387 kgair/kgfuel
470.1559387 kg/s
0.8643457kg/m3

8.98519387 kgair/kgfuel

; 9.6095m2≈ 0m2
( ) 706.9033026Pa

For the chimney computations, the flue gasses were assumed to all
exit the chimney. The exit temperature was assumed 150 oC. Ambient air
conditions were used for the outside air density. The maximum allowable flue
gas velocity is 7.5m/s. The chimney diameter to be built is 10m. For a
chimney height of 220m, the pressure drop was 706.9033026Pa.

E. Cooling Water Requirement

The circulating water pump has a flowrate of 50m3/s and will have a
temperature increase of 3.444917 oC in order to condense the steam. The
temperature difference was obtained with the heat balance formula:

The change in enthalpy occurs on statepoint 9 and statepoint 10, while the
initial temperature of the water from Balayan Bay is 30 oC.

29
F. Environmental Parameters

The selection of the best design option are also compared based on
the environmental effects of the gases resulted in the combustion of primary
fuel which is the lignite coal. The environmental parameters being compared
are the carbon oxides emission (COx), nitrogen oxides emission (NOx), sulfur
oxides emission (SOx), and ash disposal. The summary of heat losses in the
boiler are also tabulated as follows.

Table 25

Summary of Calculated Emissions of the Three Design Options

Equation
Symbol Design Option 1 Design Option 2 Design Option 3

99.96554696 kg/s 92.3316171 kg/s 94.18978455 kg/s

1.658259554 kg/s 1.392379999 kg/s 1.562449412 kg/s

0.734091186 kg/s 0.6780285215 kg/s 0.7000815183kg/s

12.59680084 kg/s 11.64478109 kg/s 11.8689888 kg/s

Table 25 shows that design option 2 has the least emission due to it
also consuming the least amount of fuel. Design option 2 has a Carbon
emission of 92.3316171 kg/s, nitrogen oxide emission of 1.392379999 kg/s
Sulfur Oxide emission of 0.6780285215 kg/s, and ang ash flow of
11.64478109 kg/s.

Equipment Selection

Based on the thermal efficiency, fuel consumption, and environmental

parameters, design option 2 is the best option. The computations were based

30
on the turbine SST-5000. SST-4000 and STF-D650 are also viable options for
the power plant and comparisons were made for the three turbines.

Table 26

Summary of Calculations for SST 5000, SST 4000, and STF D650 based
on Design Option 2

Parameters SST 5000 SST 4000 STF D650

Technical Data
Power Output 250-500 MW 100-500 MW ≤ M

Frequency 50 or 60 Hz 50 or 60 Hz 50 or 60 Hz

Efficiency 53% 43% 47.50%

Maximum Pressure 26 Mpa 10.5 Mpa 19 Mpa

Technical Parameters

Heat Added 899.5922049 MW 1103.343129 MW 1103.343129 MW

Work of Turbine 300 MW 300 MW 300 MW

Work of Pump 13.20499259 MW 1.750903776 MW 14.34613468 MW

Net Work 286.7950074 MW 298.2490962 MW 285.6538653 MW

Mass of Steam 402.4390128 kg/s 482.6258918 kg/s 433.7365554 kg/s

Mass of Fuel 47.08531399 kg/s 57.74978638 kg/s 50.3360314 kg/s

Thermal Efficiency 0.318805366 0.270314001 0.297030414

Environmental Parameter

Carbon oxide emission 92.3316171 kg/s 113.2434757 kg/s 98.70560184 kg/s

Nitrogen oxide emission 1.392379999 kg/s 1.878517962 kg/s 1.637359193 kg/s

Sulfur oxide emission 0.6780285215 kg/s 0.831596844 kg/s 0.7248388522 kg/s

Ash disposal 11.64478109 kg/s 11.8689888 kg/s 12.43803336 kg/s

31
 able 6 presents the summary of calculations for the steam turbines’
performance with design option 2. It can be seen that SST 500 is the best
choice in terms of efficiency, fuel consumption, and environmental impact.

Table 27

Equipment Selection

Relative Php/k Average T1 T2

O&M
capital cost W Efficiency years years

SIEMENS Php Php

9.8599 53% 1 25
SST 5000 193,911,717,260.0 16,173,062,400.00

Php
SIEMENS Php
9.8599 43% 1 25
SST 4000 197,507,050,260.00 17,214,143,300.00

GE Php Php
9.8599 47.5% 1 25
STF D650 200,126,507,160.00 18,093,264,348.00

T1 – Interval of Major Maintenance

T2 – Interval Between Complete Replacement

Table 27 shows how the equipment is selected. The equipment

selection is based on the relative capital cost, the Php/kW, average efficiency,
interval of major maintenance, interval between complete replacement and
the cost of operation and maintenance. After comparing the three equipment,
SIEMENS SST 5000 is chosen to be the equipment for the design for it has
the lowest relative capital cost and highest overall efficiency in the three
manufacturers.

Summary of Equipment
The summary of equipment shows how the specification of each
component are chosen based on the selection parameter required in the
calculation of the design options.

32
 Table 28
Summary of Equipment
Tag. No. Component Selection Parameter Specification Page No.

Fuel: Sub-Bituminous
Typical Fuels: Bituminous, sub-
Capacity: 962.25 MW bituminous. Lignite A, Oil and gas
Pressure: 200 bar Capacity: up to 1350 MWe
Reheat Temperature: Pressure: up to 330 bar Appendix B,
BT-10X Boiler 540 °C page 124
Temperature: 650/670°C
Reheat Pressure: 65
bar Reheat Pressure: 330 bar
Reheat Temperature: Reheat Temperature: 650/670°C
540 °C

Power Output: 300 MW Power Output: 200 MW – 500

MW
Inlet Pressure: 200 bar Frequency: 60 Hz
Inlet Pressure: up to 260 bar/
ST-10X Steam Turbine Inlet Temperature: Appendix B,
3770 psi
540°C page 123
Inlet Temperature: up to 600°C/
Reheat Temperature: 1112°F
540°C Reheat Temperature: up to
610°C/ 1130°F
Condenser Thermal Load: 1820
Pressure: 50 mbar MW
Appendix B,
C-10X Condenser Circulating Water Pressure: 55 mbar
page 124
Temperature: 30°C Circulating Water Temperature:
25°C

CFWH- Close Pressure ratings: 400-800 psig Appendix B,

Pressure: 928.3 psig
10X Feed water Heater (low to high pressure) page 127

DRT- Mass flow rate: 3240 Total Tank Volume: 11,575 liters Appendix B,
Deaerator
10X kg/h Steam Requirements: 3240 kg/h page 124

Flows: 5220m3/h
Flows: 1450m3/h
Head: 100 m
BFP- Pressure: 50 bar Appendix B,
Boiler Feed Pump Pressure: up to 517 bar
10X Temperature: 263°C page 125
Temperature range: up to 318°C
Efficiency:85%
Efficiency: up to 85%

Flows: 13600m3/h
Flows: 1144m3/h
Head: 1070 m
Condensate Pressure: 0.05 bar Appendix B,
CP-10X Pressure: up to 100 bar
Extraction Pump Temperature: 32°C page 125
Temperature range: up to 230°C
Efficiency:85%
Efficiency:85%

33
 Flows: 543m3/h Flows: 9085m3/h
FGP- Appendix B,
Flue Gas Pump Temperature: 150°C Head: 100 m
10X page 126
Temperature range: up to 150°C
Flows: 181700m3/h
Flows: 180000m3/h
CWP- Circulating Water Head: 110 m Appendix B,
Pressure: up to 517 bar
10X Pump Pressure: up to 5bar page 126
Temperature: 30°C
Temperature range: up to 318°C

Frequency: 60 Hz
Power factor: 0.85
Apparent Power: 510 MVA to
Power: 300 MVA Appendix B,
G-10X Generator 1400 MVA
Efficiency: 100% page 126
Efficiency: Up to 99%
Terminal Voltage: 19-25 kV
Output Voltage: 26kV

Table 28 shows the summary of equipment to be used in the

construction of the 600 MW coal – fired power plant. Each component is
named by tag numbers and has selection parameter used in the calculation of
the design options. The specifications of the components are chosen based
on the required parameter of the design.

Components of a Coal-Fired Power Plant

1. Steam Turbine
The steam turbine serves as the heart of the power plant as it is
responsible in converting the kinetic energy of steam into mechanical
energy from the blades in order to generate electric energy in the
generator. The steam turbine to be used is SST-5000 manufactured by
Siemens Company with an operating capacity of 200MW-500MW, inlet
pressure of up to 260 bar, main and reheat temperature of 600 oC,
frequency of 60 Hz, and efficiency of 53%.

34
 Figure 10. SST 5000, SIEMENS

2. Boiler
Two-Pass Boiler by GE CFB Technology will be installed for the
proposed coal fired power plant design. The sub-bituminous coal from
Semirara is a suitable type of fuel for this boiler. The boiler has a
capacity of 1350 MW, a pressure of 330 bar and a temperature ranges
from 650-670oC.

Figure 11. Two Pass Boiler, GE

3. Condenser
The condenser equipment to be used is 2017 Steam Power
Systems Product Catalog (GE Single Vacuum Type Condenser) having
an operating pressure of 0.05 bar, circulating seawater temperature of
30oC rising to 33 oC, circulating water flow of 50m3/s, and a tube length
of 16.5 meters.

35
 Figure 12. Condenser, GE

4. Generator
A water-cooled generator is used for the coal fired power plant.
A water cooled generator is well suited for large power station
applications where output requirements exceed the cooling capabilities
of air-cooled or conventional hydrogen-cooled options. The apparent
power of the generator is up to 1120 MVA and has a terminal voltage
of up to 26 kV.

Figure 13. Gigatop Generator. GE

5. Feed water Heater

Feed water heaters are provided for the temperature increase of

the feed water before it circulates in the boiler. Six feedwater heaters
will be used for each unit. The feed water heater to be used is
Energyen Spx Heater, a versatile heater that can be installed both in
high pressure and low pressure.

36
 Figure 14. SPX Heater, Energyen

6. Deaerator
A single deaerator is installed per unit. he deaerator’s purpose
is to remove dissolved gases from the feed water to prevent corrosion.
Steam from the intermediate pressure turbine and feedwater from the
feedwater heater will openly mix increasing the feedwater temperature.
A thermal deaerator from Eurowater is installed in the plant

Figure 15. Deaerator, Eurowater

7. Pump

The pump that will be installed in the coal fired power plant is
from Flowserve. The boiler feed pump can deliver a maximum flowrate
of 1.45m3/s with a head up to 4270m and a temperature limit of 315C.
The circulating water pump has an operational flow rate of 50m 3/s with
a head of 110m. The selected design is a vertical wel-pit pump suitable
for extended operation in condenser cooling water service. The
condensate extraction pump has a maximum flow rate of 3.778m 3/s
37
 with a head of up to 1070m designed for continuous plant operations.
The flue gas desulfurization pump flows up to 2.5m3/s with a 100m
head and temperature limit of 150C.

8. Pulveriser
The pulveriser is responsible for coal preparation for increased
combustion efficiency. A pulverized reject hopper is installed together
with the pulverizer. The hopper returns the coal not small enough for
the combustion process. Suitably pulverized coal will be transported to
the feeder for combustion.

9. Chimney
The product of combustion of the boiler is exhausted in the
chimney as a flue gas. A flue-gas type of chimney is to be used for it is
fitted on the design consideration of the power plant. It can be
observed that in a flue-gas type of chimney, condensate is being
spitted. The chimney has a height of 220m and a diameter of 10m.

10. Coal Conveyor

The coal conveyor serves as the component responsible in
transmitting the coal into the furnace. The coal conveyor spans from
the port were the cargo vessels transport the coal up to the coal yard.
Other units of coal conveyor will transport the coal from the coal yard to
the boiler’s coal silo.

11. Coal Feeder

For maximum handling efficiency of coal, aluminum coal feeders
will be utilized. Unloaded coal from the coal silo is placed on the bottom
rails and feeder gates are provided. Rotary coupler is also provided for
rotary dumping.

Process/Schematic/System Diagram
Other systems in the power plant includes flue gas treatment system
for the removal of dust and components of combustion; ash handling system
38
for the proper disposal of bottom ash product from the combustion process;
and water treatment system for the reverse osmosis and demineralization of
water to remove elements and minerals from seawater which causes damage
in the components of power plant and in the piping system.

Figure 16. Flue Gas Treatment System

The treatment of flue gases enters the selective catalytic reactor which
uses ammonia as the catalyst from the ammonia tank for denitrification
converting nitrogen oxide emissions (NO x) to diatomic non-polluting nitrogen
(N2). Removal of suspended dust in the electrostatic precipitator happens by
applying a high-voltage charge in the flowing gas. For desulfurization, seawter
is sprayed into the gas which chemically reacts to the sulfur content in the
stream reducing sulfur emissions. All the fly ash will be collected and will be
sold to cement companies. Used waste water will be transported to waste
water storage basin were it will be properly treated before being released to
the sea.

Figure 17. Ash Handling System

39
 The ash from the combustion of coal is properly handled through ash
handling system. This system cools down the raw ash to a manageable
temperature before transferring it to the slurry tank. The coarse ash from the
boiler is conveyed and treated to reduce its size for better handling. The
collected ash in the bottom is transported in a to store it temporarily.

Figure 18. Water Treatment System Diagram

Water treatment system obtains water from Balayan Bay to be used in
the power plant. The sea water is pumped to the reverse osmosis plant to
desalinate the water. It is then pumped to the demineralization plant to purify
the water and will be then transferred to the filtered water tank,
demineralization tank, and make up water tank prior to entering the condenser
were it will be used as either cooling water or makeup water. The waste water
will be treated before being returned to Balayan Bay to ensure environmental
protection.

Environmental Impact Assessment (EIA)

A power plant is very important for a developing country, particularly

for its nation's trade and industry. One such scheme that is becoming
common among nations is the generation of steam power. The environmental
effects of the design project buildings, as well as the effect during building and
operation, will always be evaluated in the building of a steam power plant. It
also believes an action to be taken to decrease environmental pollution. There

40
are things that cannot be avoided but can be minimized by means of studies
and compliance with norms.

In determining the environmental effects to the society, the following

components will be regarded: water, soil, air, nose, and fisheries, as the place
of the plant is near the ocean. The effects will be examined in each to
determine the environmental impacts on and after the plant's building.

A. Air
One of the major impacts of constructing a steam energy plant is
the effect on air quality. During operation, the heat in the boiler will release
several pollutants such as sulfur dioxide, nitrogen oxide, and other gasses
into the environment. Other pollutants include intermittent fugitive dust
emissions during the construction period; car exhausts used for
transportation of employees, transportation of construction materials and
basic equipment, and transportation during power plant operation.

Dust is produced during early construction activities due to the

movement of cars and trucks, especially during earthworks such as
excavation, foundation work, leveling, using sand and cement building.
Harmful gasses emitted by generators, vehicles, and trucks can also affect
air quality momentarily. Emissions from dangerous materials stored and
used on site are also issues to be considered during the construction
phase. This effect is considered to be temporary and has a slightly
negative significance. As the main fuel, the power plant will burn coal. As a
consequence, during the normal operation of the power plant, particulate
matter and greenhouse gas emissions will be very high.

B. Solid Waste, Hazardous, and Special Waste and Soil Pollution

Several wastes such as packing waste, metal scrap, and surplus
equipment, rooted vegetation, and excess soil will be produced during the
building of the power plant. The waste produced may be a health hazard
and may pollute waterways if disposed of incorrectly.

41
 C. Water
For the cooling system, a steam power plant must operate close to
a large body of water, hence there is a risk of water contamination
affecting the surrounding animal life and the potential for human use.

D. Fish and Fisheries

The discharge of waste liquids into the river has an adverse effect on
fishing and commercial fishing. These effluents of liquid waste can be
contaminated with chemicals and should be treated before discharge.
Natural dilution and dispersion in the building region will ensure a fast
decrease to background levels of the suspended sediment load and
elevated levels of pollutants.

G. Plant Noise

Disturbance to surrounding communities due to noise is also a

major issue in the building of a power plant. Building activities will lead to
higher noise levels at the project site and along the typical pipeline route of
roadwork. Noise can also be produced from steam machines that blow off
the atmosphere during operation.

Socio-economicc Benefits

Building a steam power plant provides some socio-economic benefits

that will help satisfy present population demands without harming the capacity
to satisfy the needs of future generations. The construction of power plants
will most likely provide job opportunities for local people in order to have a
favorable impact on the domestic economy.

Increased demand for materials, local source facilities, and work

possibilities will be opened up. The project will also bring economic benefits to
neighboring villages and communities like restaurants, gas stations, hotels
and apartment buildings, local food markets, etc. In other words, it will have a
positive indirect impact on the regional economy. The operation of the steam
power plant will generate fresh taxes and revenue, helping to boost the
finances and ultimately benefit the local population.

42
 The power plant project enables a part of the production to be retained
without the need to purchase carbon dioxide emission allowances related to
the combustion of fuels.

Environmental Impact Mitigation Measures

The required steps will be integrated into the power plant design to
avoid or minimize future environmental operational impacts. The following
mitigation measures will be implemented to mitigate the potential adverse
effects connected with the operation of the proposed power plant:

A. Waste Water
Water supply is one of the demands for the steam power plant's
building and operation. This will be given in the project region from the
creek and/or comparable water sources. As a result, the water used during
building became polluted, contaminating water bodies that can influence
both aquatic and human life.

It is necessary to meet and/or purchase drinking water for staff from

the region's drinking water network from the market. In the wastewater
treatment plant package, domestic wastewater from staff requirements will
be handled.

B. Solid Waste, Hazardous, and Special Waste and Soil

Pollution
The solid waste produced during the excavation and construction of
the power plant, municipal solid waste such as paper and plastics and
domestic organic waste from private food consumption shall be collected
by the municipalities or organizations concerned separately and properly.
To avoid too much waste dumping, recyclable materials must be
separated from non-recyclable materials. The municipality shall
periodically collect or move the solid waste to designated municipal areas.
To prevent pollution of the environment, appropriate storage area,
management systems, and disposal equipment shall be supplied.

43
Anti-degradation and Clean-up Policy

If the concentration of any parameters specified in this WQG exceeds

the numerical limits for that particular parameter, the natural concentration
shall not be added to that constituent. Variance to this policy shall not be
made unless it can be affirmatively shown that a change is justifiable in order
to provide the necessary economic or social development, that the degree of
waste treatment necessary to preserve the existing quality can not be justified
economically or socially, and that the current and expected uses of such
water will be maintained and protected.

Important Considerations

In addition to meeting the requirements as mentioned earlier, the

following provisions shall be complied with in accordance with the Water
Quality Guidelines and General Effluent Standards of the Department of
Environment and Natural Resources:

1) No individual shall discharge industrial effluents straight into water

bodies or by using bypass channels and/or pumps and other unlawful
means, entirely or partly, untreated or inadequately handled.

2) No water pollution establishment or source shall be operated in

excellent order or inadequate operation without the control equipment or
wastewater treatment scheme. No water pollution institution or source
shall operate at concentrations beyond the operating boundaries or the
capacity of the wastewater treatment facility to preserve the effluent quality
in accordance with the relevant norms or conditions required by law and/or
stipulated in the Discharge Permit.

3) No individual shall construct, erect, install or use any equipment,

machinery or means by which an effluent discharge is concealed and/or
diluted and otherwise infringes any provisions of these regulations.

4) No effluent, according to its classification, shall cause the quality of the

receiving water body to drop below the recommended WQG.

44
 5) No effluent shall be discharged into Class AA and SA waters from any
point sources.

7) In order to prevent deterioration of the quality of the receiving bodies of

water, no new industrial plant with high waste load potential shall
discharge into a water body where the water body's dilution or assimilation
capacity during dry weather is insufficient to maintain its prescribed WQG
according to its classification.

Air Quality

Contractors on-site and should monitor the air mitigation steps and include
at least the following:

 The removal of dust from the site will be used to avoid dust from
becoming a nuisance during the building stage.
 Roads will be compacted and engraved during building if needed
and maintained in good condition;
 Access roads from the site entrance will be compacted and water-
sprayed to minimize the dust produced by cars and trucks;
 The building stage will start with the building of access roads to
minimize the dust from car movements
 Stack and ambient air quality surveillance equipment and testing
equipment shall be supplied to properly determine the nature and
amount of air pollutants emitted as a consequence of the operation
of the power plant.

The Clean Air Act

A plan of action for air quality control shall be formulated and

implemented by the Department of Environment and Natural Resources
(DENR) with public participation. The plan of action shall:

(a) Provide required equipment, techniques, systems, and processes

for monitoring, compiling and analyzing information on ambient air
quality to be established and operated;

45
 (b) Include enforceable emission constraints and other control
measures, means or methods, as well as compliance schedules and
time tables as may be essential or suitable to comply with the relevant
conditions of this Act;

(c) Include a program to provide for the following considerations:

(1) Implementation of the interventions outlined in the

subparagraph;

(2) Regulating the modification and construction of any

stationary source in the fields covered by the scheme in
accordance with the policy on land use to guarantee that
environmental air quality standards are met.

C. Noise
The following steps will mitigate the noise produced during the
building. In the plant operation stage, the indoor regions will be put with
the cooling scheme and turbines. The steam turbine will be the main noise
source, but it will be provided with its own individual noise enclosure and
noise will have no important tonal or impulsive personality. The enclosure
is going to be housed within a building.

Also, consideration must be given to periodic maintenance of

equipment and construction machinery. Appropriate protection instruments
and equipment such as helmets, ear protectors or earplugs will be
provided during both operation and construction stages to safeguard the
health of employees exposed to noisy environments. To guarantee that
there is no disruption at the closest residence, the plant will be situated far
from the settlement fields.

46
 CHAPTER III

ENGINEERING ECONOMIC ANALYSIS

In this chapter, the economic analysis of the proposed design of 600
MW Coal-Fired Power Plant located at Brgy. Balanga, Lemery, Batangas with
the chosen design option using three catalogues (SIEMENS SST 5000 and
SST 4000, and GE) is discussed and reviewed. The analysis includes the
economic costing, depreciation, return of investment and other computations
involved for the economic assets of the coal-fired power plant.

Power Demand Analysis

The proposed coal-fired power plant has a capacity of 600 MW. The
electricity generated will be transmitted to the Luzon Grid of the National Grid
Corporation of the Philippines for further distribution. According to the
ransCo and National Grid Corporation (NGCP), the 0 ’s peak demand of
Luzon Grid will exceed its peak of 10,385 Megawatts on May 2017, peaking at
10876 this June.

Table 29
Monthly System Peak Demand as of 2018 (in MW)
Month (MW)

January 9,213

February 9,579

March 9,936

April 10,539

May 10,570

June 10,876

July 9,996

August 9,843

47
 September 10,035

October 10,346

November 10,088

December 9,987

Source: TransCo and NGCP

This table shows the monthly peak demand in Luzon grid. The data
gathered is around the year of 2018 on which the Luzon experienced a
heightened increase in power demand it is given by National Grid Corporation
(NGCP). Upon observing, the month of June experienced the highest peak
demand at 0 6 MW on which the country’s temperature is at its maximum,
however the month of January has the lowest peak demand on which the
country’s temperature is at its minimum.

Power Demand and Supply Balance

Table 30
Power Generation by Grid as of 2018 (in GWh)
Luzon 72, 728

Visayas 14, 266

Mindanao 12, 770

Total: 99, 765

Source: DOE, Power Statistics Summary

Table 30 above presents the power generated by each grid as of 2018.

The Philippines is composed of three electrical grids including the Luzon grid,
Visayas Grid and the Mindanao grid. One characteristic of the grids is that
most bulk generation sites are found far from the load centers, necessitating
use of long distance transmission lines. The total power generated in the year
2018 amounts to 99, 765 GWh.

48
 Table 31
Power Consumption by Sector as of 2018 (in GWh)
Residential 28, 261

Commercial 24, 016

Industrial 27, 587

Others 2, 753

Electricity Sales 82, 617

Utilities Own Use 8,141

Power Sales 9,007

Total 99,765

Source: DOE, Power Statistics Summary

Table 31 above presents the power consumed by each sector in the
year 2018. Total electricity sales sums up to 82, 617 GWh, adding the power
consumption of utilities and power sales, total power expenditure amounts to
99, 765 GWh.

Table 32
Power Generation by Source in GWh, Total Philippines (2018)
Coal 51, 932

Oil-Based 3,173

Combined Cycle 522

Diesel 2,505

Gas Turbine 0

Oil Thermal 145

Natural Gas 21, 334

Renewable Energy (RE) 23, 326

49
 Geothermal 10, 435

Hydro 9, 384

Biomass 1, 105

Solar 1, 249

Wind 1, 153

Total 99, 765

Source: DOE, Power Statistics Summary

Electricity in the Philippines is produced from various sources such as
coal, oil, natural gas, biomass, hydroelectric, solar, wind, and geothermal
sources. The allocation of electricity production according to data from
the Department of Energy Power Statistics can be seen in the table above.
The total power generation amounts to 99, 765 GWh.

Table 33
Installed Generating Capacity in MW (2018)
Coal 8, 844

Oil-Based 4, 292

Natural Gas 3, 453

Renewable Energy(RE) 7, 227

Geothermal 1, 944

Hydro 3, 701

Biomass 258

Solar 896

Wind 427

Total 23, 815

Source: DOE, Power Statistics Summary

50
 Table 33 above shows the installed generating capacity in MW as of
2018 by the different sources of power in the Philippines. Natural gas has an
installed generating capacity of 3, 453 MW, coal has 8, 844 MW, renewable
energy has 7, 227 MW. Total installed generating capacity as of 2018
amounts to 23, 815 MW.

Table 34
Dependable Generating Capacity in MW (2018)
Coal 8, 368

Oil-Based 2, 995

Natural Gas 3, 286

Renewable Energy(RE) 6, 592

Geothermal 1, 770

Hydro 3, 473

Biomass 182

Solar 740

Wind 427

Total 21, 241

Source: DOE, Power Statistics Summary

Table 34 above presents the data about the dependable generating
capacity in MW of the different sources of energy in the Philippines. Natural
Gas has a dependable capacity of 3, 286 MW, Coal has 8, 368 MW,
Renewable Energy has 6, 592 MW. The generation data includes grid
connected, embedded and off-grid generator.

51
 Table 35
Peak Demand at Batangas
Name of Cooperative Peak Demand (MW)

BATELEC I 67.34

BATELEC II 156.43

FBPC 9.03

IEEC 4.74

Total 234.54

Source: Department of Energy

The table shows the peak demand in each cooperative for Batangas.
The BATELEC II has the highest peak demand with 156.43, constituting
66.7% of the total demand of the province. The FBPC and IEEC has the
lowest peak demand with just 9.03 and 4.74 MW, respectively. The proposed
600 MW coal-fired power plant would be a great factor in increasing the power
source within the Luzon Grid. With the increasing population and demand, the
current source of power will be insufficient with the years to come, and one of
the solutions is building a power plant to satisfy the needs of power.

Table 36
Power Consumption by Sector as of 2018 in Batangas (in MWh)
Residential 492,316

Commercial 273,870

Industrial 242,285

Others 93,117

Total 1,101,588

Source: DOE, Power Statistics Summary

This table presents the power consumption by each sector in the year
2018 which will be covered by the proposed 600 MW coal-fired power plant.

52
The energy consumed in residential sectors were 492,316 MWh, in
commercial sectors were 273,870 MWh, while in industrial sectors were
242,285 MWh and others were 93,117 MWh. The total electricity sales sums
up to 1,101,588 MWh.

Economic Cost
Table 37
Power Demand Analysis (SIEMENS SST 5000)

installed capacity [MW] 600

capacity factor 0.40
Energy GWh/year 2102.400
cost/kW [Php/kW] 9.7599
capital cost [Php] 317,380,808,316.37
Life Years 25
discount rate 0.05
Capital recovery factor 0.070952457
Annual capacity cost PHP 31,738,080,831.64
Fixed O&M PHP 16,173,062,400.00
total fixed cost Php 317,380,808,316.37
Fixed cost/kWh [Php /kWh] 146,732,581.52
Variable cost/kWh [Php /kWh] 5,139,246.785
LCOE [Php /kWh] 21.9836457

Table 37 presents the Power Demand Analysis of Design option 3

using SIEMENS SST 5000 catalogue. The parameters included are installed
capacity that has a value of 600 MW, capacity factor of 40%, and the
assumed and computed energy per year, cost per kilowatt, capital cost, life
years, discount rate, capital recovery factor, annual capacity cost, fixed
operation and maintenance cost, total fixed cost, fixed cost per kilowatt,
variable cost per kilowatt and LCOE based on the catalogue selected.

The proposed coal-fired power plant design option will be having a

365-day operation.

53
 Table 38
Depreciation (SIEMENS SST 5000)
Service
Life Depreciation
Book Value(Php) Salvage Value (yrs) (BV-SV)/SL
Purchased 4,961,062,839.0
Equipment 193,911,717,260.00 69,885,146,260.00 25 0
Instrumentatio
n and Control 38,782,343,452.00 13,977,029,252.00 25 992,212,567.00
Service
Facilities 19,391,171,726.00 6,988,514,626.00 25 496,106,283.00
Etc 29,086,757,589.00 10,482,771,939.00 25 744,159,425.00
7,193,541,117.0
Total 0

Table 38 above presents the depreciation values of the purchased

equipment, instrumentation and control, service facilities and auxiliary
systems with a service life of 25 years.

Table 39
Return of Investment (SIEMENS SST 5000)
Net Income After
Period TCI ROI
Year Tax
(Php) (Php) (%)
2019 2 316,888,599,133.8 45,118,262,840.00 14.2378939
2020 3 271,770,336,293.8 45,118,262,840.00 16.6016142
2021 4 226,652,073,453.8 45,118,262,840.00 19.9063975
2022 5 181,533,810,613.8 45,118,262,840.00 24.8539171
2023 6 136,415,547,773.8 45,118,262,840.00 33.0741352
2024 7 91,297,284,933.8 45,118,262,840.00 49.4190630
2025 8 46,179,022,093.8 45,118,262,840.00 97.7029412
Average 36.5422803

Table 39 shows the return of investment of the proposed plant through

the first 7-year service life with an average of 36.5422803% ROI. On the 6th
year, the power plant will be able to return the investment with a rate of 97.%.

54
 Table 40
Payback Period (Siemens SST 5000)

Net Income TCI Depreciation

Year
after Tax (Php) (Php) (Php)
2019 45,118,262,840.00 316,888,599,133.8 7,193,541,117.95
2020 45,118,262,840.00 271,770,336,293.8 7,193,541,117.95
2021 45,118,262,840.00 226,652,073,453.8 7,193,541,117.95
2022 45,118,262,840.00 181,533,810,613.8 7,193,541,117.95
2023 45,118,262,840.00 91,297,284,933.8 7,193,541,117.95
2024 45,118,262,840.00 46,179,022,093.8 7,193,541,117.95
Payback
Period 5 years

Table 40 presents the depreciation through the 5-year service life of

the proposed coal fired power plant and the payback period by dividing the
total annual cost to the profit element. The chosen design option using the
SIEMENS SST 500 catalogue has a total of 5 years of payback period.

Table 41
Sensitivity Analysis (SIEMENS SST 5000)
Change ENPV EIRR

Base Case PHP %

Construction delay 1 year 97,456,823.15 11.674333

Reduce of Power Generation 10% 55,220,734,218 0.7643

by 10%

Increase of Fuel Price by 10% 10% 83,892,331,143 8.2321

Drop of Fuel Price by 10% 10% 93,342,756,912 9.1181

Table 41 shows the sensitivity analysis using the SIEMENS SST 500
catalogue when the power generation is reduced by 10%, the fuel price is
increase by 10%, and when the fuel price drop by 10%.

55
CASE 1. Reduce of Power Generation by 10%

The first case is a sudden reduce of the generated power by 10% in

the span of 25 years is shown by the graph to find the breakeven point for
design option 2 using SST 5000:

Chart Title
1,400,000,000,000.00

1,200,000,000,000.00

1,000,000,000,000.00

800,000,000,000.00

600,000,000,000.00

400,000,000,000.00

200,000,000,000.00

0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 19. Break-Even Graph (Case 1/ SST 5000)

This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using SST 5000. The intersection point is the breakeven point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 11.5th year.

CASE 2. Increase in fuel cost by 10% every year.

The second case is an increase in fuel cost by 10% in the span of 25

years is shown by the graph to find the breakeven point for design option 2
using SST 5000:

56
 Chart Title
1,600,000,000,000.00
1,400,000,000,000.00
1,200,000,000,000.00
1,000,000,000,000.00
800,000,000,000.00
600,000,000,000.00
400,000,000,000.00
200,000,000,000.00
0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 20. Break-Even Graph (Case 2/ SST 5000)

This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using SST 5000. The breakeven point is the intersection point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 9th year.

CASE 3. Drop of fuel price by 10%

The third case is a sudden drop of fuel price by 10% in the span of 25
years is given by the graph to find the breakeven point for design option 2
using SST 5000:

Chart Title
1,600,000,000,000.00
1,400,000,000,000.00
1,200,000,000,000.00
1,000,000,000,000.00
800,000,000,000.00
600,000,000,000.00
400,000,000,000.00
200,000,000,000.00
0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 21. Break-Even Graph (Case 3/ SST 5000)

57
 This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using SST 5000. The breakeven point is the intersection point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 10th year.
Table 42
Power Demand Analysis (SIEMENS SST 4000)

installed capacity [MW] 600

capacity factor 0.40
Energy GWh/year 2102.400
cost/kW [Php/kW] 9.7599
capital cost [Php] 323,352,682,813.56
Life Years 25
discount rate 0.05
Capital recovery factor 0.070952457
Annual capacity cost PHP 32,335,268,281.35
Fixed O&M PHP 17,214,143,300.00
total fixed cost Php 323,352,682,813.56
Fixed cost/kWh [Php /kWh] 138,651,234.52
Variable cost/kWh [Php /kWh] 5,923,653.164
LCOE [Php /kWh] 23.2834761

Table 42 presents the Power Demand Analysis of Design option

2 using SIEMENS SST 4000 catalogue. The parameters included are
installed capacity that has a value of 600 MW, capacity factor of 40%.

Table 43
Depreciation (Siemens SST 4000)
Service
Life Depreciation
Book Value(Php) Salvage Value (yrs) (BV-SV)/SL
Purchased
Equipment 197,507,050,260.00 69,885,146,260.80 25 5,053,046,311.59
Instrumentation
and Control 39,501,410,052.00 13,977,029,252.16 25 1,010,609,262.31
Service
Facilities 19,750,705,026.00 6,988,514,626.08 25 505,304,631.15
Etc 29,626,057,539.00 10,482,771,939.12 25 757,956,946.73
Total 7,326,917,151.81

58
 Table 43 above presents the depreciation values of the purchased
equipment, instrumentation and control, service facilities and auxiliary
systems with a service life of 25 years.

Table 44
Return of Investment (Siemens SST 4000)
Net Income After
Period TCI ROI
Year Tax
(Php) (Php) (%)
2019 2 322,748,991,923.8 45,118,262,840.00 13.97936
2020 3 277,630,729,083.8 45,118,262,840.00 16.25117
2021 4 232,512,466,243.8 45,118,262,840.00 19.40466
2022 5 187,394,203,403.8 45,118,262,840.00 24.07665
2023 6 142,275,940,563.8 45,118,262,840.00 31.71180
2024 7 97,157,677,723.8 45,118,262,840.00 46.43818
2025 8 52,039,414,883.8 45,118,262,840.00 86.70017
Average 34.08028

Table 44 shows the return of investment of the proposed plant through

the first 9-year service life with an average of 34.08028943% ROI. On the 7th
year, the power plant will be able to return the investment with a rate of
86.70%.

Table 45
Payback Period (Siemens SST 4000)
Net Income TCI Depreciation
after Tax (Php) (Php) (Php)
2019 4,511,826,840.00 322,748,991,923.8 7,326,917,151.81
2020 4,511,826,840.00 277,630,729,083.8 7,326,917,151.81
2021 4,511,826,840.00 232,512,466,243.8 7,326,917,151.81
2022 4,511,826,840.00 1873,94,203,403.8 7,326,917,151.81
2023 4,511,826,840.00 142,275,940,563.8 7,326,917,151.81
2024 4,511,826,840.00 97,157,677,723.8 7,326,917,151.81
2025 4,511,826,840.00 52,039414,,883.8 7,326,917,151.81
Payback Period 6 years

The table presents the depreciation through the 6-year service life of
the proposed coal fired power plant and the payback period by dividing the

59
total annual cost to the profit element. The chosen design option using the
SIEMENS SST 4000 catalogue has a total of 6 years of payback period.

Table 46
Sensitivity Analysis (Siemens SST 4000)
Change ENPV EIRR

Base Case PHP %

Construction delay 1 year 93,543,765.21 10.312423

Reduce of Power Generation by 10% 10% 43,110,238,275 0.69141

Increase of Fuel Price by 10% 10% 76,546,123,976 7.8364

Drop of Fuel Price by 10% 10% 84,742,528,369 8.9262

Table 46 shows the sensitivity analysis using the Siemens SST 4000
catalogue when the power generation is reduced by 10%, the fuel price is
increase by 10%, and when the fuel price drop by 10%.

CASE 1. Reduce of Power Generation by 10%

The first case is a sudden reduce of the generated power by 10% in

the span of 25 years is shown by the graph to find the breakeven point for
design option 2 using SST 4000:

Chart Title
1200000000000.00

1000000000000.00

800000000000.00

600000000000.00

400000000000.00

200000000000.00

0.00
1 2 3 4 5 6 7 8 9 10111213141516171819202122232425

Series1 Series2

Figure 22. Break-Even Graph (Case 1/SST 4000)

60
 This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using SST 4000. The intersection point is the breakeven point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 12th year.

CASE 2. Increase in fuel cost by 10% every year.

The second case is an increase in fuel cost by 10% in the span of 25

years is shown by the graph to find the breakeven point for design option 2
using SST 4000:

Chart Title
1,400,000,000,000.00

1,200,000,000,000.00

1,000,000,000,000.00

800,000,000,000.00

600,000,000,000.00

400,000,000,000.00

200,000,000,000.00

0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 23. Break-Even Graph (Case 2/SST 4000)

This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using SST 4000. The breakeven point is the intersection point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 10.5th year.

CASE 3. Drop of fuel price by 10%

The third case is a sudden drop of fuel price by 10% in the span of 25
years is given by the graph to find the breakeven point for design option 2
using SST 4000:

61
 Chart Title
1,400,000,000,000.00

1,200,000,000,000.00

1,000,000,000,000.00

800,000,000,000.00

600,000,000,000.00

400,000,000,000.00

200,000,000,000.00

0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 24. Break-Even Graph (Case 3/SST 4000)

This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using SST 5000. The breakeven point is the intersection point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 11th year.

Table 47
Power Demand Analysis (GE STF D650)

installed capacity [MW] 600

capacity factor 0.40
Energy GWh/year 2102.400
cost/kW [Php/kW] 9.7599
capital cost [Php] 327,544,792,888.92
Life Years 25
discount rate 0.05
Capital recovery factor 0.070952457
Annual capacity cost PHP 32,754,479,288.89
Fixed O&M PHP 18,093,264,348.00
total fixed cost Php 327,544,792,888.92
Fixed cost/kWh [Php /kWh] 133,631,234.52
Variable cost/kWh [Php /kWh] 6,375,836.785
LCOE [Php /kWh] 26.342765

Table 47 presents the Power Demand Analysis of Design option 3

using GE STF D650 catalogue. The parameters included are installed

62
capacity that has a value of 600 MW, capacity factor of 40%, and the
assumed and computed energy per year, cost per kilowatt, capital cost, life
years, discount rate, capital recovery factor, annual capacity cost, fixed
operation and maintenance cost, total fixed cost, fixed cost per kilowatt,
variable cost per kilowatt and LCOE based on the catalogue selected. The
proposed coal fired power plant design option will be having a 365-day
operation.
Table 48
Depreciation (GE STF D650)
Service
Book Life Depreciation
Value(Php) Salvage Value (yrs) (BV-SV)/SL
Purchased
Equipment 200,126,507,160.00 72,124,936,136.72 25 5,120,062,840.93
Instrumentation
and Control 40,025,301,432.00 14424987227.34 25 1,024,012,568.18
Service
Facilities 20,012,650,716.00 7,212,493,613.67 25 512,006,284.09
Etc 30,018,976,074.00 10,818,740,420.50 25 768,009,426.13
Total 7,424,091,119.34

Table 48 above presents the depreciation values of the purchased

equipment, instrumentation and control, service facilities and auxiliary
systems with a service life of 25 years.

Table 49
Return of Investment (GE STF D650)
Net Income After
Period TCI ROI
Tax

Year
(Php) (Php) (%)

2019 2 327018706670.8 45,118,262,840.00 13.79684

2020 3 281900443830.8 45,118,262,840.00 16.00503
2021 4 236782180990.8 45,118,262,840.00 19.05475
2022 5 191663918150.8 45,118,262,840.00 23.54030
2023 6 146545655310.8 45,118,262,840.00 30.78785
2024 7 101427392470.8 45,118,262,840.00 44.48331
2025 8 56309129630.8 45,118,262,840.00 80.12601
Average 32.54201

63
 Table 49 shows the return of investment of the proposed plant through
the first 9-year service life with an average of 32.5420166% ROI. On the 7th
year, the power plant will be able to return the investment with a rate of
80.12%.

Table 50
Payback Period (GE STF D650)
Net Income TCI Depreciation
Year
after Tax (Php) (Php) (Php)
2019 4,511,826,840.00 327018706670.8 7,326,917,151.81
2020 4,511,826,840.00 281900443830.8 7,326,917,151.81
2021 4,511,826,840.00 236782180990.8 7,326,917,151.81
2022 4,511,826,840.00 191663918150.8 7,326,917,151.81
2023 4,511,826,840.00 146545655310.8 7,326,917,151.81
2024 4,511,826,840.00 101427392470.8 7,326,917,151.81
2025 4,511,826,840.00 56309129630.8 7,326,917,151.81
Payback
Period 6 years

Table 50 presents the depreciation through the 6-year service life of

the proposed coal fired power plant and the payback period by dividing the
total annual cost to the profit element. The chosen design option using the GE
STF D650 catalogue has a total of 6 years of payback period.

Table 51
Sensitivity Analysis (STF D650)
Change ENPV EIRR

Base Case PHP %

Construction delay 1 year 89,001,730.15 10.674333

Reduce of Power Generation by 10% 10% 50,091,723,000 0.7198

Increase of Fuel Price by 10% 10% 81,063,172.00 7.7361

Drop of Fuel Price by 10% 10% 90,149,001,.98 8.6972

64
 Table 51 shows the sensitivity analysis using the GE STF D650
catalogue when the power generation is reduced by 10%, the fuel price is
increase by 10%, and when the fuel price drop by 10%

CASE 1. Reduce of Power Generation by 10%

The first case is a sudden reduce of the generated power by 10% in

the span of 25 years is shown by the graph to find the breakeven point for
design option 2 using STF D650:

Chart Title
1,400,000,000,000.00

1,200,000,000,000.00

1,000,000,000,000.00

800,000,000,000.00

600,000,000,000.00

400,000,000,000.00

200,000,000,000.00

0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 25. Break-Even Graph (Case 1/ STF D650)

This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using STF D650. The breakeven point is the intersection point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 11th year.

CASE 2. Increase in fuel cost by 10% every year.

The second case is an increase in fuel cost by 10% in the span of 25
years is shown by the graph to find the breakeven point for design option 2
using STF D650:

65
 Chart Title
1200000000000.00

1000000000000.00

800000000000.00

600000000000.00

400000000000.00

200000000000.00

0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 26. Break-Even Graph (Case 2/ STF D650)

This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using STF D650. The breakeven point is the intersection point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 12.5th year.

CASE 3. Drop of fuel price by 10%

The third case is a sudden drop of fuel price by 10% in the span of 25
years is given by the graph to find the breakeven point for design option 2
using STF D650:

Chart Title
1,200,000,000,000.00

1,000,000,000,000.00

800,000,000,000.00

600,000,000,000.00

400,000,000,000.00

200,000,000,000.00

0.00
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Series1 Series2

Figure 27. Break-Even Graph (Case 3/ STF D650)

66
 This graph shows the behavior of the cash inflow and cash outflow for
design option 2 using STF D650. The breakeven point is the intersection point
in which the power plant recovers its initial capital. The breakeven point of the
plant is on the 13th year.

Table 52
Economic Analysis of the Three Catalogues (Design Option 2)

Parameters SIEMENS SST SIEMENS SST GE

5000 4000
STF D650

Cost (Php) Php Php Php

193,911,717,260.0 197,507,050,260.00 200,126,507,160.00

Payback 5 years 6 years 6 years

Period

Table 52 shows the summary of the economic analysis using the three
catalogues in terms of the total cost and the payback period. It shows that
best catalogue to use in design option two is the Siemens SST 5000
catalogue.

67
 CHAPTER IV

OBSERVATION, COMMENTS AND RECOMMENDATIONS

This chapter presents the observations, comments, and

recommendations on the design selected for the proposed 300 MW Coal-
Fired Power Plant.

Observation
After the analysis and evaluation of all the data gathered, the following
are the observations are listed:
The proposed location of 600 MW Coal-Fired Power Plant which
is at Barangay Balanga, Lemery, Batangas was observed to be
feasible and advantageous for the construction and operation of the
proposed power plant. The transmission of the generated electricity of
the proposed power plant for the Luzon Grid will be the responsibility of
the National Grid Corporation of the Philippines (NGCP) and this
company will distribute the generated electricity to the customers of the
Batangas province electric cooperatives namely; BATELEC I,
BATELEC II, First Bay Power Corporation (FBPC) and Ibaan Electric
Engineering Corporation (IEEC) will transmit the generated electricity
to within reach provinces.

Comments and Recommendations

From the data and findings of the proposed 600 MW Coal-Fired Power
Plant, the following comments were made:
1. The proposed coal-fired power plant appeared in all aspects of
design consideration in designing a power plant. Plant factors were
determined high and satisfactory viable for the design to be considered
acceptable.
2. Having a background and a broad technical knowledge about this
kind of steam power plant would be a great advantage to come up with
a better and acceptable design.
3. The obtained values from the calculations are within the range of the
specifications of available power plant components.

68
 4. All equipment and miscellaneous facilities were satisfactorily
designed and evaluated.
5. Technical information has been at hand through the use of related
references and the use of the internet, which provides the equipment
catalogue and it is based on the manufacturer’s specifications to get
the best design possible for the proposed power plant.

For the improvement and development of the proposed 600 MW Coal-

Fired Power Plant, the following recommendations were brought up:
1. Further research and evaluation of the present technologies,
equipment, and operation of existing power plants are essential for
more advanced and progressive design.
2. The proponents should be more familiar with each of the equipment
specifications and it’s functions which are important in designing
and constructing a power plant.
3. Assessment of the environmental impact of the plant should be
evaluated following the guidelines presented by the power
development program of the national energy policy
4. Additional information through consultation with the concerned
person helps the proposed power plant to enhance the design and
make it possible and presentable for the actual plant construction.
5. Economic analysis must be done for the designed power plant for a
better presentation of profits to attract more investors.

69
 CHAPTER V

BIBLIOGRAPHY

Department of Energy (2018) 2018 Power Statistics Retrieved June 22, 2019,
from
https://www.doe.gov.ph/sites/default/files/pdf/energy_statistics/01_201
8_
power_statistics_as_of_29_march_2019_summary.pdf?fbclid=IwAR0O
rATEnDUV_pNL9m89ceJDD4k8dRljfIpHjueFwkszSf4Ev3dYIKNInwk
Department of Energy (2018) Luzon, Visayas and Mindanao grids - Annual
System Peak Demand per Grid as of 2018 in MW Retrieved June 22,
2019, from
https://www.doe.gov.ph/sites/default/files/pdf/energy_statistics/
01_2018_power_statistics_as_of_29_march_2019_summary.pdf?fbclid
=IwAR0OrATEnDUV_pNL9m89ceJDD4k8dRljfIpHjueFwkszSf4Ev3dYI
KNInwk
Department of Energy (2018) Monthly System Peak Demand as of 2018
Retrieved June 22, 2019, from
https://www.doe.gov.ph/sites/default/files/pdf/
energy_statistics/08_2018_power_statistics_as_of_29_march_2019_m
onthly_lvm_peak_demand.pdf?fbclid=IwAR0Nr56haWzlbSsoBVd-
OVuJlQIYho4-itUjRMQIhUi4EsEoOK8VcmM7sAM

BATELEC I COMPUTATION OF GENERATION RATE 2019 Retrieved 06-20-

19,
http://www.batelec1.com.ph/index.php/services/downloads/category/6-
generation-rate-2019

BATELEC II COMPUTATION OF GENERATION CHARGES 2019 Retrieved

06-20-19

Mechanical Booster, Steam power plant construction, working, advantages

and disadvantages with diagram. Retrieved June 23, 2019
https://www.mechanicalbooster.com/2016/08/steam-power-plant.html

Siemens SPP SST 5000, Retrieved June 23, 2019,

https://www.slideshare.net/mobile/vigneshsekaran520/SiemensSPPST
T5000

Gigatop 2 pole specification, Retrieved June 23, 2019,

https://www.slideshare.net/mobile/vigneshsekaran520/Gigatop

70
GE power Boiler, Retrieved Retrieved June 23, 2019,
https://www.ge.com/power/steam/boilers

GE power Condenser, Retrieved Retrieved June 23, 2019,

https://www.ge.com/power/steam/heat-exchange/condenser

Recommended Velocities in Steam Systems, Retrieved Retrieved July 9,

2019, https://www.engineeringtoolbox.com/flow-velocity-steam-pipes-
d_386.html

Steel Pipe Dimensions - ANSI Schedule 40 Retrieved Retrieved July 8, 2019,

https://www.engineeringtoolbox.com/ansi-steel-pipes-d_305.html

Steam System Piping Design Retrieved Retrieved July 8, 2019,

http://www.wermac.org/steam/steam_part9.html

Flowserve, Wet Pit Pumps Retrieved Retrieved July 8, 2019,

https://www.flowserve.com/en/products/pumps/vertical-pumps/wet-pit-
pumps/wet-pit-pumps-vct

71
 APPENDIX A
COMPUTATIONS

72
BOILER EFFICIENCY

The losses in the boiler are made up of chimney losses(dry gas loss,
moisture loss, humidity loss), unburnt losses, radiation losses, and
unaccountable losses

1. Chimney Loss

The typical flue gas temperature for thermal power plants is

equal to 160 oC, and the location’s ambient temperature is o
C.

a. Dry Flue Gas Loss

( )

b. Moisture Loss
( )

c. Humidity Loss
( )

73
2. Unburnt Loss

5% of Carbon residue was assumed

3. Radiation Loss
Radiation Loss is assumed to contribute 1% at maximum.

4. Unaccountable Loss

Unaccountable losses was assumed to contribute 10% of

losses.

Adding up all the losses:

Solving for the boiler efficiency:

74
COAL ANALYSIS

Ultimate Analysis of Sub-Bituminous Coal

Sample 1 Sample 2 Sample 3 Sample 4 Sample 5 Ave.

Hydrogen 4.39 4.41 4.29 4.46 4.04 4.318

Carbon 57.34 58.29 55.21 58.46 53.48 56.556

Nitrogen 1.07 1.05 1.01 1.07 0.99 1.038

Sulfur 0.77 0.73 0.77 0.77 0.72 0.752

Oxygen 16.6 16.45 16.13 16.44 16.06 16.336

Ash 19.83 19.07 22.59 18.8 24.71 21

( )

( )

The higher heating value with the consideration of the boiler efficiency:

( )

( )

75
 Pulverized coal fired boilers run with an average of 20% excess air to
burn the fuel completely:

The ambient temperature for the municipality of Lemery is 27 oC.

Computing for the humidity of air:

The actual air fuel ratio with consideration to excess air requirements
along with the humidity of the air in the location is as follows:

( )

76
Design Option 1

STATE POINT CALCULATIONS

State Pressure Enthalpy

Temp. (oC) Masssteam (kg/s)
Point (Mpa) (kJ/kg)
1 20 540 3366.370 419.910
2 7.5 375.498 3080.280 36.005
3 7.5 540 3502.650 384.223
4 5 469.812 3363.980 348.218
5 2 330.068 3092.920 307.504

77
 6 0.5 163.635 2775.750 278.926
7 0.1 99.6059 2498.250 237.867
8 0.005 32.8743 2119.920 237.867
9 0.005 32.8743 137.749 384.223
10 0.1 32.8768 137.845 307.504
11 0.1 99.6059 417.504 76.719
12 0.5 99.6335 417.921 307.504
13 0.5 151.831 640.085 28.578
14 2 151.999 641.724 307.504
15 2 212.377 908.498 40.715
16 5 212.935 912.028 307.504
17 5 263.941 1154.640 419.910
18 7.5 284.692 1157.856 419.910
19 7.5 290.535 1292.930 36.005
20 20 295.439 1310.326 419.910

MASS BALANCE

Mass balance for extracted steams in the turbines:

78
SOLVING FOR THE MASS OF THE STEAM ASSUMING A TURBINE
OUTPUT OF 300MW:

W m h h mm h h m m m (h h ) mm m m (h h6 )

m1 = 35.68721 kg/s
m2 = 36.00473 kg/s
m3 = 40.71466 kg/s
m4 = 28.57779 kg/s
m5 = 0.097780293kg/s

SOLVING FOR THE INDIVIDUAL WORK OF TURBINES

79
Heat added in the Boiler,

Heat added in Reheater,

Total Heat Added,

Pump Work,

80
Net Cycle Work,

Thermal efficiency,

81
FOR DESIGN OPTION 2

STATE POINT CALCULATIONS

Actual
State Point Enthalpy (kJ/kg)
Enthalpy (kj/kg)
1 3366.37
2 3157.87 3255.865
3 3080.28 3162.80495
4 3502.65
5 3363.98 3429.1549

82
 6 3092.62 3250.791403
7 2775.75 2999.019459
8 2498.25 2733.611646
9 2098.95 2397.240974
10 137.749
11 137.7942 137.8021765
12 417.92126
13 421.6766
14 640.085
15 656.47325
16 908.498
17 943.8005
18 1154.64
19 1186.79975 1192.475
20 1292.93
21 1299.77105
22 1408.06
23 1425.49108

Mass balance for extracted steams in the turbines:

83
Solving for using energy balance in the turbine:

84
Solving for individual work of turbines:

Heat added in the Boiler,

85
Heat added in Reheater,

Total Heat Added,

Pump Work,

Net Cycle Work,

86
Thermal efficiency,

FOR DESIGN OPTION 3

87
STATEPOINT CALCULATIONS

Actual
State Point Enthalpy (kJ/kg)
Enthalpy (kj/kg)
1 3366.37
2 3157.87 3255.865
3 3080.28 3162.80495
4 3502.65
5 3280.57 3384.9476
6 3082 3224.385372
7 2825.04 3012.732325
8 2693.45 2843.512693
9 2380.07 2597.888066
10 2132.64 2351.306591

11 137.749
12 137.7942 137.8021765
13 417.504
14 417.6604725
15 535.245
16 535.611805
17 915.29
18 916.38255
19 844.557
20 846.287805

21 1008.34
22 1053.015975 1060.899971
23 1292.93
24 1299.77105
25 1408.06
26 1425.49108

88
Mass balance for extracted steams in the turbines:

89
Solving for using energy balance in the turbine:

Solving for individual work of turbines:

90
Heat added in the Boiler,

Heat added in Reheater,

91
Total Heat Added,

Pump Work,

Net Cycle Work,

Thermal efficiency,

92
FUEL CONSUMPTION AND ENVIRONMENTAL PARAMETERS

Fuel Consumption

For Design Option 1:

For both steam turbine units = 101.9571092 kg/s

Environmental Parameters

Carbon oxides emission,

Nitrogen oxides emission,

Sulfur oxides emission,

93
Ash Disposal

For Design Option 2:

For both steam turbine units = 94.17062798 kg/s

Carbon oxides emission,

Nitrogen oxides emission,

Sulfur oxides emission,

94
Ash Disposal

For Design Option 3:

For both steam turbine units = 96.0662792 kg/s

Carbon oxides emission,

Nitrogen oxides emission,

95
Sulfur oxides emission,

Ash Disposal

For SST 4000:

For both steam turbine units = 115.4995728 kg/s

Carbon oxides emission,

Nitrogen oxides emission,

96
Sulfur oxides emission,

Ash Disposal

For STF D650:

For both steam turbine units = 100.6720628 kg/s

Carbon oxides emission,

97
Nitrogen oxides emission,

Sulfur oxides emission,

Ash Disposal

COMPUTATIONS OF OTHER COMPONENTS

Coal Storage Facility

For 1 month storage of coal:

98
The coal storage facility has an area of 260mx125mx2=65000m 2.

To determine the height of the storage area:

The height of the coal storage area was approximated to 3m.

Chimney

( )

Assume exit temperature = 150 oC, Mfg = 30

99
For chimney diameter:

Maximum allowable exit velocity=7.5m/s

For chimney pressure drop:

Chimney height =220m

( )

Air density at 27 oC, 61% humidity, 101.4kPa

ρo=1.171kg/m3

Cooling Water Requirement

@ Balayan Bay; water temp T1=30 oC

100
@ Statepoint 9, h=2397.241 kJ/kg; @ Statepoint 10. h=137.802kJ/kg

Pump flowrate =50m3/s(utilized); 50.47222 m3/s(max)

Density of water at 30 oC = 995.67kg/m3

( ) ( )

DENR permits a temperature increase of 3 oC for waste water disposal,

therefore waste water should be cooled by 0. 444917 oC before exit.

101
ENGINEERING ECONOMIC ANALYSIS

Using Siemens SST 5000 catalogue

Design Option 2
Power Demand Analysis

installed capacity [MW] 600

capacity factor 0.40
Energy GWh/year 2102.400
cost/kW [Php/kW] 9.7599
capital cost [Php] 317,380,808,316.37
Life Years 25
discount rate 0.05
Capital recovery factor 0.070952457
Annual capacity cost PHP 31,738,080,831.64
Fixed O&M PHP 164,173,062,400.00
total fixed cost Php 317,380,808,316.37
Fixed cost/kWh [Php /kWh] 146,732,581.52
Variable cost/kWh [Php /kWh] 5,139,246.785
LCOE [Php /kWh] 21.9836457
Depreciation
Service
Life Depreciation
Book Value(Php) Salvage Value (yrs) (BV-SV)/SL
Purchased 4,961,062,839.0
Equipment 193,911,717,260.00 69,885,146,260.00 25 0
Instrumentatio
n and Control 38,782,343,452.00 13,977,029,252.00 25 992,212,567.00
Service
Facilities 19,391,171,726.00 6,988,514,626.00 25 496,106,283.00
Etc 29,086,757,589.00 10,482,771,939.00 25 744,159,425.00
7,193,541,117.0
Total 0

Return of Investment
Net Income After
Period TCI ROI
Year Tax
(Php) (Php) (%)
2019 2 316,888,599,133.8 45,118,262,840.00 14.2378939
2020 3 271,770,336,293.8 45,118,262,840.00 16.6016142
2021 4 226,652,073,453.8 45,118,262,840.00 19.9063975
2022 5 181,533,810,613.8 45,118,262,840.00 24.8539171
2023 6 136,415,547,773.8 45,118,262,840.00 33.0741352
2024 7 91,297,284,933.8 45,118,262,840.00 49.4190630
2025 8 46,179,022,093.8 45,118,262,840.00 97.7029412

102
 Average 36.5422803

Payback Period
Net Income TCI Depreciation
Year
after Tax (Php) (Php) (Php)
2019 45,118,262,840.00 316,888,599,133.8 7,193,541,117.95
2020 45,118,262,840.00 271,770,336,293.8 7,193,541,117.95
2021 45,118,262,840.00 226,652,073,453.8 7,193,541,117.95
2022 45,118,262,840.00 181,533,810,613.8 7,193,541,117.95
2023 45,118,262,840.00 91,297,284,933.8 7,193,541,117.95
2024 45,118,262,840.00 46,179,022,093.8 7,193,541,117.95
Payback
Period 5 years

Sensitivity Analysis
Change ENPV EIRR

Base Case PHP %

Construction delay 1 year 97,456,823.15 11.674333

Reduce of Power Generation by 10% 55,220,734,218 0.7643

10%

Increase of Fuel Price by 10% 10% 83,892,331,143 8.2321

Drop of Fuel Price by 10% 10% 93,342,756,912 9.1181

Economical Parameters
A. Land Cost
Land Cost = Total Land Area x current land cost
Land Cost = 325,000 m2 (Php2500/m2)
Land Cost = PHP 812,500,000.00

B. Equipment Cost

Total PHP 193,911,717,260.00

C. Electrical Cost
Electrical Cost = Equipment Cost x 25%

103
 For Design Option 1
Electrical Cost = PHP 193,911,717,260.00 x 0.25
Electrical Cost = PHP 38,782,343,452.00
D. Building Cost
For Design Option 1
Building Cost = Equipment Cost x 33%
Building Cost = PHP 193,911,717,260.00 x 0.33
Building Cost = PHP 63,990,866,695.8

E. Miscellaneous Cost
Miscellaneous Cost = Equipment Cost x 10%
Miscellaneous Cost = PHP 193,911,717,260.00 x 0.1
Miscellaneous Cost = PHP 19,391,171,726.00

F. Total Capital Expenditures Cost

otal Capital Expenditures Cost ∑ cost of sub-parameters

For Design Option 1

Total = PHP 316,888,599,133.8
Operating Expenditure
A. Fuel Cost
HHV = 18311.95989 kJ/kg
Fuel Flow = 169507.1304 kg/hr
Electrical Power = 300,000 kW

Heat Rate =

Heat Rate =

Heat Rate = 10346.692588 kJ/kW-hr

Lignite coal price = $ 18.51/short ton (2000 lbs) = PHP 2.755267423/kg
Capacity = Electrical Power x 24 hr
Capacity = 300,000 kW x 24 hr
Capacity = 7,200,000 kW-hr

104
 Fuel Cost = 7,200,000 kW-hr x

(2 units)
Fuel Cost = PHP 22,417,798.77

B. Labor Cost
Labor Cost = Fuel Cost x 20%
Labor Cost = PHP 22,417,798.77 x 20%
Labor Cost = PHP 4,483,559.754

C. Maintenance and Repair

Maintenance and Repair = Fuel Cost x 20%
Maintenance and Repair = PHP 22,417,798.77 x 20%
Maintenance and Repair = PHP 4,483,559.754

D. Supplies Cost
Supply Cost = Fuel Cost x 10%
Supply Cost = PHP 22,417,798.77 x 10%
Supply Cost = PHP 2,241,779.87

E. Supervision Cost
Supervision Cost = Fuel Cost x 20%
Supervision Cost = PHP 22,417,798.77 x 20%
Supervision Cost = PHP 4,483,559.754

F. Operating Taxes
Operating Taxes = Fuel Cost x 10%
Operating Taxes = PHP 22,417,798.77 x 10%
Operating Taxes = PHP 2,241,779.87

G. Total Operating Expenditure

Total = PHP 40,352,037.786

H. Depreciation

105
 year
Depreciation ate x 00
n
year
Depreciation ate x 00
years
Depreciation Rate = 4%

Solving for the Salvage Value of the Plant

Salvage Value = Capital Expenditures x (1 - Depreciation Rate) n
Where n = Salvage Life of the Plant

Solving for the Plant Salvage Value

Salvage Value = Capital Expenditures x (1 - Depreciation Rate) n
Salvage Value = PHP 316,888,599,133.8 x (1 - 4%)25
Salvage Value = PHP 114,205,610,737.558

Annual Plant Depreciation =

n = maximum useful life of the plant

–
Annual Plant Depreciation =

Annual Plant Depreciation = PHP 8,107,319,535.84/year

I. Revenue
Annual revenue = Power Generation Rate x Actual Plant Output
Annual Revenue = PHP 9.7599/kW-hr x (600,000 kW x 0.915)
(8760hrs/yr)
Annual Revenue = PHP 46,937,701,480.00

J. Net Present Value

Net Present Value = Future Cash Flow – Total Capital Cost
Where:
Future Cash Flow = Future Revenue+ Salvage Value
Total Capital Cost = Initial Capital Cost +Operating Cost

Future Revenue = Annual Revenue x

106
 roi (Rate of Investment) = 4%
n (maximum useful life) = 25
-
- .
Future Revenue = PHP 46,937,701,480.00 x 0.

Future Revenue = PHP 572,540,296,410.542

Salvage Value = Annual Revenue x (1+roi)-n
Salvage Value = PHP 46,937,701,480.00 x (1+0.04)-25
Salvage Value = PHP 9,722,582,213.31

Future Cash Flow = PHP 572,540,296,410.542 + PHP

9,722,582,213.31
Future Cash Flow = PHP 582,262,878,623.857

Operating Cost = Operating Expenditures x

Operating Cost = PHP 40,352,037.79

Operating Cost = PHP 492,209,182.56

Solving for the Total Capital Cost

Total Capital Cost = PHP 316,888,599,133.8+ PHP 492,209,182.56

Total Capital Cost = PHP 317,380,808,316.367

Net Present Value = PHP 582,262,878,623.857- PHP

317,380,808,316.367
Net Present Value = PHP 264,882,070,307.489

K. Payback Period

Payback Period =

For Design Option 1

Payback Period =

Payback Period = 5. 16933113737663 Years

L. Return of Investment (ROI)

107
 ROI =

0, ,0 . 6

Return of Investment = 12.2409042%

Using SIEMENS SST 4000 catalogue

Design Option 2
Power Demand Analysis

installed capacity [MW] 600

capacity factor 0.40
Energy GWh/year 2102.400
cost/kW [Php/kW] 9.7599
capital cost [Php] 323,352,682,813.56
Life Years 25
discount rate 0.05
Capital recovery factor 0.070952457
Annual capacity cost PHP 32,335,268,281.35
Fixed O&M PHP 176,214,143,300.00
total fixed cost Php 323,352,682,813.56
Fixed cost/kWh [Php /kWh] 138,651,234.52
Variable cost/kWh [Php /kWh] 5,923,653.164

Depreciation
Service
Life Depreciation
Book Value(Php) Salvage Value (yrs) (BV-SV)/SL
Purchased
Equipment 197,507,050,260.00 69,885,146,260.80 25 5,053,046,311.59
Instrumentation
and Control 39,501,410,052.00 13,977,029,252.16 25 1,010,609,262.31
Service
Facilities 19,750,705,026.00 6,988,514,626.08 25 505,304,631.15
Etc 29,626,057,539.00 10,482,771,939.12 25 757,956,946.73
Total 7,326,917,151.81

Return of Investment
Net Income After
Period TCI ROI
Year Tax
(Php) (Php) (%)

108
 2019 2 322,748,991,923.8 45,118,262,840.00 13.97936
2020 3 277,630,729,083.8 45,118,262,840.00 16.25117

2021 4 232,512,466,243.8 45,118,262,840.00 19.40466

2022 5 187,394,203,403.8 45,118,262,840.00 24.07665
2023 6 142,275,940,563.8 45,118,262,840.00 31.71180
2024 7 97,157,677,723.8 45,118,262,840.00 46.43818
2025 8 52,039,414,883.8 45,118,262,840.00 86.70017
Average 34.08028

Payback Period
Net Income TCI Depreciation
after Tax (Php) (Php) (Php)
2019 4,511,826,840.00 322,748,991,923.8 7,326,917,151.81
2020 4,511,826,840.00 277,630,729,083.8 7,326,917,151.81
2021 4,511,826,840.00 232,512,466,243.8 7,326,917,151.81
2022 4,511,826,840.00 1873,94,203,403.8 7,326,917,151.81
2023 4,511,826,840.00 142,275,940,563.8 7,326,917,151.81
2024 4,511,826,840.00 97,157,677,723.8 7,326,917,151.81
2025 4,511,826,840.00 52,039414,,883.8 7,326,917,151.81
Payback
Period 6 years

Sensitivity Analysis

Change ENPV EIRR

Base Case PHP %

Construction delay 1 year 93,543,765.21 10.312423

Reduce of Power Generation by 10% 43,110,238,275 0.69141

10%

Increase of Fuel Price by 10% 10% 76,546,123,976 7.8364

Drop of Fuel Price by 10% 10% 84,742,528,369 8.9262

Economical Parameters
A. Land Cost
Land Cost = Total Land Area x current land cost
Land Cost = 325,000 m2 (Php2500/m2)
Land Cost = PHP 812,500,000.00

109
 B. Equipment Cost

Total PHP 197,507,050,260.00

C. Electrical Cost
Electrical Cost = Equipment Cost x 25%

For Design Option 1

Electrical Cost = PHP 197,507,050,260.00x 0.20
Electrical Cost = PHP 39,501,410,052.00

D. Building Cost
For Design Option 1
Building Cost = Equipment Cost x 33%
Building Cost = PHP 197,507,050,260.00x 0.33
Building Cost = PHP 65,177,326,585.8

E. Miscellaneous Cost
Miscellaneous Cost = Equipment Cost x 10%
Miscellaneous Cost = PHP 197,507,050,260.00x 0.1
Miscellaneous Cost = PHP 19,750,705,026.00

F. Total Capital Expenditures Cost

otal Capital Expenditures Cost ∑ cost of sub-parameters

Total = PHP 322,748,991,923.8

Operating Expenditure
A. Fuel Cost
HHV = 18311.95989 kJ/kg
Fuel Flow = 207899.2302kg/hr
Electrical Power = 300,000 kW

Heat Rate =

110
 Heat Rate =

Heat Rate = 12,690.14124 kJ/kW-hr

Lignite coal price = $ 18.51/short ton (2000 lbs) = PHP 2.755267423/kg
Capacity = Electrical Power x 24 hr
Capacity = 300,000 kW x 24 hr
Capacity = 7,200,000 kW-hr

Fuel Cost = 7,200,000 kW-hr x

(2 units)
Fuel Cost = PHP 27,495,262.92

B. Labor Cost
Labor Cost = Fuel Cost x 20%
Labor Cost = PHP 27,495,262.92x 20%
Labor Cost = PHP 5,499,052.584

C. Maintenance and Repair

Maintenance and Repair = Fuel Cost x 20%
Maintenance and Repair = PHP 27,495,262.92 x 20%
Maintenance and Repair = PHP 5,499,052.584

D. Supplies Cost
Supply Cost = Fuel Cost x 10%
Supply Cost = PHP 27,495,262.92x 10%
Supply Cost = PHP 2,749,526.292

E. Supervision Cost
Supervision Cost = Fuel Cost x 20%
Supervision Cost = PHP 27,495,262.92x 20%
Supervision Cost = PHP 5,499,052.584

F. Operating Taxes
Operating Taxes = Fuel Cost x 10%
111
 Operating Taxes = PHP 27,495,262.92x 10%
Operating Taxes = PHP 2,749,526.292

G. Total Operating Expenditure

Total = PHP 49,491,473.256

H. Depreciation
year
Depreciation ate x 00
n
year
Depreciation ate x 00
years
Depreciation Rate = 4%

Solving for the Salvage Value of the Plant

Salvage Value = Capital Expenditures x (1 - Depreciation Rate) n
Where n = Salvage Life of the Plant

Solving for the Plant Salvage Value

Salvage Value = Capital Expenditures x (1 - Depreciation Rate) n
Salvage Value = PHP 322,748,991,923.8x (1 - 4%)25
Salvage Value = PHP 116,317,677,058.573

Annual Plant Depreciation =

n = maximum useful life of the plant

–
Annual Plant Depreciation =

Annual Plant Depreciation = PHP 8,257,252,594.6091/year

I. Revenue
Annual revenue = Power Generation Rate x Actual Plant Output
Annual Revenue = PHP 9.7599/kW-hr x (600,000 kW x 0.915)
(8760hrs/yr)
Annual Revenue = PHP 46,937,701,480.00

J. Net Present Value

112
 Net Present Value = Future Cash Flow – Total Capital Cost
Where:
Future Cash Flow = Future Revenue+ Salvage Value
Total Capital Cost = Initial Capital Cost +Operating Cost

Future Revenue = Annual Revenue x

roi (Rate of Investment) = 4%

n (maximum useful life) = 25
-
- .
Future Revenue = PHP 46,937,701,480.00 x 0.

Future Revenue = PHP 572,540,296,410.542

Salvage Value = Annual Revenue x (1+roi)-n
Salvage Value = PHP 46,937,701,480.00 x (1+0.04)-25
Salvage Value = PHP 9,722,582,213.31

Future Cash Flow = PHP 572,540,296,410.542 + PHP

9,722,582,213.31
Future Cash Flow = PHP 582,262,878,623.857

Operating Cost = Operating Expenditures x

Operating Cost = PHP 49,491,473.256

Operating Cost = PHP 603,690,889.76691

Solving for the Total Capital Cost

Total Capital Cost = PHP 322,748,991,923.8+ PHP 603,690,889.76

Total Capital Cost = PHP 323,352,682,813.567

Net Present Value = PHP 582,262,878,623.857- PHP

323,352,682,813.567
Net Present Value = PHP 258,910,195,810.29

K. Payback Period

113
 Payback Period =

For Design Option 1

Payback Period =

Payback Period = 6. 35467235462433 Years

L. Return of Investment (ROI)

ROI =

, , . 6

Return of Investment = 11.9693502%

Using GE STF D650 Catalogue

Design Option 2
Power Demand Analysis

installed capacity [MW] 600

capacity factor 0.40
Energy GWh/year 2102.400
cost/kW [Php/kW] 9.7599
capital cost [Php] 327,544,792,888.92
Life Years 25
discount rate 0.05
Capital recovery factor 0.070952457
Annual capacity cost PHP 32,754,479,288.89
Fixed O&M PHP 187,093,264,348.00
total fixed cost Php 327,544,792,888.92
Fixed cost/kWh [Php /kWh] 133,631,234.52
Variable cost/kWh [Php /kWh] 6,375,836.785
LCOE [Php /kWh] 26.342765

Depreciation
Service
Book Life Depreciation
Value(Php) Salvage Value (yrs) (BV-SV)/SL
Purchased
Equipment 200,126,507,160.00 72,124,936,136.72 25 5,120,062,840.93
Instrumentation 40,025,301,432.00 14424987227.34 25 1,024,012,568.18

114
and Control
Service
Facilities 20,012,650,716.00 7,212,493,613.67 25 512,006,284.09
Etc 30,018,976,074.00 10,818,740,420.50 25 768,009,426.13
Total 7,424,091,119.34

Return of Investment
Net Income After
Period TCI ROI
Tax

Year
(Php) (Php) (%)

2019 2 327018706670.8 45,118,262,840.00 13.79684

2020 3 281900443830.8 45,118,262,840.00 16.00503
2021 4 236782180990.8 45,118,262,840.00 19.05475
2022 5 191663918150.8 45,118,262,840.00 23.54030
2023 6 146545655310.8 45,118,262,840.00 30.78785
2024 7 101427392470.8 45,118,262,840.00 44.48331
2025 8 56309129630.8 45,118,262,840.00 80.12601
Average 32.54201
Payback Period
Net Income TCI Depreciation
Year
after Tax (Php) (Php) (Php)
2019 4,511,826,840.00 327018706670.8 7,326,917,151.81
2020 4,511,826,840.00 281900443830.8 7,326,917,151.81
2021 4,511,826,840.00 236782180990.8 7,326,917,151.81
2022 4,511,826,840.00 191663918150.8 7,326,917,151.81
2023 4,511,826,840.00 146545655310.8 7,326,917,151.81
2024 4,511,826,840.00 101427392470.8 7,326,917,151.81
2025 4,511,826,840.00 56309129630.8 7,326,917,151.81
Payback
Period 6 years

Sensitivity Analysis

Change ENPV EIRR

Base Case PHP %

Construction delay 1 year 89,001,730.15 10.674333

Reduce of Power Generation by 10% 50,091,723,000 0.7198

10%

115
Increase of Fuel Price by 10% 10% 81,063,172.00 7.7361

Drop of Fuel Price by 10% 10% 90,149,001,.98 8.6972

Summary Economic Analysis of the Three Catalogues (Design Option 2)

Parameters SIEMENS SST SIEMENS SST GE

5000 4000
STF D650

Cost (Php) Php Php Php

193,911,717,260.0 197,507,050,260.00 200,126,507,160.00

Payback 5 years 6 years 6 years

Period

Economical Parameters
A. Land Cost
Land Cost = Total Land Area x current land cost
Land Cost = 325,000 m2 (Php2500/m2)
Land Cost = PHP 812,500,000.00

B. Equipment Cost

Total PHP 200,126,507,160.00

C. Electrical Cost
Electrical Cost = Equipment Cost x 20%
Electrical Cost = PHP 200,126,507,160.00x 0.2
Electrical Cost = PHP 40,025,301,432.00
D. Building Cost
For Design Option 1
Building Cost = Equipment Cost x 33%
Building Cost = PHP 200,126,507,160.00x 0.33
Building Cost = PHP 66,041,747,362.8

116
E. Miscellaneous Cost
Miscellaneous Cost = Equipment Cost x 10%
Miscellaneous Cost = PHP 200,126,507,160.00x 0.1
Miscellaneous Cost = PHP 20,012,650,716.00

F. Total Capital Expenditures Cost

otal Capital Expenditures Cost ∑ cost of sub-parameters

For Design Option 1

Total = PHP 327,018,706,670.8
Operating Expenditure
A. Fuel Cost
HHV = 18311.95989 kJ/kg
Fuel Flow = 181173.713 kg/hr
Electrical Power = 300,000 kW

Heat Rate =

Heat Rate =

Heat Rate = 11058.91922 kJ/kW-hr

Lignite coal price = $ 18.51/short ton (2000 lbs) = PHP 2.755267423/kg
Capacity = Electrical Power x 24 hr
Capacity = 300,000 kW x 24 hr
Capacity = 7,200,000 kW-hr

Fuel Cost = 7,200,000 kW-hr x (2

units)
Fuel Cost = PHP 23,960,737.41

B. Labor Cost
Labor Cost = Fuel Cost x 20%
Labor Cost = PHP 23,960,737.41x 20%
Labor Cost = PHP 4,792,147.482

117
C. Maintenance and Repair
Maintenance and Repair = Fuel Cost x 20%
Maintenance and Repair = PHP 23,960,737.41x 20%
Maintenance and Repair = PHP 4,792,147.482

D. Supplies Cost
Supply Cost = Fuel Cost x 10%
Supply Cost = PHP 23,960,737.41x 10%
Supply Cost = PHP 2,396,073.741

E. Supervision Cost
Supervision Cost = Fuel Cost x 20%
Supervision Cost = PHP 23,960,737.41x 20%
Supervision Cost = PHP 4,792,147.482

F. Operating Taxes
Operating Taxes = Fuel Cost x 10%
Operating Taxes = PHP 23,960,737.41x 10%
Operating Taxes = PHP 2,396,073.741

G. Total Operating Expenditure

Total = PHP 43,129,327.338

H. Depreciation
year
Depreciation ate x 00
n
year
Depreciation ate x 00
years
Depreciation Rate = 4%

Solving for the Salvage Value of the Plant

Salvage Value = Capital Expenditures x (1 - Depreciation Rate) n
Where n = Salvage Life of the Plant

Solving for the Plant Salvage Value

118
 Salvage Value = Capital Expenditures x (1 - Depreciation Rate) n
Salvage Value = PHP 327,018,706,670.8x (1 - 4%)25
Salvage Value = PHP 117,856,468,235.312

Annual Plant Depreciation =

n = maximum useful life of the plant

–
Annual Plant Depreciation =

Annual Plant Depreciation = PHP 8,366,489,537.41953/year

I. Revenue
Annual revenue = Power Generation Rate x Actual Plant Output
Annual Revenue = PHP 9.7599/kW-hr x (600,000 kW x 0.915)
(8760hrs/yr)
Annual Revenue = PHP 46,937,701,480.00

J. Net Present Value

Net Present Value = Future Cash Flow – Total Capital Cost
Where:
Future Cash Flow = Future Revenue+ Salvage Value
Total Capital Cost = Initial Capital Cost +Operating Cost

Future Revenue = Annual Revenue x

roi (Rate of Investment) = 4%

n (maximum useful life) = 25
-
- .
Future Revenue = PHP 46,937,701,480.00 x 0.

Future Revenue = PHP 572,540,296,410.542

Salvage Value = Annual Revenue x (1+roi)-n
Salvage Value = PHP 46,937,701,480.00 x (1+0.04)-25
Salvage Value = PHP 9,722,582,213.31

Future Cash Flow = PHP 572,540,296,410.542 + PHP

9,722,582,213.31

119
 Future Cash Flow = PHP 582,262,878,623.857

Operating Cost = Operating Expenditures x

Operating Cost = PHP

Operating Cost = PHP 526,086,218.127929

Solving for the Total Capital Cost

Total Capital Cost = PHP 327,018,706,670.8+ PHP 526,086,218.12

Total Capital Cost = PHP 327,544,792,888.928

Net Present Value = PHP 582,262,878,623.857- PHP

327,544,792,888.928
Net Present Value = PHP 254,718,085,734.929

K. Payback Period

Payback Period =

For Design Option 1

Payback Period =

Payback Period = 6. 16933113737663 Years

L. Return of Investment (ROI)

ROI =

, , .

Return of Investment = 11.78161427%

120
APPENDIX B
CATALOGUE

121
CATALOGUE FOR STEAM TURBINE

122
CATALOGUE FOR BOILER

CATALOGUE FOR CONDENSER

123
CATALOGUE FOR PUMPS

124
CATALOGUE FOR DAERATOR

125
CATALOGUE FOR CLOSED FEEDWATER HEATER

CATALOGUE FOR GENERATOR

126
CATALOGUE FOR PULVERIZER

127
PIPE SELECTION

128
 APPENDIX C
PROJECT DOCUMENTATION

129
DOCUMENTATION

Before the selection of the final design, different design options were
made. See photos below:

130
 Here are photos of the proponents analyzing and evaluating the
calculations obtained:

131
132
ORAL DEFENSE

133