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University of the Philippines Solar LaboratoryKabang Kalikasan ng Pilipinas (WWF Philippines)

U.P. Electrical and Electronics Engineering Foundation

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Prepared by: Prof. Rowaldo R. del Mundo Charito M. Isidro Remife L.Villarino-de Guzman Fidelpio V. Ferraris

With inputs from: Rafael Señga Ina Pozon Liam Salter

2003, Kabang Kalikasan ng Pilipinas (WWF Philippines) / University of the

Philippines Solar Laboratory This report was produced by the University of the Philippines Solar Laboratory for the Kabang Kalikasan ng Pilipinas. No part of this publication may be reproduced in any form or means without the prior written permission of the Kabang Kalikasan ng Pilipinas and the University of the Philippines Solar Laboratory.

University of the Philippines Solar Laboratory (UPSL) German Yia Hall, University of the Philippines Diliman, Quezon City Tel. No. (632) 924-4150 Fax No. (632) 434-3660 Email: [email protected] Web: http://www.upd.edu.ph/~solar

Kabang Kalikasan ng Pilipinas WWF Philippines LBI Building # 57 Kalayaan Avenue, Quezon City Tel. No. (632) 433-3220 to 22

POWER SWITCH: Scenarios and Strategies for Clean Power Development in the Philippines

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TABLE OF CONTENTS

LIST OF FIGURES...........................................................................................................iii

LIST OF TABLES.............................................................................................................vi

LIST OF APPENDICES.................................................................................................viii

LIST OF ABBREVIATIONS ............................................................................................ix

EXECUTIVE SUMMARY .................................................................................................x

1 EXECUTIVE SUMMARY.................................................................................... 1

1.1 Introduction................................................................................................ 1

1.2 Technology and Resource Assessment

for Clean Power Development ............................................................... 1

1.3 Historical Performance of the Philippine Power Sector ..................... 4

1.4 Scenarios under the Philippine Energy Plan 2003-2012 ................... 7

1.5 Clean Power Development for the Philippines .................................... 8

1.6 Conclusions and Recommendations ...................................................10

2 ENERGY TECHNOLOGIES AND RESOURCES FOR

CLEAN POWER.................................................................................................13

2.1 Clean Energy Technologies .................................................................14

2.2 Resource Assessment...........................................................................20

2.3 Cost Comparison of Power Generation Technologies .....................32

2.4 Environmental Externalities ..................................................................35

2.5 Mitigation Options ...................................................................................37

3 HISTORICAL PERFORMANCE OF THE

PHILIPPINE POWER SECTOR ......................................................................38

3.1 Historical Energy Demand and

Installed Generating Capacity ..............................................................38

3.2 Historical Reliability Performance........................................................41

3.3 Historical Environmental Performance ...............................................42

3.4 Cost of Electricity....................................................................................46


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4 SCENARIOS UNDER THE PHILIPPINE ENERGY PLAN

FOR 2003-2012.................................................................................................3.1

4.1 National Energy Planning Process ......................................................48

4.2 Gross Domestic Product Projections ..................................................49

4.3 DOE Plan for the Low Economic Growth Scenario ..........................50

4.4 DOE Plan for the High Economic Growth Scenario .........................57

5 CLEAN POWER DEVELOPMENT OPTIONS..............................................63

5.1 LEGS-MCPD Scenario..........................................................................64

5.2 LEGS-ACPD Scenario...........................................................................68

5.3 HEGS-MCPD Scenario .........................................................................71

5.4 HEGS-ACPD Scenario..........................................................................75

6 CONCLUSIONS AND RECOMMENDATIONS............................................81

6.1 Energy Planning .....................................................................................81

6.2 Transmission and Distribution Development .....................................82

6.3 Rules and Regulation ............................................................................82

6.4 Incentive Programs ................................................................................83

7 REFERENCES ...................................................................................................84


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LIST OF FIGURES

Figure 2.1 Practical Wind Resources in the Philippines .....................................23

Figure 2.2 Practical Small Hydro Resources in the Philippines.........................27

Figure 3.1 Electricity Consumption by Sector, 2001............................................39

Figure 3.2 Electricity Consumption, Gross Domestic Product and Population, 1991-2001 ..........................................................................39

Figure 3.3 Electricity Generation by Grid, 1991-2001 .........................................40

Figure 3.4 System Peak by Grid, 1991-2001........................................................40

Figure 3.5 Total Installed Generating Capacity by Source, 1999-2001..........................................................................................................41

Figure 3.6 Carbon Dioxide Emissions by Fuel Type, 1999-2001 ......................43

Figure 3.7 Energy Mix, 1999-2001 .........................................................................44

Figure 3.8 Share of Renewable and Non-Renewable Energy in the Energy Mix, 1999-2001...................................................................45

Figure 3.9 Energy Mix and Carbon Dioxide Emissions, 1991-2001..........................................................................................................45

Figure 4.1 National Energy Planning Process ......................................................49

Figure 4.2 Generation under the Low Economic Growth Scenario...................50

Figure 4.3 DOE Plan for Installed Capacity for the Low Economic Growth Scenario.....................................................................................51

Figure 4.4 Energy Mix for the DOE Plan for the Low Economic Growth Scenario.....................................................................................53

Figure 4.5 Coal and Oil-Based vs. Renewable and Natural Gas Energy Mix for the DOE Plan for the Low Economic Growth Scenario.....................................................................................53

Figure 4.6 Fossil Fuel Consumption for the DOE Plan for the Low Economic Growth Scenario..........................................................55

Figure 4.7 Carbon Dioxide Emissions for the DOE Plan for the Low Economic Growth Scenario..........................................................56

Figure 4.8 Generation under the High Economic Growth Scenario...................................................................................................57

Figure 4.9 DOE Plan for Installed Capacity for the High Economic Growth Scenario ..................................................................58

Figure 4.10 Energy Mix for the DOE Plan for the High Economic Growth Scenario.....................................................................................59


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Figure 4.11 Share of Renewable and Non-Renewable Energy in the Energy Mix for the DOE Plan for the High Economic Growth Scenario ..................................................................60

Figure 4.12 Fossil Fuel Consumption for the DOE Plan for the High Economic Growth Scenario.........................................................60

Figure 4.13 Carbon Dioxide Emissions for the DOE Plan for the High Economic Growth Scenario.........................................................62

Figure 5.1 Installed Generating Capacity for the LEGS-MCPD Scenario...................................................................................................65

Figure 5.2 Energy Mix for the LEGS-MCPD Scenario ........................................66

Figure 5.3 Coal and Oil-Based vs. Renewable and Natural Gas Energy Mix for the LEGS-MCPD Scenario ........................................66

Figure 5.4 Fossil Fuel Consumption for the LEGS-MCPD Scenario...................................................................................................67

Figure 5.5 CO2 Emissions for the LEGS-MCPD Scenario..................................67

Figure 5.6 Installed Generating Capacity for the LEGS-ACPD Scenario...................................................................................................69

Figure 5.7 Energy Mix for the LEGS-ACPD Scenario .........................................69

Figure 5.8 Coal and Oil-Based vs. Renewable and Natural Gas Energy Mix for the LEGS-ACPD Scenario .........................................70

Figure 5.9 Fossil Fuel Consumption for the LEGS-ACPD Scenario...................................................................................................70

Figure 5.10 CO2 Emissions for the LEGS-ACPD Scenario ..................................71

Figure 5.11 Installed Generating Capacity for the HEGS-MWPP Scenario...................................................................................................73

Figure 5.12 Energy Mix for the HEGS-MCPD Scenario........................................73

Figure 5.13 Coal and Oil-Based vs. Renewable and Natural Gas Energy Mix for the HEGS-MCPD Scenario........................................74

Figure 5.14 Fossil Fuel Consumption for the HEGS-MCPD Scenario...................................................................................................74

Figure 5.15 CO2 Emissions for the HEGS-MCPD Scenario.................................75

Figure 5.16 Installed Generating Capacity for the HEGS-ACPD Scenario...................................................................................................77

Figure 5.17 Energy Mix for the HEGS-ACPD Scenario ........................................77

Figure 5.18 Coal and Oil-Based vs. Renewable and Natural Gas Energy Mix for the HEGS-ACPD Scenario ........................................78

Figure 5.19 Fuel Consumption for the HEGS-ACPD Scenario............................78

Figure 5.20 CO2 Emissions for the HEGS-ACPD Scenario..................................79


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LIST OF TABLES

Table 1.1 Cost Comparison of Power Plants......................................................... 2

Table 1.2 Typical Capacity Factors of Power Plants

and Levelized Generation Costs............................................................ 2

Table 2.1 1994 Philippine Greenhouse Gas Emissions by Sector ..................13

Table 2.2 1994 Greenhouse Gas Emissions from the

Philippine Energy Sector .......................................................................13

Table 2.3 Philippine Wind Electric Potential ........................................................22

Table 2.4 Practical Wind Resources in the Philippines .....................................22

Table 2.5 Available Large Hydro Resources .......................................................25

Table 2.6 Philippine Small Hydro Electric Potential ...........................................26

Table 2.7 Practical Small Hydro Resources in the Philippines.........................26

Table 2.8 Small Hydro Power Sites Verified by the DOE ..................................26

Table 2.9 Projected Supply of Biomass Resources ...........................................28

Table 2.10 Philippine Bagasse Electric Potential..................................................30

Table 2.11 Available Geothermal Resources for Power Generation.................31

Table 2.12 Philippine Natural Gas Resources.......................................................32

Table 2.13 Cost Comparison of Power Plants.......................................................33

Table 2.14 Typical Capacity Factors of Power Plants

and Levelized Generation Costs..........................................................34

Table 2.15 Value of Air Emissions Reductions in California ...............................36

Table 2.16 Carbon Dioxide Emissions of Different Power Plant Types ............36

Table 2.17 Emission Factors for Various Power Plants .......................................36

Table 3.1 Energy Consumption by Sector, 1991-2001 ......................................38

Table 3.2 Reserve Margin, 1991-2001 .................................................................42

Table 3.3 Historical Environmental Emissions for

the Philippine Power Sector .................................................................42

Table 3.4 NPC Average Electricity Rates, 1991-2001 .......................................46

Table 3.5 NPC and IPP Production Cost at 1990 Constant Prices........................................................................................................47


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Table 4.1 Low and High GDP Forecasts for 2003 to 2012 ...............................49

Table 4.2 Percentage Reserve Margin for the DOE Plan for the Low Economic Growth Scenario..........................................................52

Table 4.3 Environmental Emissions for the DOE Plan for the Low Economic Growth Scenario..........................................................55

Table 4.4 Generation Costs for the DOE Plan for the Low Economic Growth Scenario, 2003-2012.............................................56

Table 4.5 Percentage Reserve Margin for the DOE Plan for the High Economic Growth Scenario.........................................................58

Table 4.6 Environmental Emissions for the DOE Plan for the High Economic Growth Scenario.........................................................61

Table 4.7 Generation Costs for the DOE Plan for the High Economic Growth Scenario ..................................................................62


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LIST OF APPENDICES

Appendix A Wind and Hydro Potential in the Philippines

Appendix B Historical Performance of the Philippine Power Sector

1991-2001

Appendix C Economic Scenarios and DOE Plans for the Power Sector 2003-

2012

Appendix D Clean Power Development Options


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LIST OF ABBREVIATIONS

AWPP Aggressive Wind Power Penetration

BCF billion cubic feet

Btu British thermal unit

CC combined cycle power plant

CENECO Central Negros Electric Cooperative

CER Certificate of Emissions Reduction

CH4 methane

CO carbon monoxide

CO2 carbon dioxide

FFHC First Farmers Holdings Corporation

GHG greenhouse gas

GWh gigawatthour

HAEGS Historical Average Economic Growth Scenario

HEGS High Economic Growth Scenario

IPPs Independent Power Producers

ktonne kilotonne

kW kilowatt

LEGS Low Economic Growth Scenario

LOLP loss of load probability

MERALCO Manila Electric Company

MMBFOE million barrels of fuel oil equivalent

MWPP Moderate Wind Power Penetration

NMVOC non-methane volatile organic compound

NOx nitrogen oxides

NPC National Power Corporation

NREL National Renewable Energy Laboratory

N2O nitrous oxide

PPA purchased power adjustment


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SO2 sulfur dioxide

UNDP United Nations Development Programme

UPSL University of the Philippines Solar Laboratory

VMC Victorias Milling Company

POWER SWITCH! Scenarios and Strategies for Clean Power Development in the Philippines

University of the Philippines Solar Laboratory page 1 Kabang Kalikasan ng Pilipinas, Inc. UPEEE Foundation

1 EXECUTIVE SUMMARY 1.1 Introduction An area that has great potential for greenhouse gas (GHG) reduction is the power sector. In 1994, the energy sector accounted for 50.038 million tonnes of the 100.738 million tonnes, or roughly 47 percent, of total net GHG emissions in the country. Of the energy sector GHG emissions, the energy industries, mainly the power industry, accounts for more than thirty (30) percent as a result of the burning of fossil fuels. Although it ranks only second to the transport sub-sector in terms of GHG emissions, the power sub-sector represents a large opportunity for carbon emissions reduction and sequestration, given that clean energy technologies and resources are available. This study focuses on reliability, cost and environmental performance (particularly GHG emissions) of the power sector. In particular it looks into scenarios that would entail switching to clean energy technologies from conventional fossil fuel-based technologies for grid-connected power generation. 1.2 Technology and Resource Assessment for Clean Power Development This study has assessed the technologies and resources that could be used to pursue clean power development in the Philippines. Clean Energy Technologies For the clean energy technologies, the assessment focused on technology measures that reduce carbon intensity of energy (e.g., renewable energy technologies and cleaner fossil-based technologies such as natural gas). Despite the high potential of technology measures that reduce energy intensity, which could be treated as a resource in energy planning, it is not used in this study because data available in the Philippines is insufficient to do so. The following are the clean energy technologies that could be utilized for clean power development in the Philippines:

a) Wind Energy Conversion Systems;

b) Hydroelectric Power Plants;

c) Biomass Energy Conversion Systems;

d) Geothermal Power Plants; and

e) Natural Gas-Fired Power Plants. Improved coal technologies, such as the circulating fluidized bed combustion system, is considered as “relatively cleaner” only to pulverized coal plant technology. Hence, if considered in power development with the objective of pursuing environmental sustainability, these technologies will be at the bottom of the list. Other renewable energy technologies were excluded on the basis of cost competitiveness and/or maturity of technology.



Cost Comparison of Power Generation Technologies The economics of power generation technologies depends on several factors, including: (a) investment cost, (b) operation and maintenance cost, (c) fuel cost, and (d) the level of generation (also called capacity factor). Table 1.1 below shows the costs used in this study. Screening curves (costs per kWh vs. capacity factor) were developed based on the life cycle of each power generation technology and the four economic factors mentioned above.

Table 1.1: Cost Comparison of Power Plants

Type of Power Plant Typical

Economic Life, years

Investment Cost, $/kWa

Annual Fixed O & M Cost, $/kWa

Fuel Cost, $/MWh

Oil-fired steam turbine 30 850 – 1,000 17 – 20 41.04 Oil-fired gas turbine 20 450 - 550 11 – 14 49.93 Oil-fired combined cycle gas turbine 20 700 – 900 14 – 18 32.56

Diesel motors 20 550 – 650 14 – 16 73.10 Pulverized coal-fired power plant 30 1,200 – 1,400 30 – 35 11.40

Fluidized bed coal power plant 30 1,750 – 1,800 44 – 45 9.12

Wind technologies 20 1,000 – 1,250 20 – 25 0 Hydroelectric power plants 50 2,000 – 3,500 40 – 70 0 Fluidized bed combustors (for biomass) 30 1,750 – 1,800 44 – 45 3.53

Geothermal technologies 50 1,150 – 1,500 29 – 38 0 Gas-fired combined cycle gas turbine (for natural gas) 20 700 – 900 14 – 18 36.68

Table 1.2: Typical Capacity Factors of Power Plants and Levelized Generation

Costs1 Levelized Generation Cost Power Plant Type Capacity Factor

(%) $/kWh PhP/kWh Geothermal 88 0.0193 1.0602 Coal (Pulverized coal plant) 82 0.0405 2.2282 Coal (Pulverized coal plant) 82 0.0405 2.2282 Hydro 57 0.0494 2.7153 Oil-fired steam turbine 54 0.1059 5.8236 Natural gas combined cycle 54 0.0794 4.3644 Oil-fired gas turbine 31 0.1101 6.0557 Wind Without ancillary services 30 0.0512 2.8174 With ancillary services 30 0.0625 3.4376 Diesel 9 0.2277 12.5219 1 A discount rate of 12% was used to derive levelized generation costs. Actual industry discount rates may be higher depending on the following factors: required equity return, market risks, regulatory risks, country risks and availability of financing.



The above screening curve table was used in preparing the alternative power development plans in this study. The figures used are only intended for relative comparison.2 It can be noted that on life-cycle basis, renewable energy technologies can be competitive with conventional fossil fuel-based technologies. However, most power developers are biased to fossil-based power plants because of its comparative advantage in terms of investment cost and shorter recovery period. Thus, the need for policy instruments and mechanisms that will create a more secured investment climate for renewable energy developers cannot be over-emphasized. Environmental Externalities A number of studies have attempted to put a cost on the various externalities caused by power generation using the abatement cost or the damage cost approach. The abatement cost approach uses the cost of pollution control as a proxy to the true externality cost. On the other hand, the damage cost approach puts a value on the damages that may be directly attributable to a particular pollutant. Studies vary in their estimation of externality costs because of a number of factors, including site specificity (e.g., geographical and climatological conditions), population density, emissions reduction policy, scope of analysis, among others. In this study, abatement cost values for the North Coast of California, which has the lowest abatement costs among the districts of California, were used to compute for the cost of externalities of the different power development plans. These figures were used in the absence of actual abatement cost assessment for the Philippines. Moreover, abatement technologies, if required in the Philippines’ power generation sector, will be imported from developed countries such as U.S.A or Europe. It is therefore deemed reasonable to use the lowest available value in developed countries for purposes of evaluating the prospective performance of a power development plan. It can be concluded that if environmental externalities will be considered, clean renewable energy technologies will be the least cost option for power development in the Philippines Clean Indigenous Energy Resources Energy resource assessment was conducted based on secondary data to quantify the available indigenous resources that can be utilized by the clean energy technologies as “fuel”. Assessment was made for wind, hydro, biomass, geothermal and natural gas resources for power development. Resource assessment and mapping conducted in the past for the Philippine archipelago have shown that the country has a big wind power potential. The National Renewable Energy Laboratory (NREL) has estimated that there are 76,600 MW of installed wind power capacity in the Philippines that can generate about 2 True costs will vary for a number of reasons, including variability of fuel costs, dollar discount rates, among other things. Further, these costs do not include site development costs, connection to the transmission system, transformer costs and taxes. These costs were derived using only the cost of the power plant technology, operations and maintenance cost and fuel costs.



195,200 GWh of electricity per year. For the purposes of this study, a re-analysis of the NREL wind mapping data was conducted. Additional screening criteria were imposed to determine practical and viable wind power sites. This include considering only sites with power density of at least 500 W/m2. This first criterion reduced the number of wind sites to 2,092 with an aggregate potential of 14,323 MW. A second criterion that relates to grid connection costs was also used. The transmission system of the National Transmission Company (TransCo) was overlaid to the GIS-based wind resource map to determine the proximity of the sites to the grid. Only those sites whose connection (i.e., construction of transmission lines) will cost up to 25% of the total life-cycle cost were considered. The application of the second criterion further reduced the number of sites to 1,038 with 7,404 MW potential. A re-analysis of the NREL small hydro resource assessment was also conducted. Selecting only the sites with capacities of 5 MW or more as criterion, the UPSL identified 236 small hydro sites in the country with an aggregated capacity of about 2,308 MW. Using the second screening criterion similar to that use in the wind resource assessment, (i.e., limiting the transmission investment cost to 25% of total investment cost) resulted to the elimination of three sites from the small hydro resource pool. Of all the biomass resources in the country, UPSL considered only bagasse from sugarcane processing as practical resource for grid connection. Other biomass resources are still facing problems or issues like collection, storage, and competing uses to be viable for large-scale power generation. UPSL estimates the electric power potential of bagasse at 235.7 MW. This potential is spread all over the country where sugar centrals are situated. The Philippines power sector largely depends on geothermal energy to meet the demand and energy requirements of the country. In 2001, total geothermal installed capacity amounted to 1,931 MW, which generated a total of 10,442 GWh. This accounts for 14% and 22% of the total installed capacity and total generation, respectively in the country. In addition to existing geothermal power facilities, an estimated capacity of 1,200 MW that could generate about 8,935 GWh annually can be obtained from additional verified geothermal sites in the Philippines. A few natural gas finds in the Philippines have been made, the most significant of which is that found in Malampaya and San Martin in Palawan, with a combined estimated reserves of 2,771 to 4,731 billion cubic feet (BCF). The Philippine government is considering plans to develop a local natural gas industry. If this pushes through, local natural gas production would be supplemented by imported natural gas. 1.3 Historical Performance of the Philippine Power Sector The performance (in terms of reliability, cost and environmental emissions,) of the Philippine power sector from the period beginning 1991 to 2001 was also assessed in this study.



Energy Demand and Installed Capacity The Philippines electricity consumption posted a moderate growth rate of 8.3% annually from 1991 to 2001. The industrial and residential sectors, accounting for 31% and 29% energy share for the year 2001, respectively, are the biggest users of electricity. The commercial sector accounts for 21% of the total consumption for 2001. The rest are attributed to own use, losses and miscellaneous uses. It should be noted however, that the industrial sector demand grew only by 5.5% while that of the residential sector grew by 11.7% annually for the 11-year period. Geographically, the energy demand in the country was distributed among the three (3) main islands of Luzon, Visayas and Mindanao. Bulk of the energy demand and consequently the generation comes from the main island of Luzon. In 2001 for example, the Luzon Grid has a share of 36,184 GWh of the total 47,049 GWh energy generation which represents 77% of the requirements of the country. Visayas and Mindanao share the remaining balance almost equally. In order to meet the growing demand for electricity, the installed generating capacity in the country doubled in 11 years with 6,789 MW in 1991 to 13,402 MW in 2001. Historical Reliability Performance To analyze the reliability performance of the power system in the Philippines, the reserve margin (i.e., generating capacity compared to the system peak) from 1991 to 2001 was determined from historical data. The analysis has shown that the generating facilities in the early 1990’s were performing very badly from the point of view of reliability. However, from mid 1990’s onward, the Philippines power sector performance went to the other extreme of having excessive capacity compared to the demand. This validates the clamor of the people regarding high electricity rates which is due to oversupply since most of the generating facilities are operating under the take-or-pay contract with the National Power Corporation (NPC) and other distribution utilities. It can be concluded, therefore, that the generating capacity of the power system in the Philippines can be considered highly reliable. The interruptions that the country has been experiencing can be attributed to the unreliable transmission and distribution systems and their operations. Historical Cost Performance This study also assessed the power development in the Philippines by analyzing the cost of electricity. It was noted that the rates of NPC is for its bundled generation and transmission services. For purposes of this study, these rates were unbundled into 76% and 24% for generation and transmission, respectively. The rates of NPC appear to be increasing annually except for the year 2001 when R.A. 9136 (Electric Power Industry Reform Act) was enacted and the national government has intervened in the market due to the growing clamor against the Purchase Power Adjustments (PPA) in the electric bills. The increase in rates is attributed to the economic performance of the country (as exhibited by the exchange rates) and due to the take-or-pay contracts of NPC with Independent Power Producers (IPPs).



Records also show that the production cost of IPPs were always higher than the NPC rates. This contradict the avoided cost principle of the NPC IPP Program that IPP power development project proposals will be accepted as it offer electricity at prices lower than or at least equal to NPC rates. Comparing the average rate of NPC with that paid by the consumers, which range from PhP 4.00 to PhP 6.00 per kWh, there is difference of PhP 1.00 to PhP 3.00 per kWh. This considerable difference can be attributed to the cost of distribution and to the PPA of IPP’s that sell electricity directly to the distributors. It is also worthwhile to note that with the existence of the Non-NPC IPPs (permitted to operate through Executive Order 215), particularly those owned by electricity distributors like Manila Electric Company (MERALCO), many power plants were installed even though there were already excess generation capacity in the system. The main culprit here is that the IPPs’ return on investments were guaranteed by the take-or-pay contracts with NPC and the distribution utilities. This indicates the poor coordination of the plans of the IPPs that deal directly with Distributors in the context of centralized planning of the government, particularly the NPC. Historical Environmental Performance The environmental performance of the Philippine power sector from 1991 to 2001 (measured in terms of the amount of gases and particulates that are emitted by the electric power generating plants) shows that CO2 emissions increased by 74 percent while the rest of the air emissions increased by 10 to 169 percent.

For the CO2 emissions, coal power plants are the major contributors. Its contribution increased almost ten times from 1,082,279 tons in 1991 to 10,471,222 tons in 2001. CO2 emissions from oil-based power plants, on the other hand, decreased by 21 percent from its level of 9,236,541 tons in 1991 to 7,338,665 tons in 2001. Accounting the changes in oil and coal, the net increase in CO2 for the 11-year period is 73%. Looking into the energy mix to link the environmental performance of the power sector, it can be concluded that that non-renewable energy have remained greatly dominant over renewable energy as source of fuel for power generation. The share of non-renewable sources in the energy mix even increased from 57.49% in 1991 to 62.71% in 2001. Over the period considered, generation share from oil-based power plants declined from 49.9% in 1991 to 21.9% in 2001. However, coal contribution increased more than fivefold, from 8% in 1991 to 40% in 2001. In addition, renewable hydro share decreased from 20% to 5% over the same period. This scenario allowed the continued dominance of non-renewable fuels. Clearly, the shift is only towards the use of coal, which emits more greenhouse gases, and not towards the utilization of renewable resources. This explains why the emissions of the power sector almost doubled in only 11 years.



1.4 Scenarios under the Philippine Energy Plan 2003 - 2012 The prospective performance of the Philippine Power Sector was also assessed based on the Philippine Energy Plan 2003 – 2012 prepared published by the Department of Energy. Reliability, environmental emissions and costs were calculated similar to that of the historical performance assessment. PDP for the Low Economic Growth Scenario The PEP, based on the low economic growth projections of NEDA, shows that energy generation will increase by 93% (55,142 GWh in 2003 to 106,430 GWh in 2012) over the entire period at an average rate of 7.57% annually. Total installed capacity of 14,632 GW for 2003 will increase to 20,706 MW by 2012. The increase in demand will be met mostly by increases in coal power plants (3,500 MW) and oil-based plants (1,775 MW). The increase in the share of renewable energy generating capacity will come from a 795 MW large hydro, 65 MW wind and a 40 MW geothermal capacity additions. No additional capacity addition for natural gas is expected in the period. Capacity additions, operations and maintenance and fuel would require a total cost $ 23,828 million (UPSL estimate at 2002 present value). In terms of reliability, the planned capacity additions will result in high reserve margins. For example, the reserve in 2003 will be 66%. Although this is expected to decline to 22% by 2012, it is still unrealistic to expect that cost of electricity in the Philippines in the near term will decrease under this scenario. While the generation cost for this scenario is estimated at PhP 3.16/kWh, the Purchased Power Adjustment (PPA) component in the electricity bills of the end users is still expected to result in higher cost due to the high reserve margins. To meet the energy requirements, this scenario would require 124.5 million barrels fuel oil equivalent (MMBFOE) of oil, 91.9 million tonnes of coal and 1,263 billion cubic feet (BCF) of natural gas. Of these amounts, 124.5 MMBFOE of oil and 80.2 million tonnes of coal would have to be imported. The environmental emissions resulting from DOE’s generation plan for the low economic growth scenario would result in an increase in CO2, SOx and other emissions. Total CO2 emissions for the DOE plan for the low economic growth scenario is 309.3 million tonnes. The increase in the use of coal will account to contributing 55% of the total CO2 emissions for the period. Oil-based and natural gas plants will contribute 17% and 26% to the CO2 emissions, respectively. Geothermal plants will contribute only 2%. These emissions will be the direct result of the share of coal, natural gas and oil-based sources in the energy mix which is 34%, 24% and 4%, respectively for year 2003. From a share of 37% in 2003, renewable energy’s share will decrease to only 22% in 2012. The contribution of non-renewable energy sources to the energy mix, on the other hand will increase by 24%, with the continued dominance of coal plants. This scenario will require $ 29,368 million in abatement cost.



The PEP under the Low GDP Scenario reflects the continued preference on the use coal. Notably, this plan can be judged as a business-as-usual plan that will only replicate (or be even worse than) the historical performance of the Philippine power sector from the point of view of sustainable development. PDP for the High Economic Growth Scenario The DOE also prepared a power development plan based on high economic growth projections of NEDA. Analysis of the PEP under this scenario indicates that the plan is also a business-as-usual plan that will perform no better than the historical performance of the Philippine power sector, nor the scenario for the low economic growth. The following performance indicators can be expected if this scenario push through:

a) Installed capacity: 14,632 MW in 2003 to 22,756 MW in 2012

(56% increase for the 10-year period)

b) Energy generation: 55,556 GWh in 2003 to 118,470 GWh in 2012

(213% increase for the 10-year period)

c) Reserve Margin: 25% (minimum) to 65% (maximum)

d) Energy Mix: Coal - 16% in 2003 increase to 47% in 2012

Oil - 5% in 2003 increase to 16% in 2012

Natural gas - 24% in 2003 decrease to 17% in 2012

R.E. - 37% in 2003 decrease to 20% in 2012

With the continuous decline in the share of renewable energy, within the planning period, greenhouse emissions is expected to further soar, increasing by 195% from 2003 to 2012, and will require $ 32,995 million in abatement cost. 1.5 Clean Power Development Options for the Philippines Using the clean energy technologies and resources, two (2) alternative power development plans (or strategies) that will meet the demand of the Low Economic Growth Scenario and the High Economic Growth Scenario of the PEP were prepared by UPSL. These strategies are the following:

• Moderate Clean Power Development (CCPD) Plan

In this plan, capacity addition and utilization of renewable energy (geothermal, biomass, wind and hydro power) and natural gas plants are given priority over that of non-renewable plants for power generation. Total installed capacity of wind power plants is allowed to reach a maximum of 5% of the peak demand.



• Aggressive Clean Power Development (ACDP) Plan

For this plan, the strategy is to utilize all the practical renewable energy resources where possible without caps. Cost penalties for intermittent power plant capacity beyond 5% (based on peak demand) was also imposed to account for the additional ancillary services.

It was assumed in these plans that the local natural gas industry will be able to supply fuel for up to 3,800MW natural gas power plants (maximum generation of 23,000 GWh annually) for the next twenty years. The additional natural gas requirement will be supplemented by imports from the neighboring Asian countries and other natural gas producers until new local resources are developed. For all the plans, the 2003 to 2007 capacity additions were based solely on the PEP list of committed projects. The percentage installed reserve margin for the years 2008 onwards is kept as close as possible to the corresponding PEP reserve margins for comparison. Note, however, that these reserve margins do not take into account the ancillary diesel engines, which serve as frequency regulating plants for the wind power plants. Assuming a five-year lead-time for the planning to commissioning of the additional power plants, the capacity additions starts only in 2008. In this summary, only the power development plan to meet the Low Economic Growth Scenario of the PEP 2003 – 2012 is presented. The plans that correspond to the High Economic Growth Scenario are detailed in Chapter 5. Moderate Clean Power Development (MCPD) Plan To meet the demand of the Low Economic Growth Scenario, this plan will increase the renewable energy plant installed capacity by 95% (from 4,450 MW in 2003 to 8,685 MW in 2012) and the natural gas plant capacity by 117% (from 2,763 MW in 2003 to 5,983 MW in 2012). This translates to a 69% total installed capacity for the combined natural gas and renewable energy plants. The share of renewable energy in the energy mix will increase from 37% to 41%, from the period 2003 to 2012. The natural gas contribution will also increase from 24% to 31%. This will translate to a 72% total share of clean energy in the energy mix by 2012. The share of coal and oil in the mix will be reduced by about 11% at the end of the period. This plan will reduce the GHG emissions and abatement costs for the Low GDP Scenario by 14% and 21%, respectively, as compared with the PEP. Total CO2

reduction as compared with the PEP is 44.6 million tonnes. The total cost calculated for this plan is $23,592 million and the average generation cost is PhP 3.12/kWh. This average generation cost is even cheaper than that of the PEP Low GDP scenario, which is PhP 3.16/kWh. Considering the investment, O&M and fuel costs, this plan will save $235 million in the planning period.



Aggressive Clean Power Development (ACPD) Plan To meet the demand of the Low Economic Growth Scenario, the ACPD plan will increase the renewable energy plant installed capacity by 159% (from 4,450 MW in 2003 to 11,520 MW in 2012) and the natural gas plant capacity by 95% (from 2,763 MW in 2003 to 5,383 MW in 2012). This translates to a 79% total installed capacity for the combined natural gas and renewable energy plants. The share of renewables in the energy mix will increase from 37% to 48%, from the period 2003 to 2012. The natural gas contribution will also increase from 24% to 31%. This will translate to a 79% total share of clean energy in the energy mix by 2012. The share of coal and oil in the mix will be reduced by about 20% at the end of the period. This plan will reduce the GHG emissions and abatement costs under the PEP Low GDP Scenario by 18% and 27%, respectively. The total cost calculated for this plan is $23,881 million and the average generation cost is PhP 3.17/kWh. This is comparable to the PEP Low GDP scenario, which is PhP 3.16/kWh but five centavos (PhP 0.05) per kWh more expensive than the Moderate Clean Power Development Plan due to the additional ancillary services for the intermittent wind power supply. Considering the investment, O&M and fuel costs, this plan will cost an additional $41M in the planning period compared to the PEP low GDP plan. This translates to a mitigation cost of $0.67/tonne of CO2. With the current price of CO2 at $2 - $10 per tonne, this plan will create an opportunity for the country in the carbon market. 1.6 Conclusions and Recommendations The Philippine power sector from 1991 to 2001 has not performed very well in terms of reliability and cost to end-users. While the PEP has tried to address these problems, it fails to consider the implications of the activities in this sector to the environment that could even be more important if only the externalities will be considered in the economics of energy supply. This study has assessed the technologies and resources in the Philippines that could be tapped for clean power development. To avoid significant amounts of GHG emissions in the future, the country has to resort to biomass, small hydro, wind and natural gas technologies, as was done in this study. To support power switching, new natural gas sites must be identified and developed. In addition, natural gas importation may be pursued. This study also offers two alternative paths (moderate and aggressive) through the alternative clean power development plans. These alternative plans are comparable to the PEP in terms of costs. There are even opportunities that can create additional dollar income from carbon trading and local employment. At the current CO2 prices ($5 per tonne) in the market, the Moderate Clean Power Development Plans are viable greenhouse gas mitigation option for the Philippines offering so many



opportunities both for the developers and the country. Switching to cleaner energy, therefore, is attractive as the price of carbon is expected to increase in the future. Pursuing Clean Power Development plans requires the development of a “clean energy” market in the country through effective policy instruments and mechanisms that will secure the investment climate while protecting public interest. A set of measures that should be made to attract more investments in renewable generation technologies in the future discussed below. Energy Planning The first step in developing the market for clean energy is to introduce reforms in the process of energy planning itself. Since power developers will only respond to the government call, it is important that the Philippine Energy Plan reflect the call for clean power development. This could be achieved through the following: • Improve the power development planning models

- Include environmental externalities in planning models to reflect the true cost to society of energy decisions;

- Consider the economics of smaller capacity, following load growth to deal with the overcapacity issue (in contrast to large capacity power plants currently used in energy planning);

- Include energy efficiency as a demand side option in energy planning models;

- Use coal-fired fluidized combustion technology as benchmark fossil-based plant instead of pulverized coal;

- Increase the number of candidate Renewable Energy-based Power Plants in the selection process. To increase the number of candidate renewable energy plants in planning, more rigorous and site-specific resource assessment must be conducted.

• Institutionalize a participative planning process. A decentralized planning process down to the level of the local government and participated by the stakeholders in the locality should complement the top-down planning process at the national level. Electrification planning can be done in the municipality/city levels. Resource assessment and local supply and demand balance can be done at the provincial level. This decentralized planning scheme will result in a more realistic demand forecast and will address local issues on energy, as well as issues on under- and overcapacity. While this planning process allows for a greater degree of public participation, it will also entail capacity building for local government units in the areas of planning and resource assessment.

Transmission and Distribution Development Transmission and distribution infrastructure should be developed to increase access to renewable energy sites, most of which are site specific. Transmission facilities should deliberately be expanded toward locations of promising renewable energy sources.



The cost of such an expansion should be borne by the transmission or distribution utility. This cost mechanism will ensure that all electricity consumers will share the cost of such a development. The Energy Regulatory Commission (ERC) should allow such an expansion even if it does not initially show recovery of investment. Rules and Regulation • The Wholesale Electricity Spot Market (WESM) Rules must provide that

intermittent and small-scale grid-connected renewable energy generation systems (such as wind, run-of-river small hydro and biomass) should be given priority in the dispatch of generating units. These plants must “feed-in” the Grid at minimum prices that will guarantee the returns of power developers.

• The System Operator should be allowed to procure ancillary services needed by the Grid to accommodate intermittent wind power and pass on the cost to all users of the Grid.

• The Philippine Grid and Distribution Code (PGDC) must be clear on its requirements and procedures on the connection, operation and control of non-conventional, renewable energy-based power plants, particularly on the required technical analysis and compensating equipment.

Incentive Programs • The Department of Energy must ensure that renewable energy development

should always be included in the Philippine Investment Priorities of the Board of Investment to ensure that the fiscal (e.g., tax exemptions, income tax holidays and tax credits) and non-fiscal (e.g., simplification of custom procedures and importation of consigned equipment) will be available for renewable energy developers.

• An assistance program should be created for renewable energy development. This may include subsidy for resource assessment and feasibility studies for serious developers of renewable energy.

• Dedicated Financing Windows that allow longer repayment periods for renewable energy-based development.



2 ENERGY TECHNOLOGIES AND RESOURCES FOR CLEAN POWER An area that has great potential for greenhouse gas (GHG) reduction is the power sector. In 1994, the energy sector accounted for 50,038 ktonnes of the 100,738 ktonnes, or roughly 47 percent, of total net GHG emissions in the country, as shown in Table 2.1. Of the energy sector GHG emissions, the energy industries, mainly the power industry, accounts for more than thirty (30) percent as a result of the burning of fossil fuels, as shown from Table 2.2. Although it ranks only second to the transport in terms of GHG emissions, the power sub-sector represents a large opportunity for carbon emissions reduction and sequestration, given that clean energy technologies and resources are available.

Table 2.1: 1994 Philippine Greenhouse Gas Emissions by Sector (equivalent ktonne CO2)

SECTOR CO2 CH4 N2O Total

Energy 47,335 1,985 717 50,038 Industry 10,596 7 0 10,603 Agriculture 20,800 12,330 33,130 Waste 0 6,140 954 7,094 Land Use & Forestry -2,774 2,403 245 7,094 TOTAL EQUIVALENT CO2 EMISSIONS 55,157 31,335 14,246 100,738

Source: The Philippines’ Initial National Communication on Climate Change

Table 2.2: 1994 Greenhouse Gas Emissions from the Philippine Energy Sector*

(equivalent ktonne CO2)

SECTOR CO2 CH4 N2O Total

A. Fuel Combustion Activities 47,335 1,759 717 49,811 1. Energy Industries 15,4583 11 40 15,509

2. Manufacturing Industries 8,980 170 347 9,497

3. Transport 15,801 45 43 15,890

4. Commercial/Institutional 3,368 1 0 3,369

5. Residential 2,544 1,529 285 4,359

6. Agriculture 1,185 2 3 1,190

B. Fugitive Emissions from Fuels 226.59 227 1. Coal Mining 216.72 217

2. Oil 9.87 10

TOTAL EQUIVALENT CO2 EMISSIONS 50,038 * does not include emissions from biomass Source: The Philippines’ Initial National Communication on Climate Change

3 The University of the Philippines Solar Laboratory (UPSL) calculated a slightly different value from that of the Philippines’ Initial National Communication on Climate Change. The UPSL came up with 13,548 ktonnes of CO2 for the Energy Industries for the year 1994.



This study focuses on the reliability, cost and environmental performance (particularly on GHG emissions) of the power sector. In particular, it looks into scenarios that would entail switching to clean energy technologies from conventional fossil fuel-based technologies for grid-connected power generation. In the sections that follow, technologies and resources that could be used to reduce GHGs from the power sector shall be discussed and evaluated to determine what could be used in the Philippine power sector. 2.1 Clean Energy Technologies Clean energy technologies are those that result in relatively fewer GHG emissions per unit of energy service delivered as compared to conventional technologies. These technologies may be classified as4:

• measures that reduce the energy intensity of the economy (e.g., energy conservation, improvement of power plant heat rates);

• measures that reduce the carbon intensity of energy (e.g., renewable energy technologies); and

• measures that integrate carbon sequestration into the energy production and delivery system.

These technologies may be an attractive alternative to conventional fossil fuel-based generation technologies in terms of its environmental benefits. However, they must compete with the same technologies in terms of other criteria such as cost, resource availability and technology maturity before application on a significant scale could be expected. In the following sections, a number of clean energy technologies shall be discussed. These technologies will then be evaluated to determine their viability for the Philippine power sector. Measures that Reduce Energy Intensity One way of reducing the energy intensity of the economy is by minimizing energy losses in the system. In power generation, improvements could be made to improve the efficiency of existing power plants by decreasing their heat rates, i.e., the heat energy in Btu required by the power plants to produce a kilowatt-hour of electric energy. This is done by looking at ways to improve the performance of existing power plant components like boilers, turbines and generators. This measure is a cost-effective method of achieving CO2 reductions in that it would not entail large costs for equipment although it would require capability-building activities. The Philippines Department of Energy (DOE) has already started a Heat Rate Improvement Program, which is expected to achieve a substantial amount of energy savings.

4 Marilyn A. Brown, Mark D. Levine and Walter D. Short, Scenarios for a Clean Energy Future, (U.S.: Interlaboratory Working Group on Energy-Efficient and Clean Energy Technologies), p. 1.2



Another measure is the use of efficient end-use devices. Improved technologies for electricity-consuming end-use devices are available in the market like more efficient motors, lighting technologies, refrigerators and air conditioners. In a study made by Leverage International (Consultants) Inc. on the characterization of new commercial buildings in the Philippines, it was mentioned that energy savings amounting to 39%, 32% and 10% could be realized from more efficient air conditioning, lighting and other office equipment, respectively5. In the industrial sector, potential energy savings could be realized in the use of high efficiency motors. A study conducted in 1994 estimated energy savings amounting to 423 GWh and about 74 MW of capacity could have been realized by the year 2010 in the Manila Electric Company (MERALCO) franchise area6 alone had a high efficiency motors program been implemented in 19977. The DOE has for some time been implementing an efficiency and energy-labeling and standard program to help consumers select electric appliances and equipment. The program includes the Efficiency Standard and Labeling for Room Air Conditioners, the Energy Labeling Program for Refrigerators and Freezers, the Fluorescent Lamp Ballast Energy Efficiency Standard and the Performance Certification of Fans and Blowers. The program is expected to achieve a potential energy savings amounting to 9.7 MMBFOE from 2002 to 20118. Despite the high potential of technology measures that reduce energy intensity, which could be treated as a resource in energy planning, it is not used in this study because data available in the Philippines is insufficient to do so. Measures that Reduce the Carbon Intensity of Energy For the electricity generation sector, technologies that reduce carbon intensity of energy can be classified in a number of categories. These categories are not absolute in that they sometimes overlap and some particular technology types fall under two or more categories. They are as follows: • Renewable energy technologies

These are technologies that harness the energy from renewable energy sources for power generation. Renewable energies include solar, wind, hydro, biomass and geothermal energies. Aside from it’s being clean, renewable energy sources, because of its “inexhaustibility” addresses other challenges of the energy sector such as sustainability and energy security.

5 Philippine New Commercial Building Market Characterization, (Philippines: Department of Energy, 1998), p. 9. 6 MERALCO is the distribution utility that services Metro Manila, Bulacan, Rizal, Cavite and parts of the provinces of Laguna, Quezon, Batangas and Pampanga. 7 The study referred to is the Asian Development Bank-funded Long Term Power Planning Study conducted by SRC in 1994, mentioned in the material for the March 12, 1998 meeting for the Motor Energy Efficiency Enhancement Program. 8 Philippine Energy Plan 2002-2011, (Philippines: Department of Energy), p. 59.



1. Wind Energy. The kinetic energy of the wind can be converted to mechanical energy by means of a wind turbine. This mechanical energy can then be used to run electric generators to produce electricity. Wind energy conversion technology (WEC) is a mature technology, with worldwide installed capacity totaling to 24,000 MW by the end of 2001.

Intermittent power would affect power system operability and stability and therefore poses limitations on levels of penetration of wind power. Various modeling studies show that wind generation capacities could amount from a low value of 4% to a high value of 50% of system load9, depending on system conditions. Utilities’ operational experience, particularly in the United States, has been limited to low wind power penetration levels so far. Also, intermittent generation will require additional ancillary services to be provided in the grid, and therefore translates to higher electricity costs. For the Philippines, initial estimates for wind penetration levels are between 5% and 20%. The University of the Philippines Solar Laboratory (UPSL) is currently doing studies to determine acceptable wind penetration levels considering economics and the stability of the transmission system.

2. Hydro Power. Hydro power refers to the use of falling or flowing water for

power. It is a renewable form of energy because the energy of flowing water ultimately comes from the sun. Water evaporation from the oceans and other parts of the earth’s surface consumes about one fourth of the total solar incidence on the planet. This water will return to the earth’s surface as precipitation (e.g., through rain or snow) and part of it will eventually contribute to the flow of streams, rives and falls.

Hydro power resources come in various sizes. The Philippines Department of Energy (DOE) classifies hydro resources based on its potential capacity, as follows: micro-hydro for hydro resources with capacities ranging from 1 to 100 kW; mini-hydro for those with capacities from 101 kW to 10 MW, and; large hydro as those with capacities greater than 10 MW10. Hydro power is considered a clean technology because it is renewable and does not emit air pollutants. In some cases, it generates some amount of GHG gases as a result of the rotting of organic matter that get submerged in reservoirs, but the amount of emissions is small as compared to fossil fuel-based electricity generation. The Canadian Hydropower association estimates that GHG emissions from hydro facilities is 60 times less than that of coal power plants and 18 times less than that of natural gas power plants11.

9 p. 49, Yih-huei Wan and Brian K. Parsons, Factors Relevant to Utility Integration of Intermittent Renewable Technologies, (Colorado: National Renewable Energy Laboratory, 1993), p. 49. 10 The World Energy Commission uses a different classification from that used by the DOE, which are as follows: micro hydro resources are those with capacities less than 100 kW; mini-hydro resources are those with capacities ranging from 100 kW to 1 MW, and; small hydro resources are those with capacities from 1 to 10 MW. Large hydro resources are those with capacities greater than 10 MW. Thus, the Philippine definition of mini-hydro encompasses the WEC mini- and small-hydro resources. 11 Quick Facts, Canadian Hydropower Association



Hydro power facilities offer other benefits such as low generation costs, high efficiencies, little maintenance, long life and high levels of reliability. They are – large hydro in particular - however, associated with a number of negative impacts. Among them are:

Ecological Effects

a. Landscape destruction

b. Destruction of fish habitat and fisheries

c. Rearrangement of water resources

d. Increase in water pollution

e. Displacement/wiping out of plant and animal species

f. Silting Social Impacts

A major negative social impact of large hydro projects is the dislocation of population. Various hydro projects in the Philippines have dislocated thousands. In the Philippines, the Agno River Basin Development Program resulted in the loss of hectares of Ibaloy ancestral lands and the subsequent dissolution of several Ibaloy communities. The alteration of the local ecosystem also resulted in the loss of resource base, which served as livelihood of the Ibaloys.

Risk and Safety

Major disasters involving dams have occurred in the past at 6 to 10 year intervals. With about 15,000 dams all over the world, the frequency of disasters involving dams is 1 disaster for every 120,000 dam years. Speculation also arise that dams cause earthquakes in its surrounding areas.

3. Biomass Energy. Like hydro and geothermal power, biomass energy is a

renewable resource that can be used for base load electric generation. Technologies that can be used to generate power from biomass include gasification-electric generation systems and burner technologies similar to that used for coal.

4. Geothermal Energy. Geothermal energy refers to the heat stored in the

rocks within the earth. In places where the earth’s heat flow is concentrated, this energy may be harnessed in the form of steam or hot water, which can subsequently be used for power generation. Geothermal energy is not entirely GHG emissions-free, but it emits far less greenhouse gases as compared to fossil fuel-based counterparts.



5. Solar Energy. Solar radiation may be converted to electricity by using solar thermal engines or photovoltaic cells. Solar thermal engines make use of solar concentration systems, which, as the name implies, concentrates the power of the sun, to generate high enough temperatures to heat and boil water to drive steam engines. Photovoltaics, on the other hand, convert solar energy directly to electricity in a solid-state device called the solar cell.

• Clean coal technologies

Coal in itself is considered not a clean fuel because of the relatively high levels of carbon dioxide and pollutant emissions resulting from its combustion as compared with other fuels. Despite its unfavorable environmental reputation, coal is still widely used around the world for power generation because it is abundant and cheap. Various research and development efforts in the past three decades have been successful in coming up with technologies that give better efficiencies than the conventional pulverized coal technology or that convert coal into liquid or gas fuels. Many such technologies have been demonstrated in various countries but still remain not widely used because its high investment costs are quite prohibitive. These include fluidized bed systems such as pressurized fluidized bed combustion (PFBC) and circulating fluidized bed combustion (CFBC), integrated gasification combustion cycle (IGCC) systems and coal-fueled diesel engines. Clean coal technologies are costly, sometimes requiring around $3,000 per kilowatt of installed capacity.

• Gas turbines

Current gas turbine plants have efficiencies of around thirty percent. Newer plants are actually achieving efficiencies greater than forty percent. But since this type of plant is normally used for peak load applications, this would have a relatively low impact on emissions reduction.

• Fuel cells

Fuel cells are devices that convert fuel and oxygen to electricity and heat by means of an electrochemical reaction. For most fuel cells, hydrocarbon fuels need to undergo a process of reforming to produce hydrogen, which is the form of fuel required for the electrochemical reaction to take place. Fuel cells have efficiencies ranging from 40 to 60 percent and could achieve very negligible carbon and air pollutant emissions when paired with carbon separation technologies. Costs are prohibitive, however, ranging from $2,000 to $4,000 per installed kilowatt.

• Distributed energy technologies

Unlike centralized generating units, distributed energy technologies are small and modular, with sizes ranging from a few kilowatts to a few megawatts. Distributed energy technologies can be located on the site where the resource is available or near the place where the energy is to be used. Greater local control of the system and waste heat utilization lead to higher energy efficiencies, and thus, less GHG and air pollutant emissions.



Distributed power units could be connected directly to consumers or to the transmission or distribution grid. These could provide standby generation and base load generation, peak shave, and provide waste heat (cogeneration). And because they are located near the load, transmission and distribution costs can be reduced. Technologies used for such applications include internal combustion engine-generators, fuel cells, turbine generators and renewable technologies like solar photovoltaics, wind turbines and microturbines. Through a process called gasification, biomass fuels could also be used for distributed generation to produce a gaseous fuel that can be burned in diesel- or gas motors or in gas turbines.

• Improved fossil fuel-based technologies

Aside from clean coal technologies, newer and more efficient versions of conventional fossil fuel-based technologies have been and are being developed and designed.

• Natural gas technologies

Natural gas is a fossil fuel that has clean burning properties and lower CO2 emissions as compared to other fuels. Natural gas could be used to fuel a number of power generating technologies, including combined cycle gas turbines and fuel cells. Some of these technologies, particularly combined cycle gas turbines, have investment costs that are competitive with other conventional power generation technologies.

Measures that Integrate Carbon Sequestration Carbon sequestration involves the capturing of carbon dioxide in the atmosphere or keeping it from reaching the atmosphere. For the power sector, devices for carbon sequestration use the process of adsorption of carbon dioxide on materials like activated carbon, zeolites or inorganic membranes. Employing such devices in power generation facilities would require significant capital cost and may thus increase the cost of electricity.



2.2 Resource Assessment The technologies described above would be rendered useless without the energy resource required to run them. The following sections will quantify the amount of clean energy resources in the Philippines, which will then be subsequently used for the generation of power switching scenarios. Wind Power The wind resource analysis and mapping study for the Philippine archipelago conducted by the National Renewable Energy Laboratory (NREL) shows that the country has plentiful wind electric potential. The NREL study identified around 10,000 sites in the country, occupying a total area of 11,055 km2 or roughly 3.34% of total Philippine land area, with good to excellent resource levels - equivalent to an annual average wind power of 300 W/m2 or greater12 (wind speeds of 6.4 m/s or greater). According to the study13, these sites could support at least 76,600 MW of installed capacity and generate 195,200 GWh/yr. Including sites with moderate wind resource levels, amounting to 97,000 installed capacity, would more than double total installed capacity to 173,600 MW bringing the total estimated power generation from wind to 361,000 GWh/yr. The study, however, was not able to include factors such as transmission and grid accessibility constraints in the assessment. The NREL study identified six regions in the country where the best wind resource in the country are located. These are:

1. the Batanes and Babuyan islands of north Luzon;

2. the northwest tip of Luzon (Ilocos Norte);

3. the higher interior terrain of Luzon, Mindoro, Samar, Leyte, Panay, Negros, Cebu, Palawan, eastern Mindanao, and adjacent islands;

4. well-exposed east-facing coastal locations from northern Luzon southward to Samar;

5. the wind corridors between Luzon and Mindoro (including Lubang Island);

6. between Mindoro and Panay (including the Semirara Islands and extending to the Cuyo Islands).

In contrast to the optimistic estimate of the NREL, an earlier study by the United Nations Industrial Development Organization (UNIDO) in 1994 puts the wind electric power potential for the entire Philippines at a very conservative value of 250 MW14.

12 In one of the NREL scenarios, areas with annual wind power densities of 300 W/m2 or greater were assumed to have sufficient potential for the economic development of utility-scale wind energy. 13 Assumptions used by NREL to come up with estimates are: 500 kW turbine size, hub height = 40 m, rotor diameter = 38 m, turbine spacing = 10D by 5D, capacity/km2 = 6.9 MW. 14 UNIDO, Assessment of Technical, Financial and Economic Implications of Wind Energy Applications for Power Generation, (1994).



Despite the vastness of wind resources in the country, current utilization are mostly to run wind pumps and a few small-scale turbine generators. At present, there are more than 500 wind pump and 9 wind turbine installations in the country. All wind turbine installations are of the stand-alone type, among which are the following:

1. A 10-kW system in Pagudpod, Ilocos Norte in Luzon. This is a pilot project of the National Power Corporation to electrify a number of households. It was commissioned in 1996.

2. A 25-kW stand-alone system in Picnic Grove, Tagaytay, Batangas in Luzon.

3. A 3-kW system in Bantay, Ilocos Sur in Luzon. In tandem with a diesel generator, this system is used to power up a relay station of the Philippine Telegraph and Telecommunications Company (PT & T). It is in operation since 1994.

4. A 25-kW system in General Santos in Mindanao. Two committed wind projects are expected to contribute a significant amount of electricity to grid. These are the 40-MW North Luzon Wind Power Project (NLWPP) of the Philippine National Oil Company-Energy Development Corporation (PNOC-EDC) and the 25-MW wind project of Northwind, which are scheduled for commissioning in 2006 and 2004, respectively. These wind facilities will both be located in Ilocos Norte. Proponents of these projects were able to secure power purchase agreements with the local distribution utility, which they used to obtain financing. Further, project proponents were able to obtain very lenient and attractive financing schemes. The PNOC-EDC project was given a soft loan amounting to $48 million dollars by the Japan Bank for International Cooperation (JBIC) at annual interests below 1 percent (0.95 percent for goods, 0.75 percent for consulting services) and a 40-year repayment period (inclusive of a 10-year grace period). Project proponents claim that they will be able to sell electricity at prices below that of the grid. It is significant to note two issues that developers of these two wind power projects had to address. First is the absence of site-specific wind assessment data, which required the developers to collect at least two-years of wind speed measurements. Second is the connection of the wind farms to the transmission grid. Transmission facilities are quite far from the wind sites, that for the NLWPP, that the PNOC-EDC was required to put up 42 kilometers of transmission line and 130 transmission line towers/poles to connect to the nearest transmission line trunk.



For the purposes of the present study, a re-analysis of the NREL data was conducted by the UPSL using the following criteria to screen for viable wind power sites:

1. Power density of at least 500 W/m2;

2. The transmission line components to connect the site to the existing grid will not exceed 25% of the levelized cost of the combined generation and transmission cost. To compute for transmission cost, the UPSL computed for the linear distance between the wind site and the nearest existing substation. This distance was multiplied by a factor of 1.5 to adjust for topography and other factors that may affect the routing of the transmission system.

The first criteria reduced the number of wind sites to 2,092, with an aggregate potential of 14,363 MW. The application of the second criteria further reduced the number of sites to 1,038 with 7,400 MW potential. Tables 2.3 and 2.4 summarize the results of the re-analysis. Locations of these sites are shown in Figure 2.1. Appendix A identifies the provinces where these wind resources are located, as well as its corresponding estimated electric capacity and annual generation.

Table 2.3: Philippine Wind Electric Potential

(with wind power density ≥ 500 W/m2)

Luzon Visayas Mindanao Philippines Number of sites 1,668 360 64 2,092 Total area, km2 1,755 385 66 2,206 Potential installed capacity, MWe 11,381 2,527 455 14,363

Estimated Annual Generation, GWh/yr 35,437 7,865 1,397 44,699

Table 2.4: Practical Wind Resources in the Philippines (with wind power density ≥ 500 W/m2 and transmission cost constraint)

Luzon Visayas Mindanao Philippines Number of sites 686 305 47 1,038 Total area, km2 753 330 49 1,132 Potential installed capacity, MWe

4,900 2,168 336 7,404

Estimated Annual Generation, GWh/yr 15,277 6,738 1,032 23,047



Figure 2.1: Practical Wind Resources in the Philippines (with wind power density ≥ 500 W/m2 and transmission cost constraint)

Luzon Number of sites: 686 Potential Installed Capacity: 4,900 MWe Estimated Annual Generation: 15,277 GWh

Visayas Number of sites: 305 Potential Installed Capacity: 2,168 MWe Estimated Annual Generation: 6,738 GWh

Mindanao Number of sites: 47 Potential Installed Capacity: 336 MWe Estimated Annual Generation: 1,032 GWh



Hydro Resources Hydro power contributes a large amount of energy to grid-based electricity in the country. By the end of 2001, a total of 2,518 MW of hydro power is installed in the Philippines, with an annual production of 7,104 GWh. These hydro power facilities range in size from 1 to 360 MW and includes reservoir type (dams) and run-of-river systems15. In addition to the existing hydro power generation facilities, a number of large hydro sites in country to be used as candidate power plants for energy planning. Table 2.5 lists down identified sites for large hydro16. The UPSL made a re-analysis of the small17 hydro resource assessment made by the NREL, selecting sites with capacities of 5 MW or more. Using this criterion, the UPSL identified 239 small hydro sites in the country with an aggregated capacity of about 2,327 MW. An additional screening criterion was used, i.e., sites whose transmission line components needed to connect to the existing grid must not exceed twenty five percent of the levelized combined generation and transmission investment costs. These resulted to the elimination of three sites from the small hydro resource pool. Tables 2.6 and 2.7 shows the results of the application of the criteria mentioned above, while Figure 2.2 shows the location of the sites selected. The DOE has verified a number of these small hydro sites, as listed in Table 2.8.

15 Impoundment dams involve the impounding of a large volume of water in or upstream of power plants by use of reservoirs or dams. This water may then be used to augment supply during low flow periods and thus ensure a relatively constant supply of power. Run-of-river systems, on the other hand, make use of the natural flow of a rivers as head. 16 Two of these sites, Kalayaan and San Roque, are committed projects. 17 As per WEC definition.



Table 2.5: Available Large Hydro Resources

Site Province Estimated Capacity (MW)

LUZON Abuan Isabela 60 Addalam Quirino 46 Agbulo Apayao 360 Aglubang Mindoro Oriental 13.6 Amburayan Benguet 93 Bakun A/B Benguet 45 Binongan Abra 175 Catuiran Mindoro Oriental 24 Diduyun Quirino 332 Kalayaan PS Laguna 350 Kanan Quezon 113 Lamut Ifugao 12 Matuno Ifugao 52 to 250 Nalatang Benguet 45 Pasil B/C Kalinga Apayao 42 Saltan A/B Kalinga 34 San Roque Pangasinan 345 Tanudan D Kalinga 27 Tinglayan B Kalinga 21 Total Luzon 2,189.6 to 2,387.6 VISAYAS

Pacuan Negros Oriental 33 Sicopong Negros Oriental 17.8 Timbaban Aklan 29 Villasiga Antique 29 Total Visayas 108.8 MINDANAO

Agus III Lanao del Norte 225 Bulanog-Batang Bukidnon 150 Lanon Hydro South Cotabato 21 Lake Mainit Agusan del Norte 22 Liangan Lanao del Norte 11.9 Pugo D/BA Agusan 44 Pulangi V North Cotabato 300 Tagoloan Bukidnon 68 Total Mindanao 841.9 TOTAL PHILIPPINES 3,140.3 to 3,338.3



Table 2.6: Philippine Small Hydro Electric Potential

(sites with power capacity ≥ 5 MW)

Luzon Visayas Mindanao Philippines Number of sites 134 9 96 239 Potential installed capacity, MWe

1,291 58 978 2,327

Estimated Annual Generation, GWh/yr 6,786 305 5,140 12,231

Table 2.7: Practical Small Hydro Resources in the Philippines (sites with power capacity ≥ 5 MW and transmission cost constraint)

Luzon Visayas Mindanao Philippines Number of sites 131 9 96 236 Potential installed capacity, MWe

1,272 58 978 2,308

Estimated Annual Generation, GWh/yr 6,686 305 5,140 12,131

Table 2.8: Small Hydro Power Sites Verified by the DOE

Site Province Estimated Capacity (MW)

LUZON Colasi Camarines Norte 1.0 Total Luzon 1.0 VISAYAS Amandaraga Eastern Samar 4.0 Bugtong Samar 1.0 Igbolo Iloilo City 4.0 Siaton Negros Oriental 5.4 Total Visayas 14.4 MINDANAO Lower Dapitan Zamboanga del Norte 3.8 Taguibo Agusan del Norte 7.0 Middle Dapitan Zamboanga del Norte 4.4 Libungan North Cotabato 10.0 Upper Dapitan Zamboanga del Norte 3.6 Total Mindanao 28.8 TOTAL PHILIPPINES 44.2



Figure 2.2: Practical Small Hydro Resources in the Philippines (sites with power capacity = 5 MW and transmission cost constraint)

Luzon Number of sites: 131 Potential Installed Capacity: 1,272 MWe Estimated Annual Generation: 6,686 GWh

Visayas Number of sites: 9 Potential Installed Capacity: 2,308 MWe Estimated Annual Generation: 12,131 GWh

Mindanao Number of sites: 96 Potential Installed Capacity: 978 MWe Estimated Annual Generation: 5,140 GWh



Biomass In the past, biomass has contributed a significant amount to the national energy consumption, amounting to as much as 30% of the total energy mix. However, the contribution of biomass to grid-based electricity is yet to be seen. Among identified biomass resources in the Philippines include forestry resources and fuel wood, bagasse (residue resulting from the extraction of sugar cane juice), rice hull, coconut residues, animal wastes and municipal solid wastes. Table 2.9 shows the projected supply of these biomass resources, as estimated by the Philippines Department of Energy.

Table 2.9: Projected Supply of Biomass Resources (petajoules)

Type 2005 2010 2015 2020 2025

Rice Residues 56.43 62.28 68.81 75.95 83.88

Coconut Residues 134.75 148.78 164.27 181.35 200.20

Bagasse 95.47 116.14 141.28 171.90 209.11

Fuelwood 608.54 693.63 796.05 919.21 1067.51

Animal Wastes 79.12 83.20 87.41 91.87 96.56

Municipal Wastes 736.40 833.14 934.77 1040.48 1149.12

TOTAL 1710.69 1937.19 2192.60 2480.76 2806.38 Source: Promotion of Renewable Energy Sources in South East Asia (PRESSEA) website

This high resource estimate for biomass resources has led to optimistic opinions regarding grid-connected electricity generation systems using biomass. A joint report by the United Nations Development Programme (UNDP) and the World Bank estimates power from biomass that can be exported to the grid, as follows: 60 to 90 MW from bagasse, 40 MW from rice hull and 20 MW from coconut residues. Although the paper and sugar industries already are using their biomass residues to generate heat and power for their own use, grid-connected systems have yet to materialize. Two promising power generation projects using biomass as fuel are in the development stage, both of which will be located in the province of Negros Occidental in Region VI (Western Visayas Region)18. These are the Victorias Bioenergy and the Talisay Bioenergy projects, both of which are joint undertakings of Bronzeoak Ltd of the United Kingdom and Venture Factors of the Philippines.

18 In 1999, Region VI accounted for almost 2 million tones of the total 3.6 million tones, roughly 54%, of bagasse produced from sugar mills all over the country.



The first project will involve the construction of a biomass-fired cogeneration plant inside the Victorias Milling Company (VMC) complex19. The plant, which will consist of two 161.5-tonne/hr boilers and a 50-MW steam turbine generator, will supply all the steam and power requirements of the VMC refinery facilities20, and sell excess power to the local electric cooperative Central Negros Electric Cooperative (CENECO).21 Fuel would consist of bagasse and cane trash from VMC, bagasse from other mills, and if needed, wood chips from local sustainable plantations22. It is estimated that the plant would consume 741,000 tonnes of bagasse annually. It is also estimated that the project could sell about 1.6 million certificate of emissions reduction (CER) credits over a 10-year period. The project would cost about US$ 100 million23. The plant is expected to sell electricity at a price below that of the grid. Commercial operation of the plant is scheduled on October 2005. The second project, Talisay Bioenergy, is similar to VBI but smaller in scale. It will involve the construction of a cogeneration plant in the facility of First Farmers Holdings Corporation24 (FFHC). The plant, which will consist of two 85-tonne/hr boilers and a 30-MW steam turbine generator, will supply all of FFHC’s steam and electricity requirements in exchange for the mill’s bagasse production. The plant will also provide any additional steam and electricity requirements of the FFHC at commercial rates. Electricity that will be produced by the plant in excess of FFHC’s requirements will be supplied to the local transmission grid. Commercial operation of the plant is scheduled on August 2006. The project will cost approximately US $ 60 million. Projects like the Victorias and Talisay Bioenergy projects provide economically attractive options to sugar mills for the provision of its energy requirements and dealing with its waste products. As a matter of fact, two similar projects are also being explored for possible development, also in Region VI. Table 2.10 shows UPSL’s estimates of the electric potential of bagasse in the Philippines on a per region basis. These estimates take into account that bagasse-fired systems are normally cogeneration systems25.

19 Victorias Milling Corporation has the largest milling facilities in the country, with a milling capacity of 15,000 tonnes of cane per day. 20 VBI and VMC had an initial understanding to have a 30-year energy supply agreement. Additional steam and electricity requirements of VMC will be provided by VBI at commercial rates. 21 Part of the power that will be generated by VBI will go to CENECO: 26 MW during the on-season and 43.6 MW during the off-season. A 30-year “take-or-pay” Power Supply Agreement has already been executed between CENECO and VBI. 22 Bagasse and cane trash from VMC will be provided to VBI free of charge. Bagasse will also be acquired from other plantations to supplement fuel supply. In case the amount of available bagasse and cane transh could not meet plant demands, wood chips will be acquired from industrial tree plantations. Bronzeoak and Venture Factors plan to put up Biofuel Resources, Inc. that would establish industrial tree plantations using short term tree crops. 23 Aside from plant facilities, this cost includes the construction of a 138-kV switching station and a tie-line connector approximately 3 km long. 24 FFHC has a milling capacity of 4,800 tonnes of cane per day. 25 Cogeneration systems produce electricity and heat (steam) simultaneously. Fuel consumption for cogeneration systems using bagasse as fuel is around 3kg of bagasse for every kWh of electricity produced. This value already takes steam production into account.



Because of problems with such issues like collection, storage and competing uses, which are like associated with the use of biomass fuels for large scale power generation, this study only looks on the potential of bagasse for grid-connected electricity generation. Unlike other biomass fuels, bagasse has traditionally been used in large quantities, particularly to fuel boilers in sugar mills. Despite sugar mills’ own use of bagasse for fuel, there usually remains a considerable amount of this waste material, which the mills have to dispose.

Table 2.10: Philippine Bagasse Electric Potential

Region Name Potential Installed Capacity (MW)

1 Ilocos Region 0.2 2 Cagayan Region 3.1 3 Central Luzon 14.0 4 Southern Tagalog 22.0 5 Bicol Region 4.6 6 Western Visayas Region 127.8 7 Central Visayas Region 32.7 8 Eastern Visayas Region 7.6 10 Northern Mindanao 17.9 11 Southern Mindanao 5.8

TOTAL PHILIPPINES 235.7

Geothermal Power The Philippines power sector largely depends on geothermal energy to meet the demand and energy requirements of the country. In 2001, total geothermal installed capacity amounted to 1,931 MW and geothermal generation was 10,442 GWh, accounting for 14% and 22% of the total installed capacity and total generation, respectively. In addition to existing geothermal power facilities, an estimated capacity of 1,200 MW and energy of 8,935 GWh can be obtained from the verified geothermal source candidates in the Philippines, as listed in Table 2.11. Of the total estimated capacity, 380 MW, 700 MW, and 120 MW come from Luzon, Visayas and Mindanao respectively. Very small, if any, additional geothermal resources could be expected in the future as the Philippines has nearly used most of its geothermal resource sites.



Table 2.11: Available Geothermal Resources for Power Generation

Name Location Potential Installed Capacity LUZON Bacman I Sorsogon 10 Rangas Tanawon Sorsogon 40 Manito Albay 20 Montelago Oriental Mindoro 20 Daklan Benguet 10 Mt. Natib Bataan 20 Mabini Batangas 20 Batong Buhay Kalinga 120 Buguias-Tinoc Benguet 120 Total Luzon 380 VISAYAS Northern Negros* Negros Occidental 40 Dauin Negros Oriental 20 Mt. Cabalian Leyte 60 Leyte Optimization Leyte 40 Biliran Biliran 40 Mt. Lobi Central Leyte 200 Mahagnao Central Leyte 300 Total Visayas 700 MINDANAO Lakewood Zamboanga del Sur 80 Manat-Amacan Davao del Norte 40 Total Mindanao 120 PHILIPPINES TOTAL 1,200

*committed plant Source: DOE

Natural Gas A few natural gas finds in the Philippines have been made, the most significant of which is that found in Malampaya and San Martin in Palawan26, with a combined estimated reserves of 2,771 to 4,731 billion cubic feet (BCF). Table 2.12 lists down identified natural gas fields in the country and their corresponding resource sizes. The Philippine government is considering plans to develop a local natural gas industry, which will involve the laying down of a natural gas pipeline network in Luzon and the construction of liquefied natural gas (LNG) facilities at different points in the country. If this pushes through, local natural gas production would be supplemented by imported natural gas that would come from the Trans ASEAN Gas Pipeline to meet demand.

26 These are proven fields. Source: PEP 2002-2011.



Table 2.12: Philippine Natural Gas Resources

Resource Size (BCF) Gas Field Minimum Prospective Maximum PROVEN Camago-Malampaya 2,538 3,340 4,277 San Martin 243 359 454 San Antonio 4 POTENTIAL Mindoro-Cuyo 2,720 7,060 11,210 Cotabato 60 1,158 1,760 Cagayan 176 322 518 Central Luzon 78 637 2,594 Source: Philippine Natural Gas Plan

2.3 Cost Comparison of Power Generation Technologies The investment, O & M27 and fuel costs28 comparison of the different types of power plants are shown in Table 2.13. In general, renewable energy-based plants have high investment costs. Wind and hydro plants do not require fuel but do not run at full capacity due to availability of resources. In addition, the total investment costs vary with site preparation and the required transmission lines to enable the plants to deliver power to the grid. The costs shown in Table 2.13 include only the costs of the technologies but not the associated site-specific costs that could be more expensive than the plant itself. Being site-specific, renewable energy-based power plants have to address these issues that will ultimately determine the viability of the power projects. For fossil-fuel-based power plants, it is notable that the technologies that require low investment normally require fuel with high cost. For example, coal plants could cost twice as much as diesel plants but the fuel cost for diesel plants could be 2 to 4 times the cost of coal per kWh of electricity generated. The fuel costs in Table 2.13 lists for different fuels used for power generation are based on typical power plant efficiencies. Renewable energy technologies, in general entail high investment costs. The high front-end cost associated with renewable energy technologies is often cited as one of the reasons for the high perceived risk for these technologies. Clearly, the economics of power generation technologies depends on several factors, namely: (a) investment cost, (b) operation and maintenance (O&M) cost, (c) fuel cost, and (d) the level of generation (also called capacity factor29). Screening curves can be developed to determine the optimum power generation plan considering these four factors. Using these curves, the type of power plants that will 27 Figures used for power plant investment and O&M cost are only intended for relative comparison. 28 The fuel costs used in this study do no include import duties. Furthermore, the prices of fuel are likely to differ at the time this study is released. 29 Capacity Factor (CF) refers to the percentage of the rated capacity of the power plant used for 8,760 hours (i.e., one year). Mathematically,

100hours 8,760 W)capacity(k plant

(kWh) productionenergy CF ×

×=



operate as “baseload”, “intermediate” or “peaking” plants (i.e., which will operate at high, medium or low capacity factor) could be determined/selected.

Table 2.13: Cost Comparison of Power Plants

Type of Power Plant Typical

Economic Life, years

Investment Cost, $/kWa

Annual Fixed O & M Cost,

$/kWa

Fuel Cost, $/MWh

Oil-fired steam turbine 30 850 – 1,000 17 – 20 41.04 Oil-fired gas turbine 20 450 - 550 11 – 14 49.93 Oil-fired combined cycle gas turbine 20 700 – 900 14 – 18 32.56

Diesel motors 20 550 – 650 14 – 16 73.10 Pulverized coal-fired power plant 30 1,200 – 1,400 30 – 35 11.40

Fluidized bed coal power plant 30 1,750 – 1,800 44 – 45 9.12

Wind technologies 20 1,000 – 1,250 20 – 25 0 Hydroelectric power plants 50 2,000 – 3,500 40 – 70 0

Fluidized bed combustors (for biomass) 30 1,750 – 1,800 44 – 45 3.53

Geothermal technologies 50 1,150 – 1,500 29 – 38 0 Gas-fired combined cycle gas turbine (for natural gas)

20 700 – 900 14 – 18 36.68

a From “ The Environmental Manual for Power Development”, Deutsche Gessellschaft für technishe, except for Clean Coal Technologies

Considering the availability of the resource and reliability of the technologies, Table 2.14 shows the typical capacity factors based on the investment30, O&M and fuel costs31 of the different power plant technologies. These figures are intended only for relative comparison of the different power plant technologies. These values were used by the UPSL in the cost assessment of the power development plan prepared by DOE and in preparing an alternative plan for simulating the fuel-switching scenario for the Philippine power sector discussed in the following chapters. Table 2.14 also shows the corresponding levelized cost of generation for each power plant type using the typical capacity factors. These values show that electricity generation from renewable sources, on a life-cycle basis, is competitive in comparison with conventional fossil fuel-based generation. It should be emphasized that the actual capacity factors that may be achieved in operation may not fall on the values given in Table 2.14 to satisfy the minimum off-take character of the IPP contracts. They are however useful in evaluating and developing energy plans. 30 Investment costs used in this study do not include site preparation, transmission line and transformer costs. 31 Fuel costs for oil, coal and natural gas do not include import duties. Geothermal steam and biomass fuel costs also vary, depending on the site/environment. Furthermore, the prices of fuel are likely to differ by the time this study is released.



Table 2.14: Typical Capacity Factors of Power Plants and Levelized Generation

Costs32

Levelized Generation Cost Power Plant Type Capacity Factor (%) $/kWh PhP/kWh

Geothermal 88 0.0193 1.0602 Coal (Pulverized coal plant) 82 0.0405 2.2282 Coal (Pulverized coal plant) 82 0.0405 2.2282 Hydro 57 0.0494 2.7153 Oil-fired steam turbine 54 0.1059 5.8236 Natural gas combined cycle 54 0.0794 4.3644 Oil-fired gas turbine 31 0.1101 6.0557 Wind Without ancillary services 30 0.0512 2.8174 With ancillary services 30 0.0625 3.4376 Diesel33 9 0.2277 12.5219

32 A discount rate of 12% was used to derive levelized generation costs. Actual industry discount rates may be higher depending on the following factors: required equity return, market risks, regulatory risks, country risks and availability of financing. 33 The low capacity factor computed for diesel plant is 9%, meaning it will be used for load following and/or peaking applications.



2.4 Environmental Externalities In the previous section, costs associated directly with the production of electricity from various technologies and resources were discussed. These costs are what normally dictate an energy planner’s choice of which power generation technology to use. Power generation technologies, however, are directly associated with effects that affect people’s welfare. These effects are called externalities. By definition, an externality is “an unpriced benefit or cost directly bestowed or imposed upon one agent by the actions of another agent”34. In the case of electricity generation, externalities include various pollutants that cause damage to receptors such as human health, natural ecosystems, crops and property. According to Koomey and Krause (1997), “Pollution represents an external cost because damages associated with it are borne by society as a whole and are not reflected in market transactions.” A number of studies have attempted to put a cost on the various externalities caused by power generation using the abatement cost or the damage cost approach. The abatement cost approach uses the cost of pollution control as a proxy to the true externality cost35. On the other hand, the damage cost approach puts a value on the damages that may be directly attributable to a particular pollutant. Studies vary in their estimation of externality costs because of a number of factors, including site specificity (e.g., geographical and climatological conditions), population density, emissions reduction policy, scope of analysis, among others. Table 2.15 shows the value of various air emissions in California, currently a leader in externality policy, as determined by the California Energy Commission using both the abatement and damage cost approaches. From the values given, a number of things could be noted. First, there is a pronounced difference between damage cost and pollutant cost values. Except for particulate matter, abatement costs are normally higher that damage cost estimates. Second, externality costs differ among different districts. In this study, abatement cost values for the North Coast of California, which has the lowest abatement costs among the districts, were used to compute for the cost of externalities of the different scenarios. Table 2.16 shows the factors used in this study to arrive at the CO2 emissions of each type of power plant in tonne CO2/GWh. The values were calculated based on the generic data recommended for power development analysis. It should be noted that even though coal seem to have a lower CO2 emission level than conventional power plant types, its contribution to total greenhouse emissions is more substantial since coal plants are normally used for base load generation while oil based plants are mostly used for load following and peaking applications. Other air pollutant emissions for different power plants are listed in Table 2.17.

34 T. Sundqvist and P. Söderholm, “Pricing Power Generation Externalities: Ethical Limits and Implications for Social Choice” (one of the six self-contained papers included in Sundqvist’s Doctoral Thesis, “Power Generation Choice in the Presence of Environmental Externalities, Luleá University of Technology, 2002), p. 3. 35 Jonathan Koomey and Florentin Krause, “Introduction to Environmental Externality Costs”, as published in the CRC Handbook on Energy Efficiency (1997).



Table 2.15: Value of Air Emissions Reductions in California36 ($/pound of pollutant)

District

South Coast Ventura County Bay Area San Diego San Joaquin

Valley Sacramento

Valley North Coast Pollutant

DC AC DC AC DC AC DC AC DC AC DC AC DC AC

SOx 4.88 13.02 0.99 4.08 2.28 5.85 1.76 2.37 0.99 11.71 0.99 5.39 0.99 1.98

NOx 9.52 17.4 1.08 10.85 4.83 6.84 3.66 12.03 4.26 5.98 4.01 6.01 0.53 3.96

CO 0.00 6.12 0.00 I 0.00 1.45 0.00 0.72 0.00 2.10 0.00 3.30 0.00 I

ROG 4.55 12.43 0.18 13.88 0.07 6.71 0.07 11.51 2.45 5.98 2.72 6.01 0.31 2.31

PM 31.32 3.75 16.05 1.18 15.78 1.71 9.35 0.66 2.47 3.42 1.44 1.85 0.37 0.59 DC – damage cost; AC – abatement cost; I – internalized; SOx – Sulfur Oxide; NOx – Nitrogen Oxide; CO – Carbon Monoxide; ROG – Reactive organic gases; and PM – particulate matter

Table 2.16: Carbon Dioxide Emissions of Different Power Plant Types

Power Plant Type tonne CO2/GWh

Geothermal 45.40 Pulverized Coal 726.99 Oil Combined Cycle 565.83 Natural Gas Combined Cycle 441.82 Oil Steam Turbine 713.10 Oil Gas Turbine 867.61 Diesel 763.04

Source: Computed from data give in “The GHG Indicator: UNEP Guidelines for Calculating Greenhouse Gas Emissions for Business and Non-Commercial Organizations, except for geothermal which was computed from DOE data

Table 2.17: Emissions Factors for Various Power Plants

(tonne/GWh)

Environmental Emissions Plant Type SO2 NOx CO CH4 NMVOC N2O Particulates

Coal 7.40 4.20 0.88 0.53 0.02 0.02 0.03 Oil combined cycle 7.65 2.02 0.34 1.01 0.03 0.06 0.02 Natural gas combined cycle

0.01 1.64 0.06 0.66 0.04 0.08 0.02

Oil steam turbine 9.75 2.00 0.72 0.57 0.03 0.03 0.03 Oil gas turbine 11.74 3.10 0.52 1.55 0.05 0.10 0.04 Diesel 2.03 8.73 1.75 0.87 0.05 0.05 0.02 Source: The Environmental Manual for Power Development, Deutsche Gessellschaft für technishe

36 Lifted from “What Causes the Disparity of Electricity Externality Estimates?”, one of the six self-contained papers included in Sundqvist’s Doctoral Thesis, “Power Generation Choice in the Presence of Environmental Externalities, Luleá University of Technology, 2002), p. 10. Sundqvist cites the 1992 Electricity Report by the California Energy Commission as the source of these data.



2.5 Mitigation Options As a result of the technology and resource analyses made by the UPSL, the following clean energy options were used for the generation of alternative planning options discussed in Chapter 4 of this report:

• Wind power

• Hydro

• Biomass (bagasse)

• Geothermal power

• Natural gas For biomass, only bagasse was considered as option. The UPSL did not consider other forms (rice hull, wood wastes, coconut residues) in the generation of alternative options for grid-connected electricity generation as they are still associated with problems such as that of sourcing, collection, storage and competing uses. On the use of natural gas, it was assumed that infrastructure would be built to support an expanding natural gas industry.



3 HISTORICAL PERFORMANCE OF THE PHILIPPINE POWER SECTOR In the following sections is an assessment of the performance of the Philippine power sector from the period beginning 1991 to 2001. Performance is assessed in terms of reliability, environmental emissions, and cost. Data for the historical performance of the Philippine Power Sector is given in Appendix B. 3.1 Historical Energy Demand and Installed Generating Capacity The Philippines electricity consumption posted a moderate growth rate of 8.3% annually from 1991 to 2001 as shown in Table 3.1. The industrial and residential sectors, with 31% and 29% share respectively, are the biggest users of electricity (Figure 3.1). It should be noted however, that the industrial sector demand grew only by 5.5% while that of the residential sector grew by 11.7% annually for the 11-year period. Significant also was the growth in the consumption of the commercial sector, whose demand grew by 108% from 1991 to 2001, or at an average annual growth rate of 7.6%. Both the economic performance and population growth remain as the main factors driving the consumption pattern of energy of the country. As shown in Figure 3.2, the gross domestic product and the population growth from 1991 to 2001 demonstrate a strong correlation with the consumption of electricity.

Table 3.1: Energy Consumption by Sector, 1991-2001 (GWh)

SECTOR 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Residential 6,249 6,053 6,368 7,282 8,223 9,150 10,477 11,936 11,875 12,894 13,547

Commercial 4,847 4,910 4,725 5,865 6,353 7,072 8,013 8,725 8,901 9,512 10,098

Industrial 9,339 8,859 9,395 10,684 10,950 11,851 12,531 12,543 12,444 13,191 14,452

Others 952 823 721 762 1,067 1,167 1,267 934 921 957 1,042

Own Use 1,086 1,154 1,132 1,132 1,226 1,340 1,471 1,590 1,536 2,390 2,196

Losses 3,176 4,071 4,238 4,734 5,735 6,128 6,037 5,849 5,754 6,345 5,713

Total 25,649 25,870 26,579 30,459 33,554 36,708 39,797 41,578 41,432 45,290 47,049

Geographically, the energy demand in the country was distributed among the three (3) main islands of Luzon, Visayas and Mindanao as shown in Figure 3.3. Bulk of the energy demand and consequently the generation comes from the main island of Luzon. In 2001 for example, the Luzon Grid consumed 36,184 GWh of the total 47,049 GWh energy generation which represents 77% of the requirements of the country. Visayas and Mindanao share the balance energy almost equally. Figure 3.4 shows system peak demand of the power supply system from 1991 to 2001 for the Luzon, Visayas and Mindanao grids, and the whole of the Philippines. The system peak for the whole Philippines reached 7,682 MW in 2001. This is almost twice of the 4,081 MW peak demand in 1991. With most of the industrial and commercial activities centered in Luzon, it also had the highest peak demand (5,835 MW in 2001). Visayas and Mindanao lag far behind with only 893 and 954 MW peak demand, respectively.



0

20000

40000

60000

80000

100000

120000

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

year

GWH /GDP(x10M)

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

POP(x1000)

Electricity (GWH) GDP (BPhP) Population (in million)

Figure 3.1: Electricity Consumption by Sector, 2001

Figure 3.2: Electricity Consumption, Gross Domestic Product

and Population, 1991-2001 In order to meet the growing demand for electricity, the installed generating capacity in the country doubled from 6,789 MW in 1991 to 13,402 MW in 2001 (Figure 3.5) This corresponds to the growth in demand that also doubled in the same period.

Residential29%

Commercial21%

Industrial31%

Others2%

Utilities Own Use5%

Power Losses12%



Figure 3.3: Electricity Generation by Grid, 1991-2001

(GWh)

Figure 3.4: System Peak by Grid, 1991-2001

(MW)

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

MW

Luzon Visayas Mindanao Philippines

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

GW

H

Luzon Visayas Mindanao Philippines



Figure 3.5: Total Installed Generating Capacity by Source, 1991-2001

(MW) 3.2 Historical Reliability Performance The historical data for the system peak demand and installed generating capacity indicate that the generating facilities in the early 1990’s were performing very badly from the point of view of reliability. It may be recalled that the Philippines experienced a power crisis that started in the late 1980’s and persisted in the mid 1990’s that almost crippled the national economy due to supply deficiency. There was not enough generating capacity. Hence, the National Power Corporation has to resort to rotating “brownouts”. Today, people complain of high cost of electricity allegedly due to over supply as there is “too much” installed generating capacity. To analyze further the generating capacity vis-à-vis the system peak, Table 3.2 presents the reserve margin of the power system from 1991 to 2001. In other countries such as the U.S.A., the generating capacity reliability criteria of one day per ten years (1 day/10 year) of Loss-of-Load Probability (LOLP) translates to about 20% reserve margin. This criterion is considered high but is needed to support their industries. In developing countries, the reliability criterion is very much lower compared to that in developed countries. In the Philippines, the National Power Corporation since the power crisis has adopted 1day/year LOLP. The reserve margin based on dependable capacity shows that there is indeed a large excess generating capacity in the Philippines. This validates the clamor of the people regarding high electricity rates which is due to oversupply since most of the generating facilities are operating under the take-or-pay contract with NPC and other distribution utilities.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

MW

Oil-Based Coal Natural Gas Geothermal Hydro



It can be concluded, therefore, that the generating capacity of the power system in the Philippines can be considered highly reliable. The interruptions that the country has been experiencing can be attributed to the unreliable transmission and distribution systems.

Table 3.2: Reserve Margin, 1991-2001 (%)

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 Peak (MW)

4,081 4,296 4,687 4,808 5,291 5,816 6,352 6,666 6,908 7,400 7,682

Installed Capacity (MW)

6,789 6,949 8,014 9,212 9,732 11,193 11,762 11,931 12,431 13,185 13,402

Percentage Reserve Margin (installed)

66.36 61.76 70.98 91.60 83.93 92.45 85.17 78.99 79.96 78.18 74.46

Dependable Capacity (MW)

8,621 7,450 9,497 11,363 11,209

Percentage Reserve Margin (dependable)

35.72 11.76 37.48 53.55 45.91

3.3 Historical Environmental Performance Another way of evaluating the performance of the power sector is in terms of the gases and particulates that are emitted in the air by the generating plants. This part of the study has quantified the environmental emissions of the power plants in the country. The environmental performance of the Philippine power sector from 1991 to 2001 is summarized in Table 3.3. A complete list of emissions for each year from 1991 to 2001 is provided in Appendix B. The CO2 emissions increased by 74 percent while the rest of the air emissions increased by 10 to 169 percent. Table 3.3. Historical Environmental Emissions for the Philippine Power Sector

(tonne)

Environmental Emissions 1991 Level 2001 Level % Increase

CO2 10,580,233 18,411,762 74 SO2 115,725 189,729 64 NOx 58,726 146,807 150 CO 16,124 20,796 29 CH4 587 904 54 NMVOC 975 1,075 10 N2O 415 842 103 Particulates 10,989 29,611 169



For the CO2 emissions, Figure 3.6 shows that the coal power plants are the major contributors in greenhouse gases. Its contribution increased almost ten times from 1,082,279 tons in 1991 to 10,471,222 tons in 2001. The CO2 emissions however from oil-based power plants decreased by 21 percent from its level of 9,236,541 tons in 1991 to 7,338,665 tons in 2001. The net increase in CO2 due to the changes in oil and coal is 74%. In order to analyze the factors that brought about the environmental performance of the power sector, it is necessary to look at the power development as measured by the energy mix. The energy mix indicates the intensity of contribution of renewable energy resources as fuel for power generation. Figures 3.7 and 3.8 show that non-renewable energy have remained greatly dominant over renewable energy as source of fuel for power generation. Figure 3.9 shows how carbon dioxide emissions varied with the energy mix within the 1991 to 2001 period. Note from this figure how much the CO2 emissions decreased and increased with the generation from oil-based and coal power plants.

Figure 3.6: Carbon Dioxide Emissions by Fuel Type, 1991-2001

(tonne) The share of non-renewable sources in the energy mix even increased from 57.49% in 1991 to 62.71% in 2001. The share of renewable sources, on the other hand, decreased from 42.51% to 37.29% during the same period. Over the period considered, the percentage share of oil-based power generation declined by 58%. However, the share of coal-based generation increased by 427%. This scenario allowed the continued dominance of non-renewable fuels.

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

18,000,000

20,000,000

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

tonn

e C

O2

Oil-based Coal Natural Gas Geothermal



In addition, renewable hydro and geothermal sources share decreased by 25% and 1%, respectively over the same period. Clearly, the shift is only towards use of coal, which is a cheaper fuel, and not towards use of renewable resources. This explains why the emissions of the power sector almost doubled in only 11 years. One thing to note, however, is the emerging use of natural gas, which despite being non-renewable is considered cleaner fuel for power generation. With 1,063 MW of natural gas plant already installed in 2001 and another 1,700 MW installed by 2002, more energy generated from this source can be expected in the coming years. (Chapters 4 and 5 discuss the scenarios under the DOE Philippine Energy Plan and UPSL alternative scenarios, respectively, for 2003 to 2012). Combining the generation from natural gas in the year 2001 with that of the renewable sources, the percent share of cleaner fuels increased a bit from 37% (renewable only) to 39% (renewable plus natural gas). This leaves the percent share of non-renewable (coal and oil) to 61%.

Figure 3.7: Energy Mix, 1991-2001

(%)

0%

20%

40%

60%

80%

100%

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Oil-Based Coal Natural Gas Geothermal Hydro



Figure 3.8: Share of Coal and Oil-Based vs. Renewable Energy and Natural Gas

in the Energy Mix, 1999-2001 (%)

Figure 3.9: Energy Mix and Carbon Dioxide Emissions, 1991-2001

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Coal and Oil-Based Renewable and Natural Gas

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

GW

h

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

18,000,000

20,000,000

ton

ne

CO

2

Oil-based Coal Natural Gas Geothermal Hydro CO2



3.4 Cost of Electricity This study also assessed the power development in the Philippines by analyzing the cost of electricity. It was noted that the average rates of NPC is for its bundled generation and transmission services. In addition, the average rates consist of the actual operating expenses and the financing charges of NPC. For purposes of this study, the rates of NPC were unbundled into 76% and 24% for generation and transmission, respectively. The average rates and the estimated unbundled generation and transmission rates of NPC from 1995 to 2001 are shown in Table 3.4.

Table 3.4: NPC Average Electricity Rates, 1991-2001 (PhP/kWh)

Year 1995 1996 1997 1998 1999 2000 2001 Luzon 1.85 2.08 2.29 2.77 2.84 3.34 3.01 Visayas 1.93 2.02 2.15 2.44 2.52 3.23 3.08 Mindanao 1.28 1.25 1.25 1.68 1.67 1.92 2.02 Philippines 1.77 1.96 2.14 2.58 2.65 3.12 2.90 Generation 1.35 1.49 1.63 1.96 2.02 2.37 2.20 Transmission 0.43 0.47 0.52 0.62 0.64 0.75 0.70 Note: Generation and Transmission Rates assumed 76% and 24% of the average rate, respectively

The average rates of NPC increased annually from 1991 to 2001, except for the year 2001 when R.A. 9136 (Electric Power Industry Reform Act) was enacted. Interestingly, the law has mandates to reduce the rates of electricity in the Philippines. The increase in rates is attributed to the economic performance of the country as measured the exchange rates and allegedly due to the take-or-pay contracts of NPC with Independent Power Producers (IPPs). Comparing the average rate of NPC with that paid by the consumers, which range from PhP 4.00 to PhP 6.00 per kWh, there is difference of PhP 1.00 to PhP 3.00 per kWh. This considerable difference can be attributed to the cost of distribution and to the IPP’s that sell electricity directly to the distributors. Table 2.5 show the production cost of NPC and IPPs, respectively, for the years 1995 to 2001 by fuel type. IPP costs were always higher than NPC rates. It is worthwhile to note that with the existence of the Non-NPC IPP’s (permitted to operate through Executive Order 215), particularly that of the electricity distributors like MERALCO, many power plants were installed without the benefit of proper coordination through the centralized planning of the NPC or the government. As a result, many power plants were installed in excess of what was actually needed, and the cost of which has to be paid off through the Purchased Power Adjustment (PPA).



Table 3.5: NPC and IPP Production Cost at 1990 Constant Prices (US$/kWh)*

Oil-based Hydro Geothermal Coal

Year NPC IPP NPC IPP NPC IPP NPC IPP

1995 0.0254 0.0386 0.0125 0.0360 0.0294 --- 0.0284 --- 1996 0.0281 0.0428 0.0109 0.0326 0.0252 0.0366 0.0303 0.0431 1997 0.0276 0.0450 0.0111 0.0284 0.0230 0.0349 0.0244 0.0358 1998 0.0212 0.0369 0.0092 0.0276 0.0198 0.0331 0.0150 0.0265 1999 0.0267 0.0538 0.0067 0.0270 0.0195 0.0329 0.0137 0.0236 2000 0.0394 0.0662 0.0047 0.0367 0.0167 0.0281 0.0110 0.0232 2001 0.0302 0.0462 0.0038 0.0683 0.0177 0.0233 0.0100 0.0203

* Lifted from “Renewable Energy Prospects for Supplying Electricity in the Deregulated Market in the Philippines” by J. N. Estiva and M. G. Guzman



4 SCENARIOS UNDER THE PHILIPPINE ENERGY PLAN FOR 2003 TO 2012 This section discusses the current national energy planning process and DOE’s energy generation plans for 2003 to 2012. 37 4.1 National Energy Planning Process In coming up with an energy plan, the national government through the DOE employs a top-down approach, in which all the main inputs and arguments to the plan are based on the national macroeconomic and the energy sector goals. Hinging electricity demand on the country’s economic activity, the DOE projects the national and regional energy and power requirements based on the forecast of the National Economic Development Authority’s (NEDA) Gross Domestic Product (GDP) and Gross Regional Domestic Product (GRDP). These projections are then used by the National Transmission Corporation (TRANSCO) to plan the transmission requirements of the country. Distribution utilities (DU’s), such as MERALCO and the electric cooperatives (EC’s), on the other hand, make their own demand and expansion plans based land-use, historical sales, and projected increase in customers. As illustrated in Figure 4.1, the plans formulated by the DOE, TRANSO, DU’s and EC’s, serve as primary inputs to the Power Development Plan (PDP), which in turn, is a critical part of the Philippine Energy Plan. In the PDP, where the power plant type and capacity additions and retirement are indicated, the “least cost” criterion is the primary factor in determining the power plant projects and line-up for the planning period. Interestingly, as shown in the above figure, renewable energy and other energy resources project planning do not directly form part of the PDP. Small renewable energy projects, in particular, are considered through the electrification program only. Note that the program pertains to the rural electrification program, which aims to bring electricity to the un-electrified areas. With the existing approach, it is only until the DOE puts in specific goals for the renewable energy sector can it be factored in to the PDP. Relating this type of approach to the historical performance (as discussed in the previous section) of the renewable energy, it is evident that the non-integration of the renewable energy resources projects in the PDP could limit the development of renewable energy as an important alternative power resource. The current top-down approach, while it is very effective in supporting the national goals, allows limited public and local government participation that espouses their interests, particularly in local environmental protection and power development. 37 For the scenarios in this chapter as well as in Chapter 5, power plant costs (investment, O&M and fuel) indicated in Tables 2.13 and 2.14 in Chapter 2 were used. Costs computed are for comparative purposes only and may not be equal to the actual costs. A discount rate of 12 percent was used. Actual industry discount rates may be higher depending on the following: required equity return, market risks, regulatory risks, country risks and availability of financing



Figure 4.1: National Energy Planning Process

4.2 Gross Domestic Product Projections In the Philippine Energy Plan for the period 2003-2012, the DOE uses two economic scenarios from which to forecast future energy requirement of the country. These two scenarios are based on the NEDA’s low and high projections of the country’s GDP and are aptly named the Low GDP and High GDP scenarios. In this report, the low GDP scenario will be referred to as the Low Economic Growth Scenario (LEGS) and the high GDP scenario as the High Economic Growth Scenario (HEGS). The GDP projections for the two scenarios, as well as the its corresponding growth rates are shown in Table 4.1.

Table 4.1: Low and High GDP Forecasts for 2003 to 2012

Low GDP High GDP Year GDP

(billion PhP) Growth Rate

(%) GDP

(billion PhP) Growth Rate

(%)

2003 1,079.95 4.96 1,091.11 5.51 2004 1,138.70 5.44 1,156.69 6.01 2005 1,203.62 5.70 1,229.48 6.29 2006 1,276.27 6.04 1,311.09 6.64 2007 1,343.01 5.23 1,387.10 5.80 2008 1,413.24 5.23 1,467.51 5.80 2009 1,487.14 5.23 1,552.59 5.80 2010 1,564.91 5.23 1,642.60 5.80 2011 1,646.74 5.23 1,737.82 5.80 2010 1,732.85 5.23 1,838.57 5.80

Note: GDP values for 2003 to 2006 are actual NEDA forecasts. For 2007 to 2012, the DOE estimated GDP values based on the average growth rates forecasted by NEDA. Source: Philippine Energy Plan 2003-2012

Generation Planning

(DOE)

Transmission Planning

(TRANSCO)

Distribution Planning

(PUs & Ecs)

Power Development Program

Other Energy Sectors PlanningNRE, Oil, Coal, etc.

Philippine Energy Plan

Electrification Program

SmallRenewable

EnergyProjects

Generation Planning

(DOE)

Transmission Planning

(TRANSCO)

Distribution Planning

(PUs & Ecs)

Power Development Program

Other Energy Sectors PlanningNRE, Oil, Coal, etc.

Philippine Energy Plan

Electrification Program

SmallRenewable

EnergyProjects

Top-Down Approach



In the PEP, the DOE formulates generation plans for the two economic scenarios. These plans will be discussed in the following sections. In addition, the UPSL computed the amount of emissions that would be generated and the cost of electricity generation38 for both plans of the DOE for 2003 to 2012. 4.3 DOE Plan for the Low Economic Growth Scenario Energy Generation Figure 4.2 shows the energy generation projected by the DOE that would meet the future energy requirements in 2003 to 201239. For this period, energy generation is projected to increase at an average rate of 7.57% annually and 93% over the entire period. From 55,142 GWh in 2003, generation would almost double to 106,430 GWh in 2012.

Figure 4.2: Generation under the Low Economic Growth Scenario

38 Generation costs were calculated using generic data for investment, O & M and fuel costs. Costs calculated do not include ancillary, transmission and distribution costs. 39 Details of the calculations made for this section are provided in Appendix C.

0

20000

40000

60000

80000

100000

120000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

GWh



Installed Generating Capacity Total installed capacity for 2003 is 14,632 GW and will increase to 20,706 MW by 2012. As shown in Figure 4.3, the increase in demand requirement will be met mostly by increases in oil-based and coal plant capacities of 1,775 MW and 3,500 MW, respectively40. The increase in the share of renewable energy generating capacity, amounting to 800 MW, will be due to a 795 MW hydro capacity, 65 MW wind capacity and a 40 MW geothermal capacity additions. No additional capacity addition for natural gas is expected in the period. These figures just show the continued preference on the use coal over natural gas, which is a more expensive fuel, and renewable energy plants, which are more capital intensive. Notably, this scenario is very similar to how the Philippine power sector performed historically. Reserve Margin and Reliability Table 4.2 summarizes the results of the UPSL’s calculation for the DOE’s plan for the LEGS. The table also computes the capacity that would be required if the percentage reserve margin was kept at 20%. Notable are the considerably high reserve margins for 2003 to 2009. These high reserve margins would translate to higher electricity prices during the period.

Figure 4.3: DOE Plan for Installed Capacity for the Low Economic Growth Scenario

40 In the PEP, committed and indicative capacity additions for each year in the planning period are given. For indicative plant additions, the UPSL assumed that indicative base load capacity will be coal plants while intermediate and peaking plants corresponds to oil-based plants.

0

5,000

10,000

15,000

20,000

25,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

MW

Oil-based Coal Natural Gas Geothermal Hydro Wind Demand (MW)



Table 4.2: Percentage Reserve Margin for the DOE Plan

for the Low Economic Growth Scenario, 2003-2012

Year Peak Demand (MW)


Percentage Reserve Margin

(%)

Capacity Required for 20% Reserve

Margin

2003 8,833 14,632 66 10,600 2004 9,519 15,120 59 11,423 2005 10,277 15,615 52 12,332 2006 11,139 15,865 42 13,367 2007 11,997 16,015 33 14,396 2008 12,869 16,565 29 15,443 2009 13,813 17,505 27 16,576 2010 14,814 18,405 24 16,576 2011 15,889 19,756 24 17,777 2012 17,033 20,706 22 20,440

Energy Mix For the LEGS, the PEP expects that for the year 2003, coal, natural gas and oil-based sources will supply 34%, 24% and 5%, respectively, of the total 55,143 GWh generation. Renewable energy sources, particularly geothermal and hydro, will supply 26% and 11%, respectively, of the total generation. A look at the energy mix (Figures 4.4 and 4.5) for the planning period indicates minimal thrust towards more use of renewable energy sources and cleaner fuels. From a share of 37% in 2003, renewable energy’s share decreases to 22% in 2012. Contribution from wind sources stays insignificant for the whole period. Clean fuels’ (renewable energy and natural gas) share in the energy mix decreases from 61% to 41% by 2012. The combined contribution of coal and oil to the energy mix, on the other hand will increase to 59% in 2012 to from a value of 38% in 2003. Fuel Consumption To meet demand and energy requirements, this scenario would require 124.5 million barrels of oil, 91,895,066 tonnes of coal and 1,263 billion cubic feed (BCF) of natural gas for the whole planning period. Of these amounts, 124.5 tonnes of oil and 80,224,393 tonnes of coal would have to be imported41. Imported fuel would cost $4,324 million. The breakdown of the fossil fuel that would be consumed in the LEGS-PEP scenario is shown in Figure 4.6.

41 This assumes that: • local natural gas production can support 3,800 MW capacity of 23,208 GWh energy production

annually, and; • share of imported coal is 87.3% of total consumption, as it was in 2001.



Figure 4.4: Energy Mix for the DOE Plan for the Low Economic Growth

Scenario

Figure 4.5: Coal and Oil-Based vs. Renewable and Natural Gas Energy Mix

for the DOE Plan for the Low Economic Growth Scenario

0%

20%

40%

60%

80%

100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

Oil-based Coal Natural Gas Geothermal Hydro

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Coal and Oil-Based Renewable Energy and Natural Gas



Environmental Emissions and Abatement Costs The environmental emissions resulting from DOE’s generation plan for LEGS are calculated in this report. Total CO2 emissions for the period amounts to 309.3 million tonnes. Table 4.3 shows the values for the years 2003 and 2012 and Figure 4.7 shows the contribution of each type to the CO2 emissions. Appendix C shows the amount of emissions for the whole planning period. As would be expected, the increase in the use of coal would result in an increase in CO2, SOx and other emissions. Coal contributes 55% of the CO2 emissions for the period. Oil-based and natural gas plants contribute 17% and 26% to the CO2 emissions, respectively. Geothermal plants contribute only 2%. Total cost of abatement for this scenario is $ 29,368,137,71642. Generation Cost The present value of the costs calculated for the PEP-LEGS is given below. Table 3.4 lists down the generation costs calculated for each year of the planning period, along with the assumptions used. Average generation cost for the period is PhP 3.1592 per kWh. These generation costs were computed from the values for investment, fuel, and operations and maintenance costs involved in the operation of the different plants to meet demand and energy requirements for the scenario. These do not take into account the effect on the generation cost by deals made with independent power producers.

Investment cost: $ 11,744,391,189 O&M cost: $ 2,707,454,434 Fuel cost: $ 9,376,479,292 Total: $ 23,828,324,916

42 Abatement costs values in this chapter and the chapters that follow were computed using abatement costs for SOx, NOx and particulates for the North Coast of California, as given in Chapter 1.



Figure 4.6: Fossil Fuel Consumption for the DOE Plan for the Low Economic Growth Scenario

Table 4.3: Environmental Emissions for the DOE Plan

for the Low Economic Growth Scenario (tonnes)

Emission Type Year 2003 Year 2012

CO2 18,778,850 46,669,611 SO2 159,289 489,821 NOX 112,712 295,788 CO 21,362 54,323 CH4 282 644

NMVOC 1,581 3,432 N2O 952 2,389

Particulates 19,927 55,647

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000

90,000,000

100,000,000

Oil-based Coal Natural Gas

(tonn

es)

Imported Fuel Indigenous Fuel



Figure 4.7: Carbon Dioxide Emissions for the DOE Plan for the Low Economic Growth Scenario

Table 4.4: Generation Costs for the DOE Plan for the Low Economic Growth Scenario, 2003-2012

Generation Cost Year

$/kWh PhP/kWh* 2003 0.0554 3.0447 2004 0.0564 3.1026

2005 0.0568 3.1229

2006 0.0553 3.0409

2007 0.0553 3.0429

2008 0.0564 3.0997

2009 0.0584 3.2123

2010 0.0592 3.2548

2011 0.0601 3.3072

2012 0.0612 3.3636

Average 0.0574 3.1592 Assumptions: Discount rate 12% Inflation rate 3% Fuel escalation rate 2% * $1 = PhP 55

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

45,000,000

50,000,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

tonn

e C

O2




4.4 DOE Plan for the High Economic Growth Scenario Energy Generation In the high economic growth scenario, generation is expected to increase from 55,556 GWh in 2003 to 118,470 GWh in 2012, increasing more than 200 percent within the ten-year planning period. Figure 4.8 shows the expected generation under the HEGS.

Figure 4.8: Generation under the High Economic Growth Scenario Installed Generating Capacity Installed generating capacity would increase from 14,632 MW in 2003 to 22,756 MW in 2012, corresponding to a 56% increase within the ten-year planning period. A large part of this increase is due to the addition of coal plants. Figure 4.9 shows how the installed generating capacity would change from 2003 to 2012. Reserve Margin and Reliability Similar to LEGS, the percentage reserve margin in the HEGS is considerably high, with a minimum value of 26% and a maximum of 65%. Table 4.5 lists down the percentage reserve margins for the PEP Plan for the HEGS.

0

20000

40000

60000

80000

100000

120000

140000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

GWh



Figure 4.9: DOE Plan for Installed Capacity

for the High Economic Growth Scenario

Table 4.5: Percentage Reserve Margin for the DOE Plan for the High Economic Growth Scenario, 2003-2012

Year Peak Demand (MW)


Percentage Reserve Margin

(%)

Capacity Required for 20% Reserve

Margin

2003 8,883 14,632 65 10,660 2004 9,633 15,120 57 11,560 2005 10,469 15,615 49 12,563 2006 11,424 15,865 39 13,709 2007 12,378 16,065 30 14,854 2008 13,359 16,765 25 16,031 2009 14,423 18,155 26 17,308 2010 15,562 20,005 29 18,674 2011 16,790 21,806 30 20,148 2012 18,106 22,756 26 21,727

0

5,000

10,000

15,000

20,000

25,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

MW

Oil-based Coal Natural Gas Geothermal Hydro Wind Demand (MW)



Energy Mix From Figures 4.10 and 4.11, it is quite evident that dependence on non-renewable energy for power generation remains strong. While the share of renewable energy declines to 20% by 2012 from 37% in 2003, the share of non-renewable energy increases to 80%. Much of the increase in the share of non-renewable energy may be attributed to oil whose shares increase from 5% to 17%, and natural gas whose contribution ranges from 24% to 17% for the period considered. Coal share remains very significant at 47% in 2012.

Figure 4.10: Energy Mix for the DOE Plan for the High Economic Growth Scenario

Fuel Consumption To meet demand and energy requirements, this scenario would require 184.5 million barrels of oil, 98,322,120 tonnes of coal and 1,272 BCF of natural gas for the whole planning period. Of these amounts, 184.5 million barrels of oil 85,835,211 tonnes of coal would have to be imported. Total cost of imported fuel is $5,127 million. The breakdown of fossil fuels that will be used in the HEGS-PEP scenario is shown in Figure 4.12.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

Oil-based Coal Natural Gas Geothermal Hydro Wind



Figure 4.11: Share of Renewable and Non-Renewable Energy in the Energy Mix

for the DOE Plan for the High Economic Growth Scenario

Figure 4.12: Fossil Fuel Consumption for the DOE Plan


-

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000

90,000,000

100,000,000


(tonn

es)


0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Non-Renewable Energy (w/o Nat Gas) Renewable Energy with Nat Gas



Environmental Emissions and Abatement Costs With the continuous decline in the share of renewable energy in the energy mix from 37% to a mere 20% within the planning period, greenhouse has emissions is to further soar. Total CO2 emissions for the period is 347.2 million tonnes. An estimate of the environmental emissions is provided in Table 4.6. Figure 4.13 illustrates the contribution of each energy source to CO2 emissions resulting from the DOE plan for the HEGS. Total abatement cost for the HEG-PEP Scenario is $32,995,165,568.

Table 4.6: Environmental Emissions for the DOE Plan for the High Economic Growth Scenario

(tonnes)

Emission Type Year 2003 Year 2012 CO2 19,050,843 565,294,829 SOx 167,211 631,317 NOx 111,064 326,945 CO 21,751 70,610 CH4 283 778

NMVOC 1,599 4,409 N2O 970 2,820

Particulates 19,677 61,132

Generation Cost The PEP-HEGS Scenario will require the following costs:

Investment cost: $ 12,059,022,913 O&M cost: $ 2,764,680,225 Fuel cost: $ 10,236,076,758 Total: $ 25,059,779,896

Based on the installed capacities and energy generation indicated in the PEP for the HEGS, the UPSL obtained the following shown in Table 4.7 for energy generation cost for 2003 to 2012.



Figure 4.13: Carbon Dioxide Emissions for the DOE Plan


Table 4.7: Generation Costs for the DOE Plan for the High Economic Growth Scenario, 2003-2012

Generation Cost Year $/kWh PhP/kWh*

2003 0.0549 3.0175 2004 0.0555 3.0545 2005 0.0557 3.0640 2006 0.0542 2.9810 2007 0.0543 2.9853 2008 0.0553 3.0392 2009 0.0582 3.2021 2010 0.0598 3.2889 2011 0.0612 3.3646 2012 0.0635 3.4908

Average 0.0573 3.1488 Assumptions: Discount rate 12% Inflation rate 3% Fuel escalation rate 2% * $1 = PhP 55

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

tonn

e C

O2




5 CLEAN POWER DEVELOPMENT OPTIONS Using the mitigation options identified in Section 2, four alternative strategies were used to develop mitigation scenarios that meet the demand and energy requirements of the Low Economic Growth Scenario and the High Economic Growth Scenario. These strategies are the following: • Moderate Clean Power Development (CCPD) Option

In this option, capacity addition and utilization of renewable energy (geothermal, biomass, wind and hydro power) and natural gas plants are given priority over that of non-renewable plants for power generation. Total installed capacity of wind power plants is allowed to reach a maximum of 5% of the peak demand.

• Aggressive Clean Power Development Option

For this option, the strategy is to utilize all the practical renewable energy resources where possible while keeping the appropriate reserve margins and diversity of resources.

It is assumed in these options that the local natural gas industry will be able to supply fuel for up to 3,800MW43 (equivalent to 23,208 GWh) natural gas power plants for the next twenty years. The additional requirement will be supplemented by imports from the neighboring Asian countries and other natural gas producers until new local resources are developed. For all the options, the percentage installed reserve margin for the years 2008 onwards is kept as close as possible to the corresponding PEP reserve margins for comparison. Note, however, that these reserve margins do not take into account the ancillary diesel engines, which will serve as back up to the wind power plants. The capital costs of the ancillary diesel engines are, on the other hand, considered in the investment cost of the plants. UPSL capacity additions start in 2008 assuming a five-year lead-time for the planning and commissioning of the additional power plants. The 2003 to 2007 capacity additions were based solely on the PEP list of committed projects. The projected generation for each fuel type for 2003 to 2007 is, likewise, lifted from the PEP. The annual installed capacities per fuel type for each grid are provided in Appendix D. The candidate and practical renewable resources, which were used as basis for the above options, are given Appendix A. The following sections discuss the resulting energy mix, fuel usage, and emissions for the abovementioned options.

43 Natural Gas Plan, DOE



5.1 LEGS-MCPD Scenario In this scenario, the Moderate Clean Power Development option is applied to the Low Economic Growth Scenario. Details of this scenario is given in Appendix D. Installed Capacity As shown in Figure 5.1, natural gas capacity would continue to increase until the end of the planning period. Also, renewable energy plant installed capacity is increased by 95% from 4,450 MW in 2003 to 8,685 MW in 2012. By 2012, natural gas and renewable energy plant capacities would amount to 69% of the total installed capacity. Reserve Margin The 2008 to 2012 installed capacity reserve margins for the LEGS-MCPD option for Luzon and Visayas fall within the LEGS-PEP range of 22% to 29%. For Mindanao, however, the reserve margin is quite higher at 42% to 48%. This is because more power plants are required to meet Mindanao’s energy demand, which cannot be addressed with the low dependable capacity of its existing plants. Note also that wind power plants, which were used in this option to address the additional power and energy demand, have lower capacity factors compared to coal power plants, which were used in the PEP scenarios. Energy Mix The share of renewable energy for the LEGS-MCPD option would increase by 10% from the period 2003 to 2012. The total share of clean energy in the energy mix increases by 18% due the 148% boost in energy generation from natural gas power plants. The share of coal and oil in the mix would reduce by about 28% at the end of the period. The energy mix and share of clean energy for the option are shown in Figure 5.2 and 5.3, respectively. Fuel Consumption To meet demand and energy requirements, this scenario would require 58.8 million barrels of oil, 73,945,279 tonnes of coal and 1,502.4 BCF of natural gas for the whole planning period. Of these amounts, 58.8 million barrels of oil, 64,554,228 tonnes of coal and 154.9 BCF of natural gas would have to be imported. This is shown in Figure 5.4. Total cost of fuel that need to be imported for this scenario is $ 3,060 million.



Figure 5.1: Installed Generating Capacity for the LEGS-MCPD Scenario Environmental Emissions and Abatement Cost As would be expected, GHG emissions from the LEGS-MCPD are much lower than that from the LEGS-PEP. Total CO2 emissions for the LEGS-MCPD Scenario is 264.7 million tonnes, achieving net reduction of 44.6 million tonnes of CO2 as compared to the LEGS-PEP. Figure 5.5 illustrates the CO2 emissions calculated from this option. Total cost of abatement of other emissions for this option is $23,202 million. The LEGS-PEP abatement cost is $6,166 million higher than that of the LEGS-MCPD. Generation Cost For this LEGS-MCPD, computed cost values for the planning period are as follows:

Investment cost: $ 12,113,969,254 O&M cost: $ 2,755,507,508 Fuel cost: $ 8,723,479,053 Total: $ 23,592,955,815 Average generation cost: $ 0.0568 or PhP 3.1235

The LEGS-MCPD will achieve a net savings of $ 236 million as compared with the LEGS-PEP.

0

5,000

10,000

15,000

20,000

25,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

MW

Oil-based Coal Natural Gas GeothermalHydro Biomass Wind Demand (MW)



Figure 5.2: Energy Mix for the LEGS-MCPD Scenario


for the LEGS-MCPD Scenario

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

Oil-based Coal Natural Gas Geothermal Hydro Biomass Wind

0%

10%

20%

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40%

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60%

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012




Figure 5.4: Fossil Fuel Consumption for the LEGS-MCPD Scenario

Figure 5.5: CO2 Emissions for the LEGS-MCPD Scenario

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012


-

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000


(tonn

es)




5.2 LEGS-ACPD Scenario In this scenario, the Aggressive Clean Power Development Option is applied to the Low Economic Growth Scenario. Installed Capacity In this option, renewable energy capacity is increased from 4,450 MW in 2003 to 11,520 MW in 2012. This 159% increase in renewable capacity is largely attributable to the increase in wind capacity from zero in 2003 to 3,480 MW in 2012 and the further increase in the utilization of geothermal and biomass resources. In this option, wind power plants take 20.40% of the peak demand. Figure 5.6 shows the installed capacities for the LEGS-ACPD option. Reserve Margin For Luzon and Visayas, the average reserve margins are 33% and 26%, respectively. Mindanao’s average reserve margin, for 2008 to 2012, is 53%. The average for the country is 34%. Energy Mix Figure 5.7 illustrates the energy mix resulting from the LEGS-ACPD option. The 30% increase in renewable energy share from 37% to 48% over the planning period, brings the clean energy generation from 33,794 GWh in 2003 to 84,270 GWh in 2012. Figure 5.8 shows the increase in clean energy share in the mix. Fuel Consumption Total fuel requirement for the LEGS-ACPD is 66,523,175 tonnes of coal, 1471.7 BCF of natural gas and 57.2 million barrels of oil. Coal importation for this option reaches 58,074,731 tonnes, while importation of oil and natural gas stand at 57.2 million barrels and 139.4 BCF, respectively. The mix of imported and indigenous fuel is shown in Figure 5.9. Total cost of fuel that is needed to be imported for this scenario is $ 2,860 million. Environmental Emissions and Abatement Cost The increased utilization of renewable energy resources, in this option, brings the CO2 emission level at 321.34 tonnes/GWh. The total CO2 emissions for the period is 248.4 million tonnes, which is 60.9 million tonnes less than the LEGS-PEP. The total CO2 emissions for each year are shown in Figure 5.10. Total cost of abatement for this option is $ 21,294,633,715.



Figure 5.6: Installed Generating Capacity for the LEGS-ACPD Scenario

Figure 5.7: Energy Mix for the LEGS-ACPD Scenario

0

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

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30%

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50%

60%

70%

80%

90%

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year




Figure 5.8: Coal and Oil-Based vs. Renewable and Natural Gas Energy Mix for the LEGS-ACPD Scenario

Figure 5.9: Fossil Fuel Consumption for the LEGS-ACPD Scenario

0

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000

90,000,000


(tonn

es)


0%

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20%

30%

40%

50%

60%

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012




Figure 5.10: CO2 Emissions for the LEGS-ACPD Scenario

Generation Cost For this LEGS-ACPD, computed cost values for the planning period are as follows:


This scenario would cost $52 million more than the LEGS-PEP. 5.3 HEGS-MCPD Scenario In this scenario, the Moderate Clean Power Development option is applied to the High Economic Growth Scenario. Installed Capacity The installed capacity for this option is given in Figure 5.11. Natural gas capacities are increased throughout the period and would account for the biggest share in installed capacity by 2012. Renewable energy capacity accounts for 30% in 2003 and 39% in 2012.

0

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20,000,000

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012




Reserve Margin The effective reserve margin of 27% to 31% for the whole country of the HEGS-MCPD option is close to the HEGS-PEP range of 25% to 30% for 2003 to 2012. This difference is attributable to the inevitable higher reserve margin for Mindanao, which falls within 35% to 48%. Energy Mix With its installed capacities dominating, renewable energy and natural gas contribution to the energy mix increases from 61% to 74% for 2003 to 2012. Of this mix, 2% is contributed by wind power plants. Figure 5.12 shows the corresponding energy mix for the HEGS-MCPD option, while Figure 5.13 illustrates the clean energy mix. Fuel Consumption To meet demand and energy requirements, this scenario would require 70.7 million barrels of oil, 73,940,271 tonnes of coal and 1,718.9 BCF of natural gas for the whole planning period. Of these amounts, 70.7 million barrels of oil, 64,549,857 tonnes of coal and 342.8 BCF tonnes of natural gas would have to be imported. Total cost of fuel imports is $ 3,322 million. Environmental Emissions Figure 5.15 shows the CO2 emissions resulting from the HEGS-MCPD option. The total CO2 emissions is at 283.8 million tonnes, which is 63.4 million tonnes lower than the HEGS-PEP. Total abatement cost for this option is $ 24,076,349,686. Generation Cost For this HEGS-MCPD, computed cost values for the planning period are as follows:




Figure 5.11: Installed Generating Capacity for the HEGS-MCPD Scenario

Figure 5.12: Energy Mix for the HEGS-MCPD Scenario

0

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

MW


0%

20%

40%

60%

80%

100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year





for the HEGS-MCPD Scenario

Figure 5.14: Fossil Fuel Consumption for the HEGS-MCPD Scenario

-

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000


(tonn

es)


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30%

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50%

60%

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012




Figure 5.15: CO2 Emissions for the HEGS-MCPD Scenario

5.4 HEGS-ACPD Scenario In this option, the Aggressive Clean Power Development option strategy is applied to the High Economic Growth Scenario. Installed Capacity The more aggressive use of renewable energy resources for this option results to a 50% contribution of renewable energy to the total installed capacity in 2012. Figure 5.16 illustrates this. Reserve Margin With the inevitably high reserve margin of 45% to 51% for Mindanao, the country’s effective reserve margin ranges from 28% to 32%. Energy Mix While oil-based and coal share in the energy mix decreased by 38%, clean energy share increased by 24% over the planning period. Figure 5.17 and Figure 5.18 illustrate these changes in the energy mix.

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012




Fuel Consumption To meet demand and energy requirements, this scenario would require 90.0 million barrels of oil, 67,791,682 tonnes of coal and 1,638.5 BCF of natural gas for the whole planning period. All of the oil would have to be imported, along with 59,182,139 tonnes of coal and 276.7 BCF of natural gas. Figure 5.19 shows the sharing of the imported and indigenous fossil fuels. Cost of fuel imports is $ 3,513 million. Environmental Emissions and Abatement Cost Carbon dioxide generation for the HEGS-ACPD option is shown in Figure 5.20. Total CO2 emissions is at 275.1 million tonnes, 72.1 million tonnes lower than that for the HEGS-PEP. The cost of abatement for SOx, NOx and particulates for this option is 23,288,583,560. Generation Cost For this HEGS-ACPD, computed cost values for the planning period are as follows:




Figure 5.16: Installed Generating Capacity for the HEGS-ACPD Scenario

Figure 5.17: Energy Mix for the HEGS-ACPD Scenario

0

5,000

10,000

15,000

20,000

25,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year

MW

Oil-based Coal Natural Gas GeothermalHydro Biomass Wind Peak Demand

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Year





for the HEGS-ACPD Scenario

Figure 5.19: Fuel Consumption for the HEGS-ACPD Scenario

0%

10%

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30%

40%

50%

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100%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012


0

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20,000,000

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Figure 5.20: CO2 Emissions for the HEGS-ACPD Scenario

0

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25,000,000

30,000,000

35,000,000

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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012




6 Conclusions and Recommendations The Philippine power sector from 1991 to 2001 has not performed very well in terms of reliability and cost to end-users. While the PEP has tried to address these problems, it fails to consider the implications of the activities in this sector to the environment that could even be more important if only the externalities will be considered in the economics of energy supply. Historically, the installed capacity and hence the energy mix has been dominated by non-renewable energy. In the medium term, the business-as-usual Philippine Energy Plan 2003 – 2012 does not offer a different scenario. The contribution from renewable energy is expected to decline in the next 10 years, which will worsen the situation from the point of view of clean and sustainable development. This study has assessed the technologies and resources in the Philippines that could be tapped for clean power development. The country has nearly exhausted its geothermal and large hydro resources. To avoid significant amounts of GHG emissions in the future, the country has to resort to biomass, small hydro, wind and natural gas technologies, as was done in this study. At the moment, the local natural gas industry is anchored on the natural gas find in Malampaya. To support power switching, new natural gas sites must be identified and developed. In addition, natural gas importation may be pursued. Another issue is the intermittent nature of wind power, which could adversely affect the power system’s stability at high levels of penetration. To aid planning and operation of the power system, study must be made to determine how much wind power capacity the local power system grids could absorb. Biomass power is also an attractive option for grid-connected generation. But it is still associated with problems such as fuel collection, storage and therefore requires that more research and development activities to address these issues. This study also offers two alternative paths or strategies (moderate and aggressive) through the alternative clean power development plans. These alternative plans are comparable to the PEP in terms of costs. There are even opportunities that can create additional dollar income from carbon trading and local employment. At the current CO2 prices ($5 per tonne) in the market, the Moderate Clean Power Development Plans are viable greenhouse gas mitigation option for the Philippines offering so many opportunities both for the developers and the country. Switching to cleaner energy, therefore, is attractive as the price of carbon is expected to increase in the future. Pursuing the Clean Power Development plans requires the development of a “clean energy” market in the country through effective policy instruments and mechanisms that will secure the investment climate while protecting public interest. In the following paragraphs, we have outlined a set of measures that should be made to attract more investments in renewable generation technologies in the future.



6.1 Energy Planning The first step in developing the market for clean energy is to introduce reforms in the process of energy planning itself. Since power developers will only respond to the government call, it is important that the Philippine Energy Plan reflect the call for clean power development. This could be achieved through the following: • Improve the power development planning models

- Include environmental externalities in planning models to reflect the true cost to society of energy decisions;

- Consider the economics of smaller capacity, following load growth to deal with the overcapacity issue (in contrast to large capacity power plants currently used in energy planning);

- Include energy efficiency as a demand side option in energy planning models;

- Use coal-fired fluidized combustion technology as benchmark fossil-based plant instead of pulverized coal;

- Increase the number of candidate Renewable Energy-based Power Plants in the selection process. To increase the number of candidate renewable energy plants in planning, more rigorous and site-specific resource assessment must be conducted.

• Institutionalize a participative planning process. A decentralized planning process down to the level of the local government and participated by the stakeholders in the locality should complement the top-down planning process at the national level. Electrification planning can be done in the municipality/city levels. Resource assessment and local supply and demand balance can be done at the provincial level. This decentralized planning scheme will result in a more realistic demand forecast and will address local issues on energy, as well as issues on under- and overcapacity. While this planning process allows for a greater degree of public participation, it will also entail capacity building for local government units in the areas of planning and resource assessment. A schematic of the proposed planning process is shown in Figure 6.1.



Figure 6.1: Recommended Bottom-Up Approach to Energy Planning

6.2 Transmission and Distribution Development Transmission and distribution infrastructure should be developed to increase access to renewable energy sites, most of which are site specific. Transmission facilities should deliberately be expanded toward locations of promising renewable energy sources. The cost of such an expansion should be borne by the transmission or distribution utility. This cost mechanism will ensure that all electricity consumers will share the cost of such a development. The Energy Regulatory Commission (ERC) should allow such an expansion even if it does not initially show recovery of investment. 6.3 Rules and Regulation • The Wholesale Electricity Spot Market (WESM) Rules must provide that

intermittent and small-scale grid-connected renewable energy generation systems (such as wind, run-of-river small hydro and biomass) should be given priority in the dispatch of generating units. These plants must “feed-in” the Grid at minimum prices that will guarantee the returns of power developers.

• The System Operator should be allowed to procure ancillary services needed by the Grid to accommodate intermittent wind power and pass on the cost to all users of the Grid.

• The Philippine Grid and Distribution Code (PGDC) must be clear on its requirements and procedures on the connection, operation and control of non-conventional, renewable energy-based power plants, particularly on the required technical analysis and compensating equipment.

Private S

ector Proposals

National Level

Provincial Level

National Energy Plan Centralized System Planning and

Integration of Provincial Plans

Provincial Energy Plan Resource Assessment and

Local Supply and Demand Balance

City/Municipality Energy Plan Electrification Planning

City/Municipality Level



6.4 Incentive Programs • The Department of Energy must ensure that renewable energy development

should always be included in the Philippine Investment Priorities of the Board of Investment to ensure that the fiscal (e.g., tax exemptions, income tax holidays and tax credits) and non-fiscal (e.g., simplification of custom procedures and importation of consigned equipment) will be available for renewable energy developers.

• An assistance program should be created for renewable energy development. This may include subsidy for resource assessment and feasibility studies for serious developers of renewable energy.

• Dedicated Financing Windows that allow longer repayment periods for renewable energy-based development.



7 REFERENCES Bain, Richard L., Biomass-Fired Power Generation, IEA Bioenergy Implementing Agreement, October 1996. Elliot, D., et al., Wind Energy Resource Atlas of the Philippines, National Renewable Energy Laboratory (February 2001). Estiva, J.N., and Guzman, M.G., Renewable Energy Prospects for Supplying Electricity in the Deregulated Market in the Philippines. Koomey, Jonathan and Krause, Florentin, “Introduction to Environmental Externality Costs,” CRC Handbook on Energy Efficiency, Boca Raton, FL: CRC Press, Inc., 1997. Parsons, B., “Grid-Connected Wind Energy Technology: Progress and Prospects”, paper presented at the North American Conference of the International Association of Energy Economists, Albuquerque, New Mexico (October 1998). Sundqvist, T. “Power Generation Choice in the Presence of Environmental Externalities.” Doctorate Thesis. Luleá University of Technology, 2002. Wan, Y., and B. Parsons, “Factors Relevant to Utility Integration of Intermittent Renewable Technologies”, National Renewable Energy Laboratory (1993). Choices for a Brighter Future (United States of America Department of Energy, September 1999). Environmental Manual (EM) for Power Development, OKÖ Institute, Germany (1999) Natural Gas Plan, Philippines Department of Energy Philippine Energy Plan 2002-2011, Philippines Department of Energy. Philippine Energy Plan 2003-2012, Philippines Department of Energy. Philippine Motor Market Characterization, Leverage International (Consultants) Inc. (February 1998). Philippine New Commercial Building Market Characterization, Leverage International (Consultants) Inc. (March 1998) Renewable Energy, Godfrey Boyle, ed., The Open University, Milton Keynes (1996). Scenarios for a Clean Energy Future Strengthening the Non-Conventional and Rural Energy Development Program in the Philippines: A Policy Framework and Action Plan, joint UNDP/World Bank Energy Sector Management Assistance Program (ESMAP), (August 2001).



The EM Generic Database, Deutsche Gessellschaft für technische (Zusammenarbeit GmbH, updated March 1999). The Philippines’ Initial National Communication on Climate Change www.eere.energy.gov/state_energy Ledesma, Alexis. Bronzeoak Philippines, Makati, Philippines. Interview, 25 July 2003.

Appendix A Practical Wind and Hydro Resource

Potential in the Philippines

Appendix A POWER SWITCH! Scenarios and Strategies for Clean Power Development in the Philippines

University of the Philippines Solar Laboratory page 1 of 4 Kabang Kalikasan ng Pilipinas, Inc. UPEEE Foundation

Table A.1: Locations of Practical Wind Resources in Luzon

Province Number of Sites Estimated

Aggregate Capacity (MWe)

Estimated Aggregate Annual Generation (GWh)

Abra 26 183 567 Albay 26 183 576 Aurora 46 320 1,011 Bataan 26 169 530 Batangas 16 104 328 Benguet 20 137 421 Bulacan 2 41 126 Cagayan 8 80 246 Camarines Norte 18 117 372 Camarines Sur 36 234 742 Cavite 8 87 267 Ifugao 15 98 299 Ilocos Norte 31 265 832 Ilocos Sur 8 52 161 Isabela 90 620 1,922 Kalinga 21 158 484 Laguna 5 40 125 Mountain Province 5 33 100 Nueva Ecija 20 151 478 Nueva Vizcaya 43 315 971 Pampanga 7 46 143 Pangasinan 17 125 382 Quezon 11 86 263 Quirino 21 165 509 Rizal 15 98 307 Sorsogon 24 163 509 Tarlac 4 40 123 Zambales 117 796 2,486 LUZON TOTAL 686 4906 15,280



Table A.2: Locations of Practical Wind Resources in Visayas

Province Number of Sites Estimated Capacity (MWe)

Estimated Annual Generation (GWh)

Aklan 24 163 517 Antique 41 309 965 Biliran 20 144 466 Bohol 6 39 120 Capiz 1 7 20 Cebu 30 202 620 Eastern Samar 2 14 43 Iloilo 12 85 266 Leyte 52 357 1,113 Negros Occidental 26 169 519 Negros Oriental 48 347 1,065 Samar 10 75 229 Southern Leyte 33 259 795 VISAYAS TOTAL 305 2,170 6,738

Table A.3: Locations of Practical Wind Resources in Mindanao

Province No. of Sites Estimated Capacity (MWe)


Agusan del Norte 19 133 408 Agusan del Sur 6 42 129 Camiguin 4 28 86 Surigao del Norte 14 105 322 Surigao del Sur 4 28 86 MINDANAO TOTAL 47 336 1,031



Table A.4. Locations of Practical Small Hydro Potential Resources in Luzon


Estimated Annual Generation (GWhr)

Abra 20 196 1,030 Aurora 1 10 53 Benguet 9 79 415 Ifugao 3 32 168 Ilocos Norte 3 22 116 Ilocos Sur 4 40 210 Isabela 8 72 378 Kalinga 30 318 1,671 La Union 6 35 184 Mountain Province 3 34 179 Nueva Vizcaya 15 181 110 Pangasinan 4 26 951 Quezon 3 28 147 Quirino 19 179 941 Tarlac 1 6 32 LUZON TOTAL 129 1,258 6,585

Table A.5. Locations of Practical Small Hydro Potential Resources in Visayas



Aklan 1 5 26 Eastern Samar 5 33 173 Negros Occidental 2 13 68 Negros Oriental 1 7 37 VISAYAS TOTAL 9 58 304



Table A.6. Locations of Practical Small Hydro Potential Resources in Mindanao



Agusan del Norte 3 18 95 Bukidnon 21 322 1,692 Davao 7 7 7 Davao Oriental 18 18 18 Lanao del Norte 7 53 279 Lanao del Sur 4 26 137 Maguindanao 6 58 305 Misamis Oriental 10 69 363 North Cotabato 18 230 1,209 Sultan Kudarat 1 7 37 Surigao del Sur 2 11 58 Zamboanga del Norte 1 7 37 MINDANAO TOTAL 98 826 4,237

Appendix B Historical Performance of the

Philippine Power Sector 1991-2001

Appendix B POWER SWITCH! Scenarios and Strategies for Clean Power Development in the Philippines


Table B.1: Installed Generating Capacity, 1991-2001

(MW)

Source: DOE

Table B.2: Power Generation by Source (1991-2001)

(GWh)

Source: DOE

Table B.3: Energy Consumption by Sector, 1991-2001

(GWh) Year

Year 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Residential 6,249 6,053 6,368 7,282 8,223 9,150 10,477 11,936 11,875 12,894 13,547

Commercial 4,847 4,910 4,725 5,865 6,353 7,072 8,013 8,725 8,901 9,512 10,098

Industrial 9,339 8,859 9,395 10,684 10,950 11,851 12,531 12,543 12,444 13,191 14,452

Others 952 823 721 762 1,067 1,167 1,267 934 921 957 1,042

Utilities Own Use 1,086 1,154 1,132 1,132 1,226 1,340 1,471 1,590 1,536 2,390 2,196

Power Losses 3,176 4,071 4,238 4,734 5,735 6,128 6,037 5,849 5,754 6,345 5,713

Total 25,649 25,870 26,579 30,459 33,554 36,708 39,797 41,578 41,432 45,290 47,049 Source: DOE

Oil-based Coal Natural Gas Geothermal Hydro Biomass Wind Total

1991 3,341 405 0 888 2,155 0 0 6,789

1992 3,399 405 0 888 2,257 0 0 6,949

1993 4,296 441 0 963 2,259 0 0 7,959

1994 5,335 550 0 1,073 2,254 0 0 9,212

1995 5,425 850 0 1,154 2,301 0 0 9,730

1996 5,844 1,600 0 1,417 2,301 0 0 11,162

1997 5,973 1,600 3 1,819 2,301 0 0 11,696

1998 5,568 2,200 3 1,856 2,301 0 0 11,928

1999 4,839 3,493 3 1,931 2,301 0 0 12,567

2000 4,987 3,963 3 1,931 2,301 0 0 13,185

2001 3,927 3,963 1,063 1,931 2,518 0 0 13,402

YearFuel Type


1991 12,804 1,942 0 5,758 5,145 0 0 25,649

1992 13,939 1,791 0 5,700 4,440 0 0 25,870

1993 13,867 2,015 0 5,667 5,030 0 0 26,579

1994 16,929 1,348 0 6,320 5,862 0 0 30,459

1995 19,078 2,109 0 6,135 6,232 0 0 33,554

1996 18,288 4,855 0 6,534 7,030 0 0 36,707

1997 19,116 7,363 12 7,237 6,069 0 0 39,797

1998 18,190 9,388 20 8,914 5,066 0 0 41,578

1999 11,799 11,183 16 10,594 7,840 0 0 41,432

2000 9,185 16,663 17 11,626 7,799 0 0 45,290

2001 9,867 18,789 848 10,442 7,104 0 0 47,050

YearFuel Type

Appendix B POWER SWITCH! Scenarios and Strategies for Clean Power Development in the Philippines


Table B.4: Peak Demand, 1991-2001

(MW) Year 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Luzon 3,045 3,250 3,473 3,561 3,920 4,306 4,773 5,028 5,226 5,649 5,835

Visayas 410 473 523 551 591 682 727 770 789 812 893

Mindanao 626 573 691 696 780 828 852 868 893 939 954

Philippines 4,081 4,296 4,687 4,808 5,291 5,816 6,352 6,666 6,908 7,400 7,682

Source: DOE

Table B.5: Generation by Grid, 1991-2001

(GWh) 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Luzon 19,511 19,967 19,902 23,290 25,206 27,688 30,084 31,755 31,745 34,679 36,184

Visayas 2,376 2,566 2,813 3,036 3,652 3,991 4,347 4,481 4,441 5,147 5,163

Mindanao 3,763 3,337 3,864 4,133 4,695 5,029 5,365 5,343 5,245 5,464 5,703

Philippines 25,649 25,870 26,579 30,459 33,554 36,708 39,797 41,578 41,432 45,290 47,049

Source: DOE

Table B.6: Carbon Dioxide Emissions by Source, tonne CO2

Table B.6: Environmental Emissions, tonne


1991 9,236,541 1,082,279 0 261,413 0 0 0 10,580,233

1992 10,094,675 998,127 0 258,780 0 0 0 11,351,582

1993 10,185,915 1,122,962 0 257,282 0 0 0 11,566,159

1994 12,509,360 751,242 0 286,928 0 0 0 13,547,530

1995 14,131,794 1,175,348 0 278,529 0 0 0 15,585,671

1996 13,519,362 2,705,698 0 296,644 0 0 0 16,521,704

1997 14,119,644 4,103,175 1,789 328,556 0 0 0 18,553,164

1998 13,491,679 5,231,854 3,076 404,674 0 0 0 19,131,283

1999 8,712,872 6,232,261 2,345 480,970 0 0 0 15,428,448

2000 6,870,702 9,286,311 2,563 527,820 0 0 0 16,687,396

2001 7,338,665 10,471,222 127,808 474,067 0 0 0 18,411,762

YearFuel Type

CO2 SOX NOX CO CH4 NMVOC N2O Particulates

1991 10,580,233 115,725 58,726 16,124 587 975 415 10,989

1992 11,351,582 117,990 67,069 17,090 643 1,038 436 12,639

1993 11,566,159 99,004 84,238 16,083 685 973 421 16,311

1994 13,547,530 101,964 106,586 18,486 835 1,133 469 20,733

1995 15,585,671 114,552 126,633 20,903 963 1,273 541 24,747

1996 16,521,704 135,204 130,492 21,781 974 1,291 610 25,616

1997 18,553,164 160,414 144,932 24,109 1,062 1,403 711 28,555

1998 19,131,283 162,882 154,678 23,836 1,076 1,359 742 30,708

1999 15,428,448 149,848 117,896 18,521 792 1,004 644 23,580

2000 16,687,396 164,831 136,309 18,116 805 906 734 27,727

2001 18,411,762 189,729 146,807 20,796 904 1,075 842 29,611

Environmental EmissionsYear

Appendix C Economic Scenarios and DOE Plans

for the Power Sector 2003-2012

Appendix C POWER SWITCH: Scenarios and Strategies for Clean Power Development in the Philippines


Table C.1a: DOE Plan for Power Generation for the Low Economic Growth Scenario

(GWh)

Year Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil-Based 2720 3247 3127 2777 4318 5117 5673 4577 3710 4015 Fuel Oil 2377 2747 2740 2701 4166 4998 5499 4365 3580 3859 Diesel 343 500 388 75 151 119 174 212 130 157 Coal 18629 18087 19953 24659 26446 27561 29218 28828 27420 27606 Local 2820 1101 1289 2216 2586 2862 3200 3108 2789 2842 Imported 15809 16986 18664 22443 23860 24698 26018 25720 24630 24764 Natural Gas 13349 16017 17141 18210 19415 20074 20260 20192 19965 20068 Hydro 6324 6893 7928 7943 7968 8001 8042 8069 8029 8038 Geothermal 14121 14975 15054 15092 15098 15099 15095 15104 15103 15103 Wind 0 153 153 153 153 153 153 153 153 152 Others 0 0 825 746 1551 4433 7920 15713 24910 31448 Baseload 0 0 0 0 1104 2960 4028 10338 19206 25371 Midrange 0 0 825 746 446 1473 3852 4881 5339 5545 Peaking 0 0 0 0 0 0 39 495 365 531 TOTAL 55142 59372 64182 69580 74948 80437 86360 92636 99290 106430 Source: Philippine Energy Plan 2003-2012

Table C.1b: System Peak Demand Forecasts for the Low Economic Growth Scenario

(MW)

YEAR LUZON VISAYAS MINDANAO NATIONAL Non-Coincident Peak

2003 6,752 1,007 1,074 8,833 2004 7,275 1,084 1,159 9,519 2005 7,855 1,168 1,254 10,277 2006 8,503 1,276 1,360 11,139 2007 9,161 1,377 1,459 11,997 2008 9,830 1,477 1,563 12,869 2009 10,548 1,592 1,673 13,813 2010 11,319 1,707 1,789 14,814 2011 12,149 1,829 1,912 15,889 2012 13,034 1,958 2,041 17,033

Annual Ave. G.R.

(2003 - 2007) 7.93% 8.13% 7.95% 7.95% (2008 - 2012) 7.31% 7.30% 6.91% 7.26% (2003 - 2012) 7.58% 7.67% 7.39% 7.57%

Source: Philippine Energy Plan 2003-2012



Table C.1c: Electricity Sales Forecasts for the Low Economic Growth Scenario (GWh)

YEAR LUZON VISAYAS MINDANAO TOTAL

2003 39,604 5,320 6,258 51,182 2004 42,675 5,726 6,754 55,154 2005 46,072 6,170 7,306 59,548 2006 49,875 6,740 7,924 64,539 2007 53,735 7,274 8,497 69,506 2008 57,660 7,801 9,103 74,564 2009 61,870 8,411 9,743 80,024 2010 66,391 9,016 10,420 85,827 2011 71,260 9,661 11,135 92,057 2012 76,452 10,342 11,892 98,686

Annual Ave. G.R.

(2003 - 2007) 7.93% 8.13% 7.95% 7.95% (2008 - 2012) 7.31% 7.30% 6.91% 7.26% (2003 - 2012) 7.58% 7.67% 7.39% 7.57%




Table C.1d: DOE Plan for Installed Capacity for the Low Economic Growth Scenario

(MW)

Year Fuel Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil-based 2443 2443 2443 2443 2443 2443 2233 1583 1583 1583 Coal 3758 3758 3758 3758 3758 3758 3758 3758 3758 3758

Local 450 450 450 450 450 450 450 450 450 450

Imported 3,308 3,308 3,308 3,308 3,308 3,308 3,308 3,308 3,308 3,308

Natural Gas 2763 2763 2763 2763 2763 2763 2763 2763 2763 2763 Hydro 1510 1860 2205 2205 2205 2205 2205 2205 2205 2205 Geothermal 907 907 907 907 907 907 907 907 907 907 NRE

Wind - 65 65 65 65 65 65 65 65 65

Others

Baseload - - - - - - - 600 1500 2100

Intermediate - - - - - 300 900 1200 1500 1500

Peaking - - - - - - 300 750 750 900

Luzo

n

LUZON TOTAL 11,381 11,796 12,141 12,141 12,141 12,441 13,131 13,831 15,031 15,781 Oil-based 468 431 281 281 281 281 281 281 182 182

Coal 205 205 205 205 205 205 205 205 205 205

Local 150 150 150 150 150 150 150 150 150 150

Imported 55 55 55 55 55 55 55 55 55 55

Natural Gas - - - - - - - - - -

Hydro 12 12 12 12 12 12 12 12 12 12 Geothermal 919 959 959 959 959 959 959 959 959 959 NRE

Wind - - - - - - - - - -

Others Baseload - - - - 100 200 300 400 500 600 Intermediate - - 200 250 250 250 350 350 350 350 Peaking - - - - - - - - - -

Vis

ayas

VISAYAS TOTAL 1,604 1,607 1,657 1,707 1,807 1,907 2,107 2,207 2,208 2,308

Oil-based 546 616 616 616 616 616 616 616 616 616 Coal - - - 200 200 200 200 200 200 200

Local - - - - - - - - - -

Imported - - - 200 200 200 200 200 200 200

Natural Gas - - - - - - - - - -


Wind - - - - - - - - - -

Others

Baseload - - - - 50 200 250 350 500 600

Intermediate - - 100 100 100 100 100 100 100 100

Peaking - - - - - - - - - -

Min

dan

ao

MINDANAO TOTAL 1,647 1,717 1,817 2,017 2,067 2,217 2,267 2,367 2,517 2,617



Year Fuel Type

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Oil-based 3,457 3,490 3,340 3,340 3,340 3,340 3,130 2,480 2,381 2,381 Coal 3,963 3,963 3,963 4,163 4,163 4,163 4,163 4,163 4,163 4,163

Local 600 600 600 600 600 600 600 600 600 600

Imported 3,363 3,363 3,363 3,563 3,563 3,563 3,563 3,563 3,563 3,563

Natural Gas 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 Hydro 2,519 2,869 3,214 3,214 3,214 3,214 3,214 3,214 3,214 3,214 Geothermal 1,930 1,970 1,970 1,970 1,970 1,970 1,970 1,970 1,970 1,970 NRE

Wind - 65 65 65 65 65 65 65 65 65

Others

Baseload - - - - 150 400 550 1,350 2,500 3,300

Intermediate - - 300 350 350 650 1,350 1,650 1,950 1,950

Peaking - - - - - - 300 750 750 900

Phi

lippi

nes

PHILIPPINES TOTAL 14,632 15,120 15,615 15,865 16,015 16,565 17,505 18,405 19,756 20,706 Source: Philippine Energy Plan 2003



Table C.1e: DOE Plan for Power Plant Line-Up for the Low Economic Growth Scenario


LUZON VISAYAS MINDANAO PHILIPPINES

YEAR PLANT ADDITION MW

capacity installed

MW PLANT ADDITION MW capacity

installed MW PLANT ADDITION MW

capacity installed

MW cumulative total

Kalayaan 3&4

350 345

Uprating of Leyte-Bohol Interconnection from 35 MW to 100 MW 40 385

PNOC_EDC Wind 40 Mambucal Geo 40 Transfer of a Diesel Plant to Mindanao (70 MW) -70

2004

Northwind 25

San Roque Hydro

345 690

Uprating of Leyte-Cebu Interconnection from 200 MW to 400 MW 240

Diesel Plant from Luzon 70 170 1,100

Panay Midrange 150 Midrange Plant 100

2005

Negros Midrange 50

2006 690 Panay Midrange 50 290 Mindanao Coal 200 370 1,350

2007 690 Panay Baseload 100 390 Baseload Plant 50 420 1,500

Midrange 300 990 Cebu Baseload 50 490 Baseload Plant 150 570 2,050 2008

Negros Baseload 50

Midrange 600 1,890 Cebu Baseload 50 690 Baseload Plant 50 620 3,200

Peaking 300 Panay Baseload 50 2009

Bohol Midrange 100

Baseload Plant 600 3,240 Cebu Baseload 100 790 Baseload Plant 100 720 4,750

Midrange 300 2010

Peaking 450

Baseload Plant 900 4,440 Cebu Baseload 50 890 Baseload Plant 150 870 6,200 2011

Midrange 300 Negros Baseload 50

Baseload Plant 600 5,190 Cebu Baseload 50 990 Baseload Plant 100 970 7,150 2012

Peaking 150 Panay Baseload 50



Table C.1f: Total CO2 Emissions by Fuel Type for the DOE Plan for the Low Economic Growth Scenario

(tonne) Year Geothermal Coal Natural gas Oil-based TOTAL

2003 641,093 10,114,896 5,897,849 2,125,011 18,778,850

2004 679,865 9,820,609 7,076,624 2,536,797 20,113,894

2005 683,452 10,833,782 7,573,229 3,158,821 22,249,284

2006 685,177 13,388,975 8,045,534 2,816,776 24,936,462

2007 685,449 14,958,687 8,577,927 3,760,465 27,982,528

2008 685,495 16,571,837 8,869,086 5,275,644 31,402,061

2009 685,313 18,051,416 8,951,264 7,803,792 35,491,785

2010 685,722 21,265,770 8,921,220 8,188,273 39,060,985

2011 685,676 25,316,289 8,820,927 7,809,100 42,631,993

2012 685,676 28,764,660 8,866,435 8,352,840 46,669,611

Total for period 6,802,918 169,086,922 81,600,095 51,827,519 309,317,453

Table C.1g: Total SOx Emissions by Fuel Type for the DOE Plan for the Low Economic Growth Scenario

(tonne)

Year Geothermal Coal Natural gas Oil-based TOTAL

2003 - 137,855 104 21,330 159,289

2004 - 133,844 125 25,460 159,429

2005 - 147,652 134 34,201 181,988

2006 - 182,477 143 30,532 213,151

2007 - 203,870 152 39,091 243,113

2008 - 225,855 157 57,410 283,422

2009 - 246,020 159 89,762 335,941

2010 - 289,828 158 94,177 384,163

2011 - 345,032 156 92,491 437,680

2012 - 392,030 157 97,635 489,821

Total for period - 2,304,464 1,445 582,088 2,887,997

Table C.1h: Total NOx Emissions by Fuel Type for the DOE Plan for the Low

Economic Growth Scenario (tonne)


2003 - 78,242 21,939 12,531 112,712

2004 - 75,965 26,324 14,962 117,251

2005 - 83,803 28,171 16,963 128,937

2006 - 103,568 29,928 15,103 148,599

2007 - 115,710 31,908 21,279 168,897

2008 - 128,188 32,991 28,138 189,317

2009 - 139,633 33,297 38,410 211,340

2010 - 164,497 33,185 40,521 238,203

2011 - 195,829 32,812 36,808 265,450

2012 - 222,503 32,981 40,303 295,788

Total for period - 1,307,939 303,536 265,019 1,876,493



Table C.1i: Total CO Emissions by Fuel Type for the DOE Plan for the Low Economic Growth Scenario

(tonne)


2003 - 9,873 8,776 2,714 21,362

2004 - 9,586 10,529 3,240 23,355

2005 - 10,575 11,268 4,397 26,241

2006 - 13,069 11,971 3,925 28,966

2007 - 14,602 12,763 4,999 32,363

2008 - 16,176 13,196 7,385 36,758

2009 - 17,620 13,319 11,656 42,595

2010 - 20,758 13,274 12,554 46,586

2011 - 24,712 13,125 12,285 50,121

2012 - 28,078 13,193 13,053 54,323

Total for period - 165,049 121,414 76,207 362,671

Table C.1j: Total CH4 Emissions by Fuel Type for the DOE Plan for the Low Economic Growth Scenario


2003 - 103 145 33 282

2004 - 100 174 40 314

2005 - 111 186 49 346

2006 - 137 198 44 379

2007 - 153 211 59 423

2008 - 170 218 82 470

2009 - 185 220 121 526

2010 - 218 219 129 566

2011 - 259 217 122 598

2012 - 294 218 131 644

Total for period - 1,730 2,008 810 4,548

Table C.1k: Total NMVOC Emissions by Fuel Type for the DOE Plan for the Low



2003 - 373 1,045 163 1,581

2004 - 362 1,254 195 1,810

2005 - 399 1,341 267 2,008

2006 - 493 1,425 238 2,157

2007 - 551 1,519 302 2,373

2008 - 610 1,571 449 2,630

2009 - 665 1,586 713 2,963

2010 - 783 1,580 770 3,134

2011 - 933 1,562 755 3,250

2012 - 1,060 1,571 802 3,432

Total for period - 6,228 14,454 4,655 25,337



Table C.1l: Total N2O Emissions by Fuel Type for the DOE Plan for the Low Economic Growth Scenario


2003 - 559 313 79 952

2004 - 543 376 95 1,013

2005 - 599 402 121 1,122

2006 - 740 428 108 1,275

2007 - 827 456 142 1,424

2008 - 916 471 202 1,589

2009 - 997 476 305 1,778

2010 - 1,175 474 320 1,969

2011 - 1,399 469 308 2,176

2012 - 1,589 471 328 2,389

Total for period - 9,342 4,336 2,008 15,686

Table C.1m: Total Particulate Emissions by Fuel Type for the DOE Plan for the

Low Economic Growth Scenario (tonne)


2003 - 16,394 836 2,698 19,927

2004 - 15,917 1,003 3,221 20,140

2005 - 17,559 1,073 3,528 22,160

2006 - 21,700 1,140 3,139 25,979

2007 - 24,244 1,216 4,514 29,973

2008 - 26,858 1,257 5,836 33,952

2009 - 29,256 1,268 7,684 38,209

2010 - 34,466 1,264 7,923 43,653

2011 - 41,031 1,250 7,072 49,353

2012 - 46,620 1,256 7,771 55,647

Total for period - 274,044 11,563 53,387 338,995

Table C.1n: Environmental Emissions per Unit Generation

(tonne/kWh) Environmental Emissions

Year CO2 SOX NOX CO CH4 NMVOC N2O Particulates

2003 340.55 2.89 2.04 0.39 0.01 0.03 0.02 0.36

2004 338.78 2.69 1.97 0.39 0.01 0.03 0.02 0.34

2005 346.66 2.84 2.01 0.41 0.01 0.03 0.02 0.35

2006 358.39 3.06 2.14 0.42 0.01 0.03 0.02 0.37

2007 373.36 3.24 2.25 0.43 0.01 0.03 0.02 0.40

2008 390.39 3.52 2.35 0.46 0.01 0.03 0.02 0.42

2009 410.97 3.89 2.45 0.49 0.01 0.03 0.02 0.44

2010 421.66 4.15 2.57 0.50 0.01 0.03 0.02 0.47

2011 429.37 4.41 2.67 0.50 0.01 0.03 0.02 0.50

2012 438.50 4.60 2.78 0.51 0.01 0.03 0.02 0.52



Table C.2a: DOE Plan for Power Generation for the High Economic Growth Scenario

(GWh) Year Type

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Oil-Based 2865 3614 3484 3899 6367 6225 5758 3494 3009 4246 Fuel Oil 2465 3018 2956 3725 6021 6074 5555 3339 2944 4088 Diesel 400 596 528 175 345 151 203 155 64 157 Coal 18893 18850 21243 26016 27836 29335 30518 29734 28946 30604 Local 3082 1363 2323 2507 2923 3158 3372 3242 3042 3338 Imported 15811 17487 18920 23509 24912 26177 27146 26492 25904 27267 Natural Gas 13349 16084 17439 18578 19791 20221 20260 20192 19965 20122 Hydro 6324 6893 7932 7952 8020 8027 8073 8069 8043 8093 Geothermal 14126 15000 15076 15101 15104 15104 15101 15104 15105 15106 Wind 0 153 153 153 153 153 153 153 153 152 Others 0 0 937 952 1883 6743 13254 24128 34095 40147 Baseload 0 0 0 0 1142 3435 5158 13769 22932 24783 Midrange 0 0 937 952 741 3308 8062 10345 11154 15028 Peaking 0 0 0 0 0 0 33 14 10 336 TOTAL 55556 60595 66263 72650 79153 85807 93115 100874 109316 118470 Source: Philippine Energy Plan 2003-2012

Table C.2b: System Peak Demand Forecasts for the High Economic Growth

Scenario (MW)

YEAR LUZON VISAYAS MINDANAO NATIONAL Non-Coincident Peak

2003 6,788 1,014 1,081 8,883 2004 7,357 1,099 1,176 9,633 2005 7,994 1,194 1,281 10,469 2006 8,711 1,313 1,400 11,424 2007 9,438 1,428 1,512 12,378 2008 10,186 1,543 1,630 13,359 2009 10,992 1,675 1,757 14,423 2010 11,862 1,809 1,891 15,562 2011 12,804 1,953 2,034 16,790 2012 13,815 2,106 2,186 18,106

Annual Ave. G.R.

(2003 - 2007) 8.59% 8.94% 8.73% 8.65% (2008 - 2012) 7.92% 8.09% 7.60% 7.90% (2003 - 2012) 8.22% 8.46% 8.13% 8.23%




Table C.2c: Electricity Sales Forecasts for the High Economic Growth Scenario (GWh)

YEAR

2003 39,814 5,355 6,300 51,469 2004 43,156 5,807 6,851 55,814 2005 46,888 6,305 7,465 60,658 2006 51,094 6,938 8,155 66,187 2007 55,363 7,542 8,805 71,711 2008 59,746 8,149 9,497 77,392 2009 64,474 8,848 10,233 83,555 2010 69,578 9,555 11,015 90,148 2011 75,104 10,314 11,847 97,266 2012 81,033 11,124 12,732 104,888

Annual Ave. G.R.

(2003 - 2007) 8.59% 8.94% 8.73% 8.64% (2008 - 2012) 7.92% 8.09% 7.60% 7.90% (2003 - 2012) 8.22% 8.46% 8.13% 8.23%




Table C.2d: DOE Plan for Installed Capacity for the High Economic Growth Scenario

(MW)

Year Fuel Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil-based 2,443 2,443 2,443 2,443 2,443 2,443 2,233 1,583 1,583 1,583 Coal 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758

Local 450 450 450 450 450 450 450 450 450 450

Imported 3,308 3,308 3,308 3,308 3,308 3,308 3,308 3,308 3,308 3,308

Natural Gas 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763

Hydro 1,510 1,860 2,205 2,205 2,205 2,205 2,205 2,205 2,205 2,205 Geothermal 907 907 907 907 907 907 907 907 907 907 NRE

Wind - 65 65 65 65 65 65 65 65 65

Others

Baseload - - - - - - - 900 1,800 1,800

Intermediate - - - - - 300 1,500 2,700 3,300 3,300

Peaking - - - - - - - - - 750

Luzo

n

LUZON TOTAL 11,381 11,796 12,141 12,141 12,141 12,441 13,431 14,881 16,381 17,131

Oil-based 468 431 281 281 281 281 281 281 182 182

Coal 205 205 205 205 205 205 205 205 205 205

Local 150 150 150 150 150 150 150 150 150 150

Imported 55 55 55 55 55 55 55 55 55 55

Natural Gas - - - - - - - - - -

Hydro 12 12 12 12 12 12 12 12 12 12 Geothermal 919 959 959 959 959 959 959 959 959 959

NRE

Wind - - - - - - - - - -

Others Baseload - - - - 100 200 400 550 650 750 Intermediate - - 200 250 300 350 500 550 650 650

Peaking - - - - - - - - - -

Vis

ayas

VISAYAS TOTAL 1,604 1,607 1,657 1,707 1,857 2,007 2,357 2,557 2,658 2,758

Oil-based 546 616 616 616 616 616 616 616 616 616 Coal - - - 200 200 200 200 200 200 200

Local - - - - - - - - - -

Imported - - - 200 200 200 200 200 200 200

Natural Gas - - - - - - - - - -


Wind - - - - - - - - - -

Others

Baseload - - - - 50 250 300 400 550 650

Intermediate - - 100 100 100 150 150 250 300 300

Peaking - - - - - - - - - -

Min

dan

ao

MINDANAO TOTAL 1,647 1,717 1,817 2,017 2,067 2,317 2,367 2,567 2,767 2,867



Year Fuel Type

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Oil-based 3,457 3,490 3,340 3,340 3,340 3,340 3,130 2,480 2,381 2,381

Coal 3,963 3,963 3,963 4,163 4,163 4,163 4,163 4,163 4,163 4,163

Local 600 600 600 600 600 600 600 600 600 600

Imported 3,363 3,363 3,363 3,563 3,563 3,563 3,563 3,563 3,563 3,563

Natural Gas 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 2,763 Hydro 2,519 2,869 3,214 3,214 3,214 3,214 3,214 3,214 3,214 3,214

Geothermal 1,930 1,970 1,970 1,970 1,970 1,970 1,970 1,970 1,970 1,970 NRE

Wind - 65 65 65 65 65 65 65 65 65

Others

Baseload - - - - 150 450 700 1,850 3,000 3,200

Intermediate - - 300 350 400 800 2,150 3,500 4,250 4,250

Peaking - - - - - - 0 0 0 750

Phi

lippi

nes

PHILIPPINES TOTAL 14,632 15,120 15,615 15,865 16,065 16,765 18,155 20,005 21,806 22,756



Table C.2e: DOE Plan for Power Plant Line-Up for the High Economic Growth Scenario


LUZON VISAYAS MINDANAO PHILIPPINES

YEAR PLANT ADDITION MW

capacity installed

MW PLANT ADDITION MW capacity

installed MW PLANT ADDITION MW

capacity installed

MW cumulative total

Kalayaan 3&4 350 345 Uprating of Leyte-Bohol Interconnection from 35 MW to 100 MW

40 0 385

PNOC_EDC Wind 40 from 35 MW to 100 MW

Transfer of Hopewell GT to Mindanao (70 MW)

-70 Mambucal Geo 40 2004

Northwind 25

San Roque Hydro 345 690 Uprating of Leyte-Cebu Interconnection from 200 MW to 400 MW

240 Hopewell GT from Luzon

70 170 1,100

Panay Midrange 150 Midrange Plant 100

2005

Negros Midrange 50

2006 690 Panay Midrange 50 290 Mindanao Coal 200 370 1,350

690 Panay Baseload 100 440 Baseload Plant 50 420 1,550 2007

Panay Midrange 50

Midrange 300 990 Cebu Baseload 50 590 Baseload Plant 200 670 2,250

Cebu Midrange 50 Midrange Plant 50 2008

Negros Baseload 50

Midrange 1,200 2,190 Cebu Baseload 100 940 Baseload Plant 50 720 3,850

Panay Baseload 50

Negros Baseload 50

Cebu Midrange 50

2009

Bohol Midrange 100

Baseload Plant 900 4,290 Cebu Baseload 150 1,140 Baseload Plant 100 870 6,300

Midrange 1,200 Bohol Midrange 50 Midrange Plant 50 2010

Baseload Plant 900 5,790 Cebu Baseload 50 1,340 Baseload Plant 150 1,070 8,200

Midrange 600 Negros Baseload 50 Midrange Plant 50 2011

Cebu Midrange 100

Peaking 750 6,540 Cebu Baseload 50 1,440 Baseload Plant 100 1,170 9,150 2012 Panay Baseload 50



Table C.2f: Total CO2 Emissions by Fuel Type for the DOE Plan for the High Economic Growth Scenario


2003 641,320 10,258,239 5,897,849 2,253,435 19,050,843

2004 681,000 10,234,891 7,106,226 2,840,055 20,862,172

2005 684,450 11,534,207 7,704,891 2,863,793 22,787,341

2006 685,585 14,125,779 8,208,124 3,877,529 26,897,017

2007 685,722 15,734,042 8,744,051 5,664,859 30,828,673

2008 685,722 17,792,965 8,934,033 7,785,862 35,198,582

2009 685,585 19,370,822 8,951,264 11,565,124 40,572,796

2010 685,722 23,620,609 8,921,220 11,743,322 44,970,873

2011 685,767 28,167,941 8,820,927 12,060,537 49,735,173

2012 685,812 30,073,206 8,890,293 16,645,518 56,294,829

Total for period 6,806,686 180,912,701 82,178,879 77,300,035 347,198,300

Table C.2g: Total SOx Emissions by Fuel Type for the DOE Plan for the High Economic Growth Scenario


2003 - 139,808 104 27,299 167,211

2004 - 139,490 126 33,639 173,254

2005 - 157,198 136 34,473 191,808

2006 - 192,518 145 51,202 243,866

2007 - 214,437 155 74,094 288,686

2008 - 242,498 158 104,396 347,052

2009 - 264,002 159 154,784 418,945

2010 - 321,922 158 157,630 479,710

2011 - 383,897 156 162,688 546,741

2012 - 409,864 157 221,296 631,317

Total for period - 2,465,636 1,456 1,021,499 3,488,590

Table C.2h: Total NOx Emissions by Fuel Type for the DOE Plan for the High Economic Growth Scenario


2003 - 79,351 21,939 9,774 111,064

2004 - 79,170 26,434 12,895 118,498

2005 - 89,221 28,661 12,824 130,706

2006 - 109,267 30,533 13,877 153,677

2007 - 121,708 32,526 20,653 174,887

2008 - 137,634 33,233 27,043 197,909

2009 - 149,839 33,297 41,180 224,316

2010 - 182,713 33,185 42,014 257,912

2011 - 217,888 32,812 42,683 293,383

2012 - 232,625 33,070 61,250 326,945

Total for period - 1,399,415 305,689 284,194 1,989,297



Table C.2i: Total CO Emissions by Fuel Type for the DOE Plan for the High



2003 - 10,013 8,776 2,962 21,751

2004 - 9,991 10,573 3,719 24,283

2005 - 11,259 11,464 4,122 26,845

2006 - 13,788 12,213 5,529 31,530

2007 - 15,358 13,010 7,831 36,199

2008 - 17,368 13,293 11,691 42,352

2009 - 18,908 13,319 18,574 50,801

2010 - 23,057 13,274 19,701 56,032

2011 - 27,495 13,125 20,452 61,072

2012 - 29,355 13,228 28,027 70,610

Total for period - 176,593 122,275 122,608 421,476

Table C.2j: Total CH4 Emissions by Fuel Type for the DOE Plan for the High



2003 - 105 145 33 283

2004 - 105 175 42 321

2005 - 118 190 43 351

2006 - 145 202 55 402

2007 - 161 215 80 456

2008 - 182 220 112 514

2009 - 198 220 171 589

2010 - 242 219 176 638

2011 - 288 217 182 687

2012 - 308 219 252 778

Total for period - 1,851 2,022 1,145 5,018

Table C.2k: Total NMVOC Emissions by Fuel Type for the DOE Plan for the High Economic Growth Scenario


2003 - 378 1,045 177 1,599

2004 - 377 1,259 222 1,858

2005 - 425 1,365 250 2,039

2006 - 520 1,454 332 2,306

2007 - 580 1,549 468 2,596

2008 - 655 1,583 707 2,945

2009 - 714 1,586 1,136 3,435

2010 - 870 1,580 1,212 3,662

2011 - 1,038 1,562 1,260 3,860

2012 - 1,108 1,575 1,726 4,409

Total for period - 6,664 14,557 7,489 28,710



Table C.2l: Total N2O Emissions by Fuel Type for the DOE Plan for the High Economic Growth Scenario


2003 - 567 313 90 970

2004 - 566 378 112 1,055

2005 - 637 409 114 1,160

2006 - 780 436 159 1,376

2007 - 869 465 232 1,566

2008 - 983 475 322 1,779

2009 - 1,070 476 478 2,024

2010 - 1,305 474 486 2,265

2011 - 1,556 469 500 2,525

2012 - 1,662 472 686 2,820

Total for period - 9,996 4,367 3,176 17,539

Table C.2m: Total Particulate Emissions by Fuel Type for the DOE Plan for the

High Economic Growth Scenario (tonne)


2003 - 16,626 836 2,215 19,677

2004 - 16,588 1,007 2,898 20,493

2005 - 18,694 1,092 2,688 22,474

2006 - 22,894 1,163 3,074 27,131

2007 - 25,501 1,239 4,691 31,430

2008 - 28,838 1,266 5,709 35,813

2009 - 31,395 1,268 7,991 40,655

2010 - 38,283 1,264 7,688 47,235

2011 - 45,653 1,250 7,697 54,599

2012 - 48,741 1,260 11,131 61,132

Total for period - 293,211 11,645 55,783 360,639

Table C.1n: Environmental Emissions per Unit Generation

(tonne/kWh) Environmental Emissions

Year CO2 SOX NOX CO CH4 NMVOC N2O Particulates

2003 370.14 3.25 2.16 0.42 0.01 0.03 0.02 0.38

2004 373.78 3.10 2.12 0.44 0.01 0.03 0.02 0.37

2005 375.67 3.16 2.15 0.44 0.01 0.03 0.02 0.37

2006 406.38 3.68 2.32 0.48 0.01 0.03 0.02 0.41

2007 429.91 4.03 2.44 0.50 0.01 0.04 0.02 0.44

2008 454.81 4.48 2.56 0.55 0.01 0.04 0.02 0.46

2009 485.58 5.01 2.68 0.61 0.01 0.04 0.02 0.49

2010 498.86 5.32 2.86 0.62 0.01 0.04 0.03 0.52

2011 511.34 5.62 3.02 0.63 0.01 0.04 0.03 0.56

2012 536.71 6.02 3.12 0.67 0.01 0.04 0.03 0.58

Appendix D Clean Power Development Options

2003-2012

Appendix D POWER SWITCH! Scenarios and Strategies for Clean Power Development in the Philippines


APPENDIX D.1 LOW ECONOMIC GROWTH

SCENARIO- MODERATE CLEAN POWER

DEVELOPMENT OPTION (LEGS-MCPD)



Table D.1a: Installed Capacity

(MW) Year

Fuel Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil-based 2,491 2,491 2,491 2,491 2,491 1,871 1,661 1,011 1,011 1,011 Coal 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,583 4,383 5,283 5,583 5,983 Geothermal 907 907 907 907 907 947 977 1,227 1,267 1,287 Hydro 1,510 1,860 2,205 2,205 2,205 2,404 2,404 2,422 2,797 3,211 Biomass - - - - - - - - - - Wind - 25 25 65 65 130 235 400 525 650

Luzo

n

LUZON TOTAL 11,429 11,804 12,149 12,189 12,189 12,694 13,419 14,101 14,941 15,901 Oil-based 545 509 559 559 609 609 609 629 605 655 Coal 205 205 205 205 205 205 205 205 205 205 Natural Gas - - - - - - - - - - Geothermal 916 956 956 956 956 986 1,066 1,116 1,216 1,266 Hydro 12 12 12 12 12 12 12 37 63 73 Biomass - - - 50 80 80 80 100 100 100 Wind - - - - - 20 40 60 80 100

Vis

ayas

VISAYAS TOTAL 1,678 1,682 1,732 1,782 1,862 1,912 2,012 2,146 2,269 2,398

Oil-based 547 547 647 647 647 647 647 647 647 647 Coal - - - 200 250 250 250 250 250 250 Natural Gas - - - - - - - - - - Geothermal 108 108 108 108 108 128 148 188 228 228 Hydro 997 997 997 997 997 1,255 1,415 1,467 1,558 1,658 Biomass - - - - - 12 12 12 12 12 Wind - - - - - 20 40 60 80 100

Min

dana

o

MINDANAO TOTAL 1,652 1,652 1,752 1,952 2,002 2,312 2,512 2,624 2,775 2,895 Oil-based 3,583 3,547 3,697 3,697 3,747 3,127 2,917 2,287 2,263 2,313 Coal 3,963 3,963 3,963 4,163 4,213 4,213 4,213 4,213 4,213 4,213 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,583 4,383 5,283 5,583 5,983 Geothermal 1,931 1,971 1,971 1,971 1,971 2,061 2,191 2,531 2,711 2,781 Hydro 2,519 2,869 3,214 3,214 3,214 3,671 3,831 3,925 4,418 4,942 Biomass - - - 50 80 92 92 112 112 112 Wind - 25 25 65 65 170 315 520 685 850

Phi

lippi

nes




Table D.1b: Annual Capacity Additions (MW)

Table D.1c: Power Generation (GWh)

Table D.1d: Carbon Dioxide Emissions by Fuel Type (tonne)

Oil-based Coal Natural Gas Geothermal Hydro Biomass Wind Total Addition

Current Installed 3,583 3,963 2,763 1,931 2,519 0 0

2003 0 0 0 0 0 0 0 0

2004 0 0 0 40 350 0 25 4152005 300 0 0 0 345 0 0 645

2006 0 200 0 0 0 50 40 290

2007 50 50 0 0 0 30 0 130

2008 0 0 820 90 457 12 105 1,484

2009 0 0 800 130 160 0 145 1,235

2010 20 0 900 340 94 20 205 1,579

2011 75 0 300 180 493 0 165 1,213

2012 50 0 400 70 524 0 165 1,209

Year Fuel Type


2003 2,720 18,629 13,349 14,121 6,324 0 0 55,143

2004 3,247 18,087 16,017 14,975 6,893 0 153 59,372

2005 3,952 19,953 17,141 15,054 7,928 0 153 64,181

2006 3,523 24,659 18,210 15,092 7,943 0 153 69,580

2007 4,764 27,550 19,415 15,098 7,968 0 153 74,948

2008 6,590 30,521 20,074 15,099 8,001 0 153 80,438

2009 1,596 27,906 24,943 14,085 16,343 645 843 86,360

2010 1,706 27,857 27,374 16,710 16,813 785 1,391 92,636

2011 1,652 27,589 30,060 18,100 19,271 785 1,831 99,289

2012 1,915 27,835 33,097 18,641 21,884 785 2,272 106,430

Fuel TypeYear


2003 2,125,011 10,114,896 5,897,849 641,093 - - - 18,778,850

2004 2,536,797 9,820,609 7,076,624 679,865 - - - 20,113,894

2005 3,158,821 10,833,782 7,573,229 683,452 - - - 22,249,284

2006 2,816,776 13,388,975 8,045,534 685,177 - - - 24,936,462

2007 3,760,465 14,958,687 8,577,927 685,449 - - - 27,982,528

2008 5,275,644 16,571,837 8,869,086 685,495 - - - 31,402,061

2009 1,089,937 15,151,783 11,020,477 639,456 - - - 27,901,654

2010 1,174,313 15,125,576 12,094,216 758,653 - - - 29,152,757

2011 1,133,148 14,979,784 13,281,263 821,757 - - - 30,215,951

2012 1,333,908 15,113,383 14,623,101 846,297 - - - 31,916,689

Year Fuel Type



Table D.1e: Environmental Emissions (tonne)

Table D.1f: Environmental Emission per Unit Generation (tonne/GWh)

Table D.1g: Generation Cost


2003 18,778,850 159,289 112,712 21,362 282 1,581 952 19,927

2004 20,113,894 159,429 117,251 23,355 314 1,810 1,013 20,140

2005 22,249,284 181,988 128,937 26,241 346 2,008 1,122 22,1602006 24,936,462 213,151 148,599 28,966 379 2,157 1,275 25,979

2007 27,982,528 243,113 168,897 32,363 423 2,373 1,424 29,973

2008 31,402,061 283,422 189,317 36,758 470 2,630 1,589 33,952

2009 27,901,654 217,840 164,380 32,442 443 2,584 775,147 27,536

2010 29,152,757 217,726 169,137 34,110 470 2,779 943,397 27,839

2011 30,215,951 215,650 171,954 35,687 497 2,981 943,451 27,677

2012 31,916,689 218,029 180,275 38,044 536 3,238 943,535 28,542


CO2 SOX NOX CO CH 4 NMVOC N2O Particulates

2003 340.55 2.89 2.04 0.39 0.01 0.03 0.02 0.36

2004 338.78 2.69 1.97 0.39 0.01 0.03 0.02 0.34

2005 346.66 2.84 2.01 0.41 0.01 0.03 0.02 0.35

2006 358.39 3.06 2.14 0.42 0.01 0.03 0.02 0.37

2007 373.36 3.24 2.25 0.43 0.01 0.03 0.02 0.40

2008 390.39 3.52 2.35 0.46 0.01 0.03 0.02 0.42

2009 323.09 2.52 1.90 0.38 0.01 0.03 8.98 0.32

2010 314.70 2.35 1.83 0.37 0.01 0.03 10.18 0.30

2011 304.32 2.17 1.73 0.36 0.01 0.03 9.50 0.28

2012 299.88 2.05 1.69 0.36 0.01 0.03 8.87 0.27

Year Environmental Emissions

US$/kWh PhP/kWh

2003 0.06 3.04

2004 0.06 3.10

2005 0.06 3.12

2006 0.06 3.05

2007 0.06 3.05

2008 0.06 3.20

2009 0.06 3.06

2010 0.06 3.10

2011 0.06 3.19

2012 0.06 3.31

Year Generation Cost



APPENDIX D.2 LOW ECONOMIC GROWTH

SCENARIO- AGGRESSIVE CLEAN POWER

DEVELOPMENT OPTION (LEGS-ACPD)




(MW)

Year Fuel Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil-based 2,491 2,491 2,491 2,491 2,491 1,871 1,661 1,011 1,011 1,011 Coal 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,063 3,778 4,548 4,968 5,468 Geothermal 907 907 907 907 907 947 977 1,227 1,267 1,287 Hydro 1,510 1,860 2,205 2,205 2,205 2,404 2,404 2,422 2,797 3,211 Biomass - - - - - 10 25 25 25 25 Wind - 25 25 65 65 665 1,265 1,865 2,465 3,065

Luzo

n


Vis

ayas

VISAYAS TOTAL 1,678 1,682 1,732 1,782 1,862 1,922 2,042 2,136 2,283 2,413

Oil-based 547 547 647 647 647 647 647 647 647 647 Coal - - - 200 250 250 250 250 250 250 Natural Gas - - - - - - - - - - Geothermal 108 108 108 108 108 128 148 188 228 228 Hydro 997 997 997 997 997 1,255 1,415 1,467 1,558 1,658 Biomass - - - - - 12 12 12 12 12 Wind - - - - - 33 106 179 262 335

Min

dana

o

MINDANAO TOTAL 1,652 1,652 1,752 1,952 2,002 2,325 2,578 2,743 2,957 3,130 Oil-based 3,583 3,547 3,697 3,697 3,747 3,127 2,917 2,267 2,168 2,168 Coal 3,963 3,963 3,963 4,163 4,213 4,213 4,213 4,213 4,213 4,213 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,063 3,778 4,548 4,968 5,468 Geothermal 1,931 1,971 1,971 1,971 1,971 2,071 2,221 2,561 2,841 2,991 Hydro 2,519 2,869 3,214 3,214 3,214 3,671 3,831 3,925 4,418 4,932 Biomass - - - 50 80 102 117 117 117 117 Wind - 25 25 65 65 718 1,411 2,104 2,807 3,480

Phi

lippi

nes





*includes capacities of diesel engines used as ancillary to wind power plants



Oil-based* Coal Natural Gas Geothermal Hydro Biomass Wind Total Addition

Currently Installed 3,583 3,963 2,763 1,931 2,519 0 0

2003 0 0 0 0 0 0 0 0

2004 0 0 0 40 350 0 25 415

2005 300 0 0 0 345 0 0 645

2006 0 200 0 0 0 50 40 290

2007 50 50 0 0 0 30 0 130

2008 548 0 300 100 457 22 653 2,079

2009 548 0 715 150 160 15 693 2,281

2010 488 0 770 340 94 0 693 2,385

2011 538 0 420 280 492 0 703 2,433

2012 528 0 500 150 514 0 673 2,365

Year Fuel Type


2003 2,720 18,629 13,349 14,121 6,324 0 0 55,143

2004 3,247 18,087 16,017 14,975 6,893 0 153 59,372

2005 3,952 19,953 17,141 15,054 7,928 0 153 64,181

2006 3,523 24,659 18,210 15,092 7,943 0 153 69,580

2007 4,764 27,550 19,415 15,098 7,968 0 153 74,948

2008 4,385 26,375 18,341 13,158 15,545 715 1,919 80,437

2009 3,654 24,746 22,708 14,317 16,345 820 3,770 86,360

2010 1,704 23,534 27,198 16,942 16,815 820 5,622 92,636

2011 1,651 21,655 29,885 19,104 19,270 436 7,287 99,289

2012 1,915 20,245 32,922 20,263 21,741 259 9,085 106,430

Year Fuel Type


2003 2,125,011 10,114,896 5,897,849 641,093 - - - 18,778,850

2004 2,536,797 9,820,609 7,076,624 679,865 - - - 20,113,894

2005 3,158,821 10,833,782 7,573,229 683,452 - - - 22,249,284

2006 2,816,776 13,388,975 8,045,534 685,177 - - - 24,936,462

2007 3,760,465 14,958,687 8,577,927 685,449 - - - 27,982,528

2008 3,157,136 14,320,647 8,103,361 597,386 - - - 26,178,529

2009 2,557,709 13,436,477 10,032,732 649,973 - - - 26,676,891

2010 1,172,790 12,778,369 12,016,809 769,170 - - - 26,737,138

2011 1,132,387 11,758,117 13,203,856 867,332 - - - 26,961,692

2012 1,333,908 10,992,082 14,545,694 919,919 - - - 27,791,602

Year Fuel Type







2003 18,778,850 159,289 112,712 21,362 282 1,581 952 19,927

2004 20,113,894 159,429 117,251 23,355 314 1,810 1,013 20,140

2005 22,249,284 181,988 128,937 26,241 346 2,008 1,122 22,1602006 24,936,462 213,151 148,599 28,966 379 2,157 1,275 25,979

2007 27,982,528 243,113 168,897 32,363 423 2,373 1,424 29,973

2008 26,178,529 232,065 155,223 29,376 389 2,154 859,125 28,010

2009 26,676,891 214,539 151,546 30,475 418 2,407 985,301 26,086

2010 26,737,138 185,731 150,675 31,702 444 2,679 985,311 24,020

2011 26,961,692 171,739 146,737 32,426 462 2,849 525,150 22,442

2012 27,791,602 161,859 148,107 33,906 492 3,073 312,583 21,852



2003 340.55 2.89 2.04 0.39 0.01 0.03 0.02 0.36

2004 338.78 2.69 1.97 0.39 0.01 0.03 0.02 0.34

2005 346.66 2.84 2.01 0.41 0.01 0.03 0.02 0.35

2006 358.39 3.06 2.14 0.42 0.01 0.03 0.02 0.37

2007 373.36 3.24 2.25 0.43 0.01 0.03 0.02 0.40

2008 325.45 2.89 1.93 0.37 0.00 0.03 10.68 0.35

2009 308.90 2.48 1.75 0.35 0.00 0.03 11.41 0.30

2010 288.63 2.00 1.63 0.34 0.00 0.03 10.64 0.26

2011 271.54 1.73 1.48 0.33 0.00 0.03 5.29 0.23

2012 261.13 1.52 1.39 0.32 0.00 0.03 2.94 0.21


US$/kWh PhP/kWh

2003 0.06 3.04

2004 0.06 3.10

2005 0.06 3.12

2006 0.06 3.05

2007 0.06 3.05

2008 0.05 3.01

2009 0.06 3.15

2010 0.06 3.23

2011 0.06 3.38

2012 0.06 3.54




APPENDIX D.3 HIGH ECONOMIC GROWTH

SCENARIO- MODERATE CLEAN POWER

DEVELOPMENT OPTION (HEGS-MCPD)




(MW)

Year Fuel Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil-based 2,491 2,491 2,491 2,491 2,491 1,871 1,661 1,011 1,011 1,011 Coal 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,583 4,733 6,433 7,183 7,383 Geothermal 907 907 907 907 907 947 977 1,227 1,267 1,287 Hydro 1,510 1,860 2,205 2,205 2,205 2,404 2,404 2,422 2,797 3,211 Biomass - - - - - - - - - - Wind - 25 25 65 65 130 275 440 565 690

Luzo

n


Vis

ayas

VISAYAS TOTAL 1,678 1,682 1,732 1,832 1,862 1,922 2,122 2,311 2,534 2,663

Oil-based 547 547 717 717 717 717 717 717 717 717 Coal - - - 200 200 200 200 200 200 200 Natural Gas - - - - - - - - - - Geothermal 108 108 108 108 108 128 148 188 228 228 Hydro 997 997 997 997 997 1,367 1,467 1,658 1,658 1,687 Biomass - - - - - - - - - - Wind - - - - - - 49 69 89 109

Min

dana

o

MINDANAO TOTAL 1,652 1,652 1,822 2,022 2,022 2,412 2,581 2,832 2,892 2,941 Oil-based 3,583 3,547 3,767 3,817 3,817 3,197 2,987 2,357 2,333 2,383 Coal 3,963 3,963 3,963 4,163 4,163 4,163 4,163 4,163 4,163 4,163 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,583 4,733 6,433 7,183 7,383 Geothermal 1,931 1,971 1,971 1,971 1,971 2,071 2,301 2,691 2,971 3,041 Hydro 2,519 2,869 3,214 3,214 3,214 3,783 3,883 4,116 4,518 4,971 Biomass - - - 50 80 80 80 100 100 100 Wind - 25 25 65 65 150 364 574 739 904

Phi

lippi

nes




Table D.3b: Annual Capacity Additions

(MW)



Oil-based Coal Natural Gas Geothermal Hydro Biomass Wind Total Addition

Currently Installed 3,583 3,963 2,763 1,931 2,519 0 0 14,759

2003 0 0 0 0 0 0 0 0

2004 0 0 0 40 350 0 25 415

2005 370 0 0 0 345 0 0 715

2006 50 200 0 0 0 50 40 340

2007 0 0 0 0 0 30 0 30

2008 0 0 820 100 569 0 85 1,574

2009 0 0 1,150 230 100 0 214 1,694

2010 20 0 1,700 390 233 20 210 2,573

2011 75 0 750 280 402 0 165 1,672

2012 50 0 200 70 453 0 165 938

Year Fuel Type


2003 2,864 18,893 13,349 14,126 6,324 0 0 55,556

2004 3,615 18,850 16,084 15,000 6,893 0 153 60,595

2005 4,420 21,243 17,439 15,076 7,932 0 153 66,263

2006 4,850 26,016 18,578 15,101 7,952 0 153 72,650

2007 7,107 28,978 19,791 15,104 8,020 0 153 79,153

2008 4,463 27,973 23,146 13,158 16,103 561 402 85,807

2009 2,646 27,479 29,919 14,934 16,602 561 974 93,115

2010 2,252 27,209 33,465 17,946 17,766 701 1,535 100,874

2011 2,879 26,964 37,503 20,108 19,769 343 1,749 109,315

2012 3,747 26,964 42,065 20,649 22,028 701 2,317 118,471

Year Fuel Type


2003 2,252,722 10,258,239 5,897,849 641,320 - - - 19,050,130

2004 2,840,768 10,234,891 7,106,226 681,000 - - - 20,862,885

2005 3,484,190 11,534,207 7,704,891 684,450 - - - 23,407,739

2006 3,897,496 14,125,779 8,208,124 685,585 - - - 26,916,984

2007 5,664,859 15,734,042 8,744,051 685,722 - - - 30,828,673

2008 3,128,877 15,188,496 10,226,404 597,386 - - - 29,141,163

2009 1,855,858 14,920,208 13,218,671 678,019 - - - 30,672,756

2010 1,555,110 14,773,321 14,785,600 814,745 - - - 31,928,777

2011 2,033,367 14,640,458 16,569,537 912,907 - - - 34,156,269

2012 2,695,991 14,640,458 18,585,272 937,448 - - - 36,859,169

YearFuel Type




Table D.3f: Environmental Emission per Unit Generation

(tonne/GWh)



2003 19,050,130 167,202 111,062 21,750 283 1,599 970 19,676

2004 20,862,885 173,264 118,500 24,284 321 1,858 1,055 20,494

2005 23,407,739 200,294 132,447 27,343 358 2,065 1,186 23,096

2006 26,916,984 244,139 153,733 31,546 402 2,307 1,377 27,151

2007 30,828,673 288,686 174,887 36,199 456 2,596 1,566 31,430

2008 29,141,163 239,636 173,734 33,304 453 2,559 674,268 43,677

2009 30,672,756 217,873 179,755 36,428 509 3,024 674,359 42,506

2010 31,928,777 215,099 181,266 38,272 540 3,274 842,617 45,166

2011 34,156,269 214,591 191,684 41,344 592 3,620 413,372 37,711

2012 36,859,169 216,389 207,421 45,101 655 4,024 842,845 48,099



2003 370.13 3.25 2.16 0.42 0.01 0.03 0.02 0.38

2004 373.79 3.10 2.12 0.44 0.01 0.03 0.02 0.37

2005 385.90 3.30 2.18 0.45 0.01 0.03 0.02 0.38

2006 406.68 3.69 2.32 0.48 0.01 0.03 0.02 0.41

2007 429.91 4.03 2.44 0.50 0.01 0.04 0.02 0.44

2008 376.54 3.10 2.24 0.43 0.01 0.03 8.71 0.56

2009 367.10 2.61 2.15 0.44 0.01 0.04 8.07 0.51

2010 354.18 2.39 2.01 0.42 0.01 0.04 9.35 0.50

2011 351.17 2.21 1.97 0.43 0.01 0.04 4.25 0.39

2012 351.41 2.06 1.98 0.43 0.01 0.04 8.04 0.46


US$/kWh PhP/kWh

2003 0.0549 3.0175

2004 0.0554 3.0495

2005 0.0555 3.0536

2006 0.0544 2.9923

2007 0.0542 2.9785

2008 0.0541 2.9744

2009 0.0561 3.0868

2010 0.0578 3.1790

2011 0.0603 3.3138

2012 0.0622 3.4193




APPENDIX D.4 HIGH ECONOMIC GROWTH

SCENARIO- AGGRESSIVE CLEAN POWER

DEVELOPMENT OPTION (HEGS-ACPD)



Table D.4a: Installed Capacity (MW)

Year

Fuel Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil-based 2,491 2,491 2,491 2,491 2,491 1,871 1,661 1,011 1,011 1,011 Coal 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 3,758 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,063 3,783 4,983 5,333 5,333 Geothermal 907 907 907 907 907 947 977 1,227 1,267 1,287 Hydro 1,510 1,860 2,205 2,205 2,205 2,404 2,404 2,422 2,797 3,211 Biomass - - - - - 15 15 25 25 25 Wind - 25 25 65 65 665 1,265 1,865 2,465 3,065

Luzo

n


Vis

ayas

VISAYAS TOTAL 1,678 1,682 1,732 1,832 1,862 1,942 2,122 2,336 2,548 2,678 Oil-based 547 547 717 717 717 717 717 717 717 717 Coal - - - 200 200 200 200 200 200 200 Natural Gas - - - - - - - - - - Geothermal 108 108 108 108 108 128 148 188 228 228 Hydro 997 997 997 997 997 1,339 1,540 1,687 1,687 1,687 Biomass - - - - - - - - - 12 Wind - - - - - 76 152 186 262 336

Min

dana

o

MINDANAO TOTAL 1,652 1,652 1,822 2,022 2,022 2,460 2,757 2,978 3,094 3,180 Oil-based 3,583 3,547 3,767 3,817 3,817 3,197 2,987 2,337 2,238 2,238 Coal 3,963 3,963 3,963 4,163 4,163 4,163 4,163 4,163 4,163 4,163 Natural Gas 2,763 2,763 2,763 2,763 2,763 3,063 3,783 4,983 5,333 5,333 Geothermal 1,931 1,971 1,971 1,971 1,971 2,071 2,221 2,561 2,841 2,991 Hydro 2,519 2,869 3,214 3,214 3,214 3,765 3,966 4,155 4,557 4,971 Biomass - - - 50 80 95 95 125 125 137 Wind - 25 25 65 65 771 1,527 2,281 3,041 3,715

Phi

lippi

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*includes capacities of diesel engines used as ancillary to wind power plants



Oil-based* Coal Natural Gas Geothermal Hydro Biomass Wind Total Addition

Currently Installed 3,583 3,963 2,763 1,931 2,519 0 0

2003 0 0 0 0 0 0 0 0

2004 0 0 0 40 350 0 25 4152005 370 0 0 0 345 0 0 715

2006 50 200 0 0 0 50 40 340

2007 0 0 0 0 0 30 0 30

2008 621 0 300 100 551 15 706 2,292

2009 582 0 720 150 201 0 756 2,409

2010 549 0 1,200 340 189 30 754 3,062

2011 595 0 350 280 402 0 760 2,387

2012 529 0 0 150 414 12 674 1,779

Fuel TypeYear


2003 2,864 18,893 13,349 14,126 6,324 0 0 55,556

2004 3,615 18,850 16,084 15,000 6,893 0 153 60,595

2005 4,420 21,243 17,439 15,076 7,932 0 153 66,263

2006 4,850 26,016 18,578 15,101 7,952 0 153 72,650

2007 7,107 28,978 19,791 15,104 8,020 0 153 79,153

2008 6,549 26,315 21,045 13,158 16,014 666 2,060 85,807

2009 6,186 24,760 26,091 14,317 17,016 666 4,080 93,115

2010 2,471 23,239 33,290 16,942 17,960 876 6,095 100,874

2011 3,109 21,426 36,953 19,104 19,963 876 7,883 109,315

2012 8,600 20,012 36,953 20,263 22,030 960 9,653 118,471

Year Fuel Type


2003 2,252,722 10,258,239 5,897,849 641,320 - - - 19,050,130

2004 2,840,768 10,234,891 7,106,226 681,000 - - - 20,862,885

2005 3,484,190 11,534,207 7,704,891 684,450 - - - 23,407,739

2006 3,897,496 14,125,779 8,208,124 685,585 - - - 26,916,984

2007 5,664,859 15,734,042 8,744,051 685,722 - - - 30,828,673

2008 4,630,538 14,288,115 9,298,103 597,386 - - - 28,814,142

2009 4,335,382 13,443,735 11,527,419 649,973 - - - 29,956,508

2010 1,650,538 12,618,216 14,708,193 769,170 - - - 29,746,118

2011 2,209,193 11,633,479 16,326,639 867,332 - - - 31,036,644

2012 6,398,867 10,865,993 16,326,639 919,919 - - - 34,511,418

Year Fuel Type







2003 19,050,130 167,202 111,062 21,750 283 1,599 970 19,676

2004 20,862,885 173,264 118,500 24,284 321 1,858 1,055 20,494

2005 23,407,739 200,294 132,447 27,343 358 2,065 1,186 23,0962006 26,916,984 244,139 153,733 31,546 402 2,307 1,377 27,151

2007 30,828,673 288,686 174,887 36,199 456 2,596 1,566 31,430

2008 28,814,142 246,720 168,625 32,258 439 2,425 800,374 46,263

2009 29,956,508 234,679 166,882 34,465 479 2,771 800,438 44,485

2010 29,746,118 188,212 164,106 36,294 517 3,196 1,052,740 45,738

2011 31,036,644 174,073 170,515 38,248 559 3,479 1,052,785 45,997

2012 34,511,418 174,754 212,654 42,291 634 3,750 1,153,777 56,355



2003 370.13 3.25 2.16 0.42 0.01 0.03 0.02 0.38

2004 373.79 3.10 2.12 0.44 0.01 0.03 0.02 0.37

2005 385.90 3.30 2.18 0.45 0.01 0.03 0.02 0.38

2006 406.68 3.69 2.32 0.48 0.01 0.03 0.02 0.41

2007 429.91 4.03 2.44 0.50 0.01 0.04 0.02 0.44

2008 372.31 3.19 2.18 0.42 0.01 0.03 10.34 0.60

2009 358.52 2.81 2.00 0.41 0.01 0.03 9.58 0.53

2010 329.97 2.09 1.82 0.40 0.01 0.04 11.68 0.51

2011 319.09 1.79 1.75 0.39 0.01 0.04 10.82 0.47

2012 329.03 1.67 2.03 0.40 0.01 0.04 11.00 0.54


US$/kWh PhP/kWh

2003 0.0549 3.0175

2004 0.0554 3.0495

2005 0.0555 3.0536

2006 0.0544 2.9923

2007 0.0542 2.9785

2008 0.0550 3.0228

2009 0.0575 3.1607

2010 0.0593 3.2638

2011 0.0622 3.4234

2012 0.0670 3.6854


Documents

power switch cover - wwfeu.awsassets.panda.org