5-1 Chapter 5 Barangay Electrification Plan 5.1 Procedure of the Barangay Electrification Plan 5.1.1 Electrification Target The government has set the target of electrifying 100% of the barangays by 2006 and to achieve 90% household electrification by 2017. In accordance with this target, the Study team has set up a target of the total (100%) barangay electrification by 2006 in Palawan Province as well. In the next three (3) years up to 2006, barangay electrification will be the main focus of the Master Plan. After achieving entire barangay electrification, the focus will move on to the improvement of household electrification. Based on the present electrification level and information obtained through the Study including demand forecasts, capacity to pay, fund availability, the plan for improving household electrification will be determined. Figure 5.1.1 Electrification Target 5.1.2 Barangay Electrification Program There are 431 barangays in Palawan. The number of electrified barangays was 271 as of December 2003. The remaining 160 barangays will be targeted in the Study. 2003 2006 2015 100% ?% Barangay Electrification Ratio HH Electrification Ratio
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Chapter 5 Barangay Electrification Plan 5.1 Procedure of the Barangay Electrification Plan 5.1.1 Electrification Target
The government has set the target of electrifying 100% of the barangays by 2006 and to achieve 90% household electrification by 2017. In accordance with this target, the Study team has set up a target of the total (100%) barangay electrification by 2006 in Palawan Province as well. In the next three (3) years up to 2006, barangay electrification will be the main focus of the Master Plan.
After achieving entire barangay electrification, the focus will move on to the improvement of household electrification. Based on the present electrification level and information obtained through the Study including demand forecasts, capacity to pay, fund availability, the plan for improving household electrification will be determined.
Figure 5.1.1 Electrification Target
5.1.2 Barangay Electrification Program
There are 431 barangays in Palawan. The number of electrified barangays was 271 as of
December 2003. The remaining 160 barangays will be targeted in the Study.
2003 2006 2015
100%
?%
Barangay Electrification Ratio
HH Electrification Ratio
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5.1.3 Prioritization of Barangay Electrification
It is impossible to electrify the 160 barangays all at once, due to the limitation of various resources. Therefore, some prioritization will be necessary. The Study has considered three factors for the prioritization; (1) Electrification cost and O&M cost
Electrification cost and O&M cost should be the most important factors to prioritize barangay electrification since the government development fund is limited and low electricity tariffs at present may not be able to cover the O&M cost. (2) Social and economic benefits
Social and economic benefits will be considered by putting higher priority on socially important areas and social and economical development areas among the un-electrified areas. This may not lead to the most affordable solution, but economical feasibility will be taken into consideration. (3) Social equity
One of the objectives of electrification is to target poverty alleviation and narrowing the poverty gap between areas. Electrification should contribute to well-balanced social and economical development in the province and improve living conditions in the areas.
In MEDP 2003, criteria and their weightings for the electrification projects for un-electrified
areas that are unviable have been determined. The cost factor is given the highest priority.
Table 5.1.1 MEDP Electrification Criteria
Source: 2003 MEDP 5.1.4 Electrification Method
Three electrification methods are considered in the study: (1) Extension of the existing
EC-grid, (2) a mini-grid system and (3) a stand-alone system. The appropriate electrification method for each un-electrified barangay will be selected from these three options. (1) Extension of the existing EC-grids: EElleeccttrriiffiiccaattiioonn ccoonnnneeccttiinngg ttoo tthhee eexxiissttiinngg ddiissttrriibbuuttiioonn lliinneess ooff EECCss,, mmoosstt ooff wwhhiicchh aarreeaass aarree pprroovviiddeedd wwiitthh 2244--hhoouurr eelleeccttrriicciittyy..
Criteria Indicator Weight 1) Low Level of Electrification Access to Electricity by Families by Province 20% 2) Economic Efficiency Connection Cost per Households 50% 3) Eradication of Poverty Poverty Incident of Families by Province 15% 4) Equity of Regional Development GRDP per Capita per Household 10% 5) Environment Friendly Technologies 5%
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(2) Mini-grid systems: There will be electrification by a power plant (micro hydro or diesel) that supplies power to the
households nearby, where grid expansion may be difficult, physically or economically. Its generation capacity will be above 30kW. (3) Stand-alone systems:
There will be electrification by SHS (Solar Home System), BCS (Battery Charging System) and a small-scale diesel generator (mini-diesel generator).
Table 5.1.2 Electrification Method Power system Capacity & Households Power sources
1) Extension of the EC grid Connection to the existing EC-grid with 24-hour supply
2) Mini-grid system Electrification by a power plant that supply power nearby
5.1.5 Methodology to Select an Appropriate Electrification Method
An appropriate electrification method is determined for each un-electrified barangay from the electrification methods described above. The methodology for determination is as follows: (1) Screening by restricted areas for development and on-going electrification programs
This screening eliminates barangays which are located in restricted areas of ECAN (refer to chapter 3.7.1 (1)) and barangays where electrification projects are already ongoing for a target barangay for electrification with the EC-grid extension and a mini-grid system.
A stand-alone electrification method is determined for these eliminated barangays by reason of ECAN restricted areas.
(2) Posibility of EC-grid extension
The possibility of an EC-grid distribution line extension will be examined. The long-run marginal cost (LRMC) of a mini-grid system (diesel or micro hydropower) with
the capacity for electrifying a barangay is compared to the LRMC of EC-grid extension (see Figure 5.1.2). When the LRMC of EC-grid extension is more economical than the LRMC of a mini-grid system, EC-grid extension is selected as the electrification method for a barangay.
Considering future extension of a distribution line, it is better for a barangay to use EC-grid extension. Therefore, although a barangay is already electrified by a mini-grid or stand-alone system, the possibility of EC-grid extension is examined for the electrified barangay.
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Fig.5.1.2 Annual Cost of Distribution Line Expansion & Diesel &Hydro
0
5
10
15
20
25
30
35
40
45
0 5 10 15 20 25 30 35
Distance from Tapping Point (km)
Annual
Cost
(P
hp/
kWh)
Distribution(Php/kWh)
Diesel(Php/kWh)
Hydro(Php/kWh)
Figure 5.1.2 Cost Comparison of EC-Grid Extension and Mini-Grid System
(3) Examine the possibility of a mini-grid system
The possibility of electrification by a mini-grid system is examined for barangays to which EC-grid extension is not applied above. A mini-grid system requires a minimum capacity of demand to become feasible. Diesel generators with a reliable power-supply-use would be more than 30kW in capacity. Micro hydropower also requires a capacity of 30kW from an economical point of view. According to the socio-economic survey (refer to Section 4.2) and the demand forecast (see Section 5.1.3 (4), forthcoming), average household power demand is estimated to be 106W in the target electrification area. Therefore, 30kW demand capacity translates into approximately 300 households. In the Study, barangays with more than or equal to 300 potential households will be suitable for electrification using a mini-grid system. LRMC of diesel and micro hydropower is compared and a power system with a lower LRMC is selected for the electrification of the barangay.
On the other hand, barangays with less than 300 potential households will not be feasible for electrification using a mini-grid system, and so consequently a stand-alone system will be considered.
(4) Stand-alone system
A stand-alone system has 3 candidate methods for electrification (SHS, BCS and a mini-diesel) and there is no determined way for the selection of each method. For example, we can select an appropriate method by comparing annual cost per household in each method.
An example shown in Figure 5.1.3 shows that a mini-diesel generator system would provide electricity at lower cost if more than 15 households are concentrated.
Long
-run
Mar
gina
l Cos
t (Ph
p/kW
h)
Distribution Line Extension
Mini-grid (Hydro)
Mini-grid (Diesel)
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0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
0 5 10 15 20 25Number of Target Household
Pro
duction c
ost
(P
/H
ouse
hold
)
SHSMini-Diesel
SHS Mini-Diesel
Figure 5.1.3 Cost Comparison between SHS and Mini-Diesel 5.2 Power Demand Forecast 5.2.1 Target of Power Demand Forecast
There are two different approaches to power demand forecasts in general. One is the macro-method and the other is the micro-method. In the macro-method, future power demand is forecasted through the analysis of the historical correlation between power demand and an economic indicator such as GDP or a historical trend of power demand. In the micro-method, the components of power demand are estimated individually and future power demand is obtained by adding up the components.
Each method has its own advantages and disadvantages. For data collection, the macro-method needs time-series data over a long period. In contrast, the micro-method requires a wide variety of data. Therefore, the employed demand forecasting method depends on the target of the power demand forecast. The targets for the power demand forecast in the Study is classified into the three areas1 below in the electricity supply system.
(a) Electrified areas by NPC-SPUG and ECs (PALECO and BISELCO) (b) Electrified areas by SHS, BCS, BAPA, LGU, others (c) Un-electrified areas
NPC-SPUG and ECs make their own power demand forecasts every year. In the case of (b),
potential power demand is generally forecasted in advance of the implementation of an electrification project. However, it is not general to continue conducting power demand forecasts after electrification. Therefore, area (b) is the same (c) as un-electrified areas from the viewpoint of power demand forecast. 1 The number of Barangays in (a), (b), and (c) are 212, 59, and 160 respectively. (Dec. 31, 2003)
Ann
ual C
ost p
er H
ouse
hold
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For these reasons, the target of the power demand forecast in the Study was finally classified into two areas. In addition, the target year of the power demand forecast in the Study is 2015.
In this section, power demand forecasts in the area of (b) and (c) are discussed (see Chapter 6.1 for power demand forecast in the area of (a)). 5.2.2 Electrified Areas by SHS, BCS, BAPA, LGU and Un-Electrified Areas
Some barangays obtain electricity through stand-alone systems such as SHS, BCS or a
mini-grid system managed by BAPA, LGU and others. As mentioned above, potential power demand is generally forecasted in advance of the implementation of an electrification project and the feasibility of the project and the specifications of power equipment are examined. However, once the electrification takes place, it is usual for no further power demand forecasts to be conducted.
Consequently, there are no historical data on the actual demand of such electrified areas as well as un-electrified areas. Therefore, the micro-method is better than the macro-method for power demand forecasts for such areas. The process of the micro-method in the Study is shown below.
(a) Projection of population and potential households in 2015 (b) Estimation of target households for electrification (c) Estimation of unit energy consumption and peak demand (d) Estimation of potential power demand in 2015
(1) Projection of population and potential households in 2015
Population of each barangay is projected using the population growth rate based on the annual average growth rate of the municipality that includes the barangay in the CENSUS population 1995 and 2000.
An average household size is also projected by the same method as a population projection. Finally, the number of potential households in 2015 is calculated using the projected population and the average household size. Table 5.2.1 shows the number of potential households in 2015 estimated by using these methods.
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Table 5.2.1 Number of Potential Households in 2015 Present Municipality Barangaye-Status Name Name 2000(Base 2005 2006 2010 2015 2000(Base 2005 2006 2010 2015
Table 5.2.1 Number of Potential Households in 2015 (Continued) Present Municipality Barangaye-Status Name Name 2000(Base 2005 2006 2010 2015 2000(Base 2005 2006 2010 2015
Table 5.2.1 Number of Potential Households in 2015 (Continued) Present Municipality Barangaye-Status Name Name 2000(Base 2005 2006 2010 2015 2000(Base 2005 2006 2010 2015
Table 5.2.1 Number of Potential Households in 2015 (Continued) Present Municipality Barangaye-Status Name Name 2000(Base 2005 2006 2010 2015 2000(Base 2005 2006 2010 2015
Table 5.2.1 Number of Potential Households in 2015 (Continued) Present Municipality Barangaye-Status Name Name 2000(Base 2005 2006 2010 2015 2000(Base 2005 2006 2010 2015
(2) Estimation of target households for electrification The number of target households for electrification depends on a target household
electrification ratio. For example, if the target ratio is 90%, which is the DOE’s target in 2017, the target households for electrification in 2017 is 90% of potential households in 2017.
In estimating target households for electrification, the Study distinguishes between two types of target households. One is the target households for the whole barangay electrification, and the other is the target households for household electrification improvement (see Figure 5.2.1). The target households for the whole barangay electrification are estimated by the formula shown in Figure 5.2.1. The Study employs the “capacity to pay” factor and the “concentration ratio”, because not all potential households can afford to pay the electricity charge2 and not all potential households are located at one spot in a barangay. The “capacity to pay” factor refers to the share of potential households in the barangay that can afford to pay the electricity charge. The concentration ratio refers to the share of households that are expected to be located in the proximity of the barangay center 3 . According to the socio-economic survey, the “capacity to pay” factor and the concentration ratio are considered to be about 0.7 and 0.5 ~ 0.7 in Palawan, respectively (see Section 4.2). The Study employs the concentration ratio of 0.5.
Un-electrified Bgy. A
SitioBgy. Center
Target HH for 100% Bgy. Electrification
Target HH for HH Electrification Improvement
= Potential HH x Capacity to Pay Factor x Concentration Ratio
= Potential HH x Target HH Electrification Ratio- Target HH for 100% Bgy. Electrification
Target HH in Bgy. A
= Target HH for 100% Bgy. Electrification+ Target HH for HH Electrification Improvement
Un-electrified Bgy. AUn-electrified Bgy. A
SitioBgy. CenterSitioBgy. CenterSitioBgy. Center
Target HH for 100% Bgy. Electrification
Target HH for HH Electrification Improvement
= Potential HH x Capacity to Pay Factor x Concentration Ratio
= Potential HH x Target HH Electrification Ratio- Target HH for 100% Bgy. Electrification
Target HH in Bgy. A
= Target HH for 100% Bgy. Electrification+ Target HH for HH Electrification Improvement
Figure 5.2.1 Type of Target Households for Electrification
Table 5.2.6 shows the number of target households for the whole barangay electrification in
20064 and the number of target households for household electrification improvement in 2015 in the case of an 80% electrification target.
2 The minimum charge is assumed to be P150 / month, which is a general minimum monthly charge in BAPA. 3 The Barangay proper has the Barangay hall, the Barangay plaza, a Barangay day care center and other facilities. 4 The number of target households for 100% barangay electrification in 2006 is 35% of the potential households in each barangay.
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(3) Estimation of unit energy consumption and peak demand The Study assumes the two consumer types below in estimating unit energy consumption and
peak demand.
Low Use Consumer : Fluorescent Light (20 W) x 2 High Use Consumer : Fluorescent Light (20 W) x 4, Color TV (50 W) x 1,
Audio5 (20 W) x 1, Refrigerator (100 W) x 1, Electric Fan (30 W) x 1
In the case of electrification with SHS and/or BCS, however, the parameter of appliances to
install and supply hours are fixed at two fluorescent lights and 4-hour supply respectively in consideration of MEDP and existing SHS and BCS projects in Palawan.
Figure 5.2.2 shows the daily use patterns of each appliance.
Low Use ConsumerItem Qt. W WH MAX. W Hours in Use -1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 -24
Figure 5.2.2 Daily Use Pattern of Electric Appliances
There are many options for the electricity supply hours. The Study uses a 6-hour supply as a base for power demand forecasting, which many existing mini-grid systems also employ. Figure 5.2.3 shows the daily load curve of each consumer type.
5 Karaoke, VCD, Cassette recorder, others
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Load Curve of Low Use Customer
0
50
100
150
200
250
300
17-18 18-19 19-20 20-21 21-22 22-23
Hour
WFluorescent Light
Load Curve of High Use Customer
0
50
100
150
200
250
300
17-18 18-19 19-20 20-21 21-22 22-23
Hour
W
Refrigerator Color TV Electric Fan Audio Fluorescent Light
Figure 5.2.3 Daily Load Curve of each Consumer Type (6-Hour Supply)
Table 5.2.2 shows the unit energy consumption and peak demand for each consumer type.
Table 5.2.2 Unit Energy Consumption and Peak Demand
Consumer Type Energy Consumption (Wh) Peak Demand (W) Low Use Consumer 160 Wh / day /HH = 4.8 kWh / Month /HH 40 W / HH High Use Consumer 1,260 Wh / day / HH = 37.8 kWh / Month /HH 260 W / HH Note: 6-hour supply
The share of low and high use consumer depends on the economical conditions of each
barangay. The Study assumes the two types of shares shown below.
Category I : The ratio of low use consumer and high use consumer is 90% to 10% Category II : The ratio of low use consumer and high use consumer is 70% to 30%
In Palawan, coastal barangays generally have better economical conditions than highland barangays. Table 5.2.3 shows the histogram of monthly energy consumption of consumers in Barangay. Port Barton BAPA, which provides a 6-hour supply to its consumers. Since about 30% of the consumers are ranked above 30 kWh, the economical condition of Barangay. Port Barton is considered to be close to Category II.
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Table 5.2.3 Monthly Energy Consumption in Port Barton BAPA Monthly Energy Consumption
Total 121 100.00% Source: Port Barton BAPA Monthly Financial and Statistical Report, April, 2002
Ideally, the category for each barangay needs to be set individually considering their respective
economic conditions. The Study, however, set the category for all barangays at Category II. This is due to the fact that almost all of the barangays in Palawan are located along coastlines. Table 5.2.4 shows the annual unit energy consumption and peak demand for the given conditions.
Table 5.2.4 Annual Unit Energy Consumption and Peak Demand Barangay Category Unit Energy Consumption (kWh) Unit Peak Demand (W)
Category II 179 kWh / year / HH 106 W / HH Note: 6-hour supply
Table 5.2.5 shows the daily unit energy consumption and peak demand for reference.
Table 5.2.5 Daily Unit Energy Consumption and Peak Demand Category I Category II (SHS / BCS)
(4) Estimation of potential power demand in 2015 Figure 5.2.4 shows the flow for estimating potential power demand on a sample barangay
(Barangay A) with 1,000 households.
Potential HHin 2015
Target HH for100%Bgy.
Electrification
(Bgy. A)Category II
6 hours
1,000 HH
350 HH
Potential HH forHH Electrification
650 HH
Target HH forHH Electrification
Un-Electrified HHin 2015
(Target Ratio of HH Electrification = 80%)
450 HH(= 1,000 x 0.8 –350)
200 HH
Target HH in Sitio A
Target HH in Sitio B
225 HH
225 HH
350 x 179 = 62.7 (MWh)
350 x 106=37.1 (kW)
225 x 179 = 40.3 (MWh)
225 x 106 = 23.9 (kW)
225 x 179 = 40.3 (MWh)
225 x 106= 23.9 (kW)
Total potential demand in Bgy.A = 143.3 (MWh)= 84.9 (kW)
Unit Energy Consumption = 179 kWh / year /HHUnit Peak Demand = 106 W / HH
Potential HHin 2015
Target HH for100%Bgy.
Electrification
(Bgy. A)Category II
6 hours
1,000 HH
350 HH
Potential HH forHH Electrification
650 HH
Target HH forHH Electrification
Un-Electrified HHin 2015
(Target Ratio of HH Electrification = 80%)
450 HH(= 1,000 x 0.8 –350)
200 HH
Target HH in Sitio A
Target HH in Sitio B
225 HH
225 HH
350 x 179 = 62.7 (MWh)
350 x 106=37.1 (kW)
225 x 179 = 40.3 (MWh)
225 x 106 = 23.9 (kW)
225 x 179 = 40.3 (MWh)
225 x 106= 23.9 (kW)
Total potential demand in Bgy.A = 143.3 (MWh)= 84.9 (kW)
Unit Energy Consumption = 179 kWh / year /HHUnit Peak Demand = 106 W / HH
Figure 5.2.4 Flow for Estimating Potential Power Demand Finally, potential power demand in the electrified and un-electrified barangays, except for the barangays supplied with electricity from NPC-SPUG and ECs, are shown in Table 5.2.6.
Table 5.2.6 Potential Power Demand Forecast in 2015 (Non NPC-SPUG and ECs Areas) Present Municipality Barangay Potential HH Target HH Energy Demand Target HH Energy Demand Target HH Energy Demande-Status Name Name 2015 (2006, 35%) (MWh) (kW) For 80%, 2015 (MWh) (kW) (Total, 2015) (MWh) (kW)
5.3 Example of Barangay Electrification Selection Method (Model Barangay) The selection of an electrification method requires the estimation of electrification costs reflecting topographic conditions and power demand size of the target barangay.
This section describes the procedure and the details of electrification cost for each method by using a model barangay. 5.3.1 Model Barangay Table 5.3.1 shows the details of the model barangay.
Table 5.3.1 Details of Model Barangay Barangay Name Panalingaan, Rizal Potential Households in 2015 1,746 Households
(Concentration Ratio) (0.5) (Capacity to Pay Factor) (0.7)
Unit Energy Consumption 166 kWh / year / HH Unit Peak Demand 98 W / HH Maximum demand in 2015 59.9 kW ECAN condition Non- restricted area On-going electrification project No project
5.3.2 Assumptions of Electrification Methods (1) Diesel power (a) Mini-grid
The required level of reliability for a mini-grid system will be similar to that of the EC-grid. Therefore, diesel generators that can provide a high level of reliability are assumed to be used. Moreover, in order to maintain reliability, periodical overhauls will be necessary, as well as backup systems in the cases of machine failures. Therefore, it is assumed that two sets of diesel generators will be installed for a mini-grid system.
The capacity of diesel generator available on market with the acceptable level of reliability seems to be about 30kW output or more. Therefore, the capacity of a diesel generator for a mini-grid is set to 30kW or more.
The Study team assumes an interest rate of 12% and constant electricity consumption after 2015 for the calculation of the LRMC of the mini-grid system. Also these assumptions are used for EC-grid extension and hydropower. Additionally, since the condition of the secondary distribution line in a barangay center required in a mini-grid system is the same as that in an EC-grid extension, the electrification cost for selecting the system does not contain the cost of this secondary line.6 6 The cost of secondary distribution line is calculated in Section 5.4.5
Unit Capacity 60 kW No. of Unit 2 unit One extra unit for backup Diesel generator 14,400 Php/kW Estimated on the basis of the data from NPC-SPUG Maintenance Cost 1.41 Php/kWh Rectified value by comparing the standard expense in Japan with the
expense of NPC-SPUGLifetime 70,000 ope. Hours Assume 70% of standard lifetime for a middle speed engine Thermal efficiency 30% Value lower than standard Fuel Cost 27 Php/L The highest purchase price of NPC-SPUG in Palawan Labor Cost 8,000 Php/month 2 persons, actual salary from one BAPA in Palawan
(b) Stand-alone
For a stand-alone system, a diesel generator requires the similar reliability level of SHS. However, the crucial problem of an inexpensive diesel generator is its sustainability. In areas
electrified by inexpensive diesel generators, the maintenance is almost non-existent except for oil and filter changes. It seems difficult to expect sufficient maintenance in those areas. In most of these areas, diesel generators seem to break down within about four years of operation, with only make shift repairs that extend their life for very short periods before they are totally discarded. Therefore, the life of the diesel engine for a stand-alone system is presumed to be short, so that replacement can occur before failure or the need for major overhauls.
The assumptions related to a diesel generator for a stand-alone system are shown in Tables 5.3.4 and 5.3.5.
Considering the short lifetime of a diesel generator for a stand-alone system, replacement cost for the period of 20 years (same as lifetime of SHS) is included in the electrification cost.
Designing a diesel generator for a stand-alone system requires the assumed number of households to which electricity is supplied. The Study team set the number of 20 households for the system on the basis of the actual condition of areas electrified by private owned diesel generators (generally 20-30 households, refer to Section 3.4.2 (1)).
Unit Capacity 3 kW 20 households supply Diesel Generator 10,400 Php/kW Estimated on the basis of local cost and the data from NPC-SPUGMaintenance Cost 5,000 Php/year Oil filter change Lifetime 4,000 ope. Hours 4 ope.hours/day, replacement of engine every 3 years Thermal Efficiency 20% Value lower than standard Fuel Cost 27 Php/L The highest purchase price of NPC-SPUG in Palawan Labor Cost 4,000 Php/month 2 persons, actual salary from one BAPA in Palawan
(2) Hydropower (a) The basic data for cost estimation
Since most of the works, especially civil construction works, will be conducted in Palawan, the project costs should be estimated using Palawan unit costs. The unit cost data was obtained from interviews with DPWH, PNCC, NIA, turbine and generator companies in Europe, consultant companies in Manila and local construction companies in Palawan Reports on past feasibility studies were also used. DOE does not have specific construction cost data since the DOE's main roles are to promote mini and micro hydropower and to support LGUs to plan and construct mini and micro hydropower facilities both technically and financially. DOE merely evaluates project proposals that LGUs, NGOs and other organizations submit to DOE, and does not estimate costs by themselves. The cost data used for the estimation is listed below. The details of cost estimation will be explained in the Annex.
The lifetime of a hydropower facility is generally set at 40 years including both civil structures
and mechanical-electrical equipment. This Study also uses 40 years. (b) Hydro project for the model Barangay
Based on the conditions of the model barangay, the Study team set a model hydropower project in order to make comparisons with other generation types. The basic concepts for setting a hydropower project for the model barangay are: 1) the nearest river that has enough water for generation during the dry season is chosen for a potential site in order to minimize the length of distribution lines and 2) the capacity should be enough for covering the demand of the target households in the barangay in 2015. The concept is outlined in the Figure 5.3.1, and the conditions and the costs of the micro-hydropower for the model barangay are shown in the Table 5.3.7 and Table 5.3.87.
7 There are no potential sites for micro-hydropower around the center of barangay Salogan. Therefore, for the model hydropower project, various
specifications for the civil structures were set using the Salogan project (newly identified by the Study team). The reasons for choosing the Salogan project were: (1) the data of civil structures are general, (2) the number of households in Barangay Samanñana and the nearest barangay from the Salogan power station are almost the same as the targets in the model barangay.
Item Unit Cost
Project Cost Php 69,872* Electrification Cost per HH Php/HH 3,494* Annual Cost per HH Php/year/HH 3,384*
Table 5.3.6 Unit Costs used in the StudyUnit Name Unit Cost
Concrete Work Common Concrete 3,134 PHP/m3 Rubble Masory Concrete 2,712 PHP/m3 Concrete Spray 13,622 PHP/m3 Invert Concrete 4,990 PHP/m3
Excavation Work Common Excavation 136 PHP/m3 Rock Excavation 314 PHP/m3
* Including cost of diesel generator replacement for 20 years
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Table 5.3.7 Assumptions for Cost Estimation (Micro-Hydropower) Item Condition
Installed Capacity 60 kW Effective Head 40 m Maximum Discharge Water 0.181 m3/sec Flow Utilization Factor 90% Length of Distribution Line 3.7 km O&M Cost 2% of annualized construction cost Lifetime 40 years
(3) Distribution line extension Distribution line extension cost means expenses to construct distribution lines between the
center of the model barangay and the nearest tapping point of the existing distribution lines. In this connection, the cost excludes the expenses for installing secondary distribution lines between the tapping point of the center and each consumer in the model barangay.
Barangay Panalingaan is located far from the existing distribution line. It is about 34km from the PALECO distribution line in BATARAZA and 38km from the Rizal local government unit network. Neighbor barangays are located at less than 10km but have not yet been energized. This barangay is not feasible for EC-grid extension based on the actual situation. But in the model study calculation, the distance from the nearest tapping point is considered as a variable to generalize the calculation result.
Table 5.3.8 Electrification Cost (Micro-Hydropower) Item Unit Cost
Figure 5.3.1 Image of Hydropower for the Model Barangay
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Regarding unit construction cost, the Study employs the actual construction cost of PALECO and not NEA (see Table 3.4.7, 3.4.8, 3.4.9).
Lifetime for a wood pole is usually 15 years. But PALECO is installing exported wood poles that have lifetimes of 40 years in tropical conditions. In this calculation, lifetime is set at 40 years.
Usually distribution line facilities do not need periodic maintenance. The cost of lineman only for the tapping line is negligible. Only fuel costs for electric supply per kWh are considered as operation cost. Table 5.3.9 shows the assumptions for the distribution line extension.
Table 5.3.9 Assumptions for Cost Estimation (Distribution Line Extension)
Distance between the centers of Bgy. and the nearest tapping point Parameter of calculation
Unit cost for distribution line construction 817,473 Php/km Lifetime for distribution line 40 years Operation Cost 3.41 Php/kWh
The results of the calculation are shown in formulas 5.3.1 and 5.3.2.
Construction Cost = 817,473 x Distance (km) (Php/km) Formula 5.3.1 LRMC = 1.38 x Distance + 3.43 (Php/kWh) Formula 5.3.2
(4) Solar power
There are several design methods for solar power systems. Among these methods, the parametric design method was adopted in this Study since this method is simple and easy to understand. The parametric design method has been applied for many solar power projects and has a good track record for generating adequate results for formulating the Master Plan. Another method, such as the simulation design method, can offer more precise results, but this method is more suitable for assessments of larger scale projects.
As for the detailed of design method, refer to the Annex. (a) SHS
Table 5.3.10 shows the assumptions for cost estimation of the SHS system and Table 5.3.11 shows the cost of SHS.
Table 5.3.10 Assumptions for Cost Estimation (SHS)
Item Condition Remarks Design Parameter 0.6 Estimated on the basis of actual data and typical value Inclined solar radiation 4 kWh/m2/day PV module angle 15 degree
System Efficiency 60% Calculation result based on actual temperature and specification of equipments
Battery Voltage 12 V Availability of battery in rural area Depth of Charge 50% Performance of available battery of rural area Consecutive cloud day 3 days Based on the actual solar duration data System Cost 30,380Php/unit Based on the DOE project data, hearing with manufactures and websiteLifetime 20 years
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(b) BCS
Most of the parameters for BCS are identical to those for SHS. Table 5.3.12 shows additional parameters required to design BCS.
The detailed designing of BCS requires setting the number of target households to be electrified based on a more detailed socio-economic survey8. In the Study the number of target households is set at 15 households, based on the threshold defined by the comparison of economic features of SHS and a mini-diesel generator for a stand-alone system. Table 5.3.13 shows the cost of electrification by BCS.
Table 5.3.12 Assumptions for Cost Estimation (BCS)
Item Condition Remarks The number of target household to be electrified 15 Economic threshold between SHS and mini-diesel for
stand-alone system Maximum battery capacity 70 Ah Availability and portability in rural area Charging frequency 3 日/回 40Wh/day/HH
(c) PV Hybrid system
In the Master Plan a PV hybrid system is not considered as a candidate system for barangay electrification. The reasons are as follows. Assumptions
For the analysis of a hybrid system, the Study team assumes that a PV system is added on a diesel generator for a mini-grid system discussed in the above section.
Results
- High initial investment cost and high production cost. Investment Cost 27 million Php Production Cost 48 Php/kWh
- Less contribution of CO2 credit from reduction of GHG to saving investment cost Contribution of credit estimated based on the Proto-type Carbon Fund of the World Bank (US/t-CO2) is 0.1 Php/kWh, which cannot reduce the production cost to the level of diesel power for the mini-grid system discussed in the above section.
8 Evaluation of superiority of BCS to SHS and mini-diesel requires detailed socio-economic surveys of the target barangay to grasp its economic
conditions, the number of target households to be electrified and concentration level of households in the barangay. Therefore, field survey covering these aspects should be conducted in future FS.
Table 5.3.11 Electrification Cost (SHS) Item Unit Cost
System Cost Php 30,380 Electrification Cost per HH Php 30,380 Annual Cost per HH Php/year/hh 5,437
Table 5.3.13 Electrification Cost (BCS) Item Unit
System Cost Php 214,630
Electrification Cost per HH Php/HH 14,308
Annual Cost per HH Php/ year/HH 2,272
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(6) Wind power Available generation from wind power systems is calculated on the condition that the wind
speed used in the calculation is adjusted to the USAID level, and electrification cost is estimated. As a result, the investment cost and production cost is remarkably higher than with other
systems. Therefore, the Study team decided that wind power is out as a candidate system for barangay electrification in the Master Plan.
Table 5.3.14 shows the assumptions for the cost estimation of wind power and Table 5.3.15 shows the electrification cost of the system.
Table 5.3.14 Assumptions for Cost Estimation (Wind Power)
Item Condition Remarks Maximum Demand of each HH 40 WHH Data from demand forecast, demand same as SHS Daily Demand of each HH 120 Wh/day/HH Data from demand forecast, demand same as SHS Installed Capacity 7.5 kW High plant factor, less than 100kW in capacity Battery Voltage 12 V Availability of batteries in rural areas Depth of Charge 50% Performance of available batteries in rural areas Battery Capacity 10 days demand Availability of batteries in rural areas Continuance Supply Capacity 550 Wh/day Minimum number of 10 days SMA (Single Moving Average)No. of Target Electrified 4 HH/unit Based on demand per HH and continuance supply capacity
5.3.3 Selection of Electrification Method (Model Barangay) (1) Screening by restricted areas for development and on-going electrification programs
The model barangay has no restrictions on development activities or on-going electrification projects. Therefore, this screening is not used to identify an electrification method for the model barangay.
(2) Examine the possibility of EC-grid extension
As mentioned in Section 5.1.5 (3), firstly the LRMC of the EC-grid and the mini-grid system (diesel, and if suitable site is near the target barangay, micro-hydropower) is calculated to meet the demand of target households to be electrified.
The possibility of an EC-grid extension is examined, while comparing the LRMC of each system.
Figure 5.3.2 shows the comparison of the LRMC of each system.
Table 5.3.15 Electrification Cost (Wind Power) Item Unit Cost
System Cost Php 2,744 x 103 Electrification Cost per HH Php/HH 686 x 103 Production Cost Php/kWh 2,324
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Figure 5.3.2 LRMC Comparison of the EC-Grid Extension and Mini-Grid System (Model Barangay) As shown in Figure 5.3.2, in the case that the distance from the center of the model barangay to
the nearest tapping point is shorter than 8km, an EC-grid extension is selected as an appropriate method for the model barangay.
(3) Examine the possibility of a mini-grid system
In the case that the distance from the center of the model barangay to the nearest tapping point is longer than 8km, an EC-grid extension is not justified in the screening above, and so the possibility of a mini-grid system or another suitable type of system is examined.
As described in Section 5.1.5, a mini-grid system is not applied to barangays with the potential demand of less than 30kW due to the reliability of diesel power and the economical efficiency of hydropower for a mini-grid system.
In the case of the model barangay, the potential demand (59.9 kW) is larger than 30kW. Therefore, the barangay has the possibility of a mini-grid system. As for the type of the system, it is concluded that diesel power is more suitable than hydropower for the model barangay.
(4) Examine the possibility of a stand-alone system
A stand-alone system is not selected as an electrification method for the model barangay.
8km
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5.4 Scenario Options 5.4.1 Scenarios for Barangay Electrification
The scenario for barangay electrification in the Study is outlined below: (1) Base scenario (Least cost electrification)
Using the above methodology to select the appropriate electrification method, a plan to electrify all the un-electrified barangays by the year 2006 will be determined. The base scenario will be the electrification case involving the least cost, which selects the electrification method from economical point of view in accordance with the MEDP 2003 criteria, which places a high priority on economic efficiency. (2) Reliability-oriented scenario (Utilization of grid extension)
Reliability is different among various electrification methods. Extension of the existing grid provides 24-hour power supply, whereas a mini-grid system provides around 6 hours and a stand-alone system provides electricity that is barely sufficient for lighting alone. Therefore, in addition to the base scenario, the reliability-oriented electrification method will be studied as an alternative case.
For this scenario, special weight will be put on reliability by allowing double the cost for grid extension in selecting an electrification method. Timing of the implementation will be the same as the base scenario. (3) Environment-friendly scenario (Utilization of hydropower resources)
MEDP 2003 has a strategy to promote hydropower because hydropower is a renewable and domestic energy. Hydropower may enjoy low-interest funding because it is environmental friendly and so a special weight allowing quadruple the cost of diesel power will be applied in selecting the electrification method. Timing of the implementation will be the same as the base scenario.
5.4.2 Technical Study for Barangay Electrification Plan
(1) On-going electrification projects Only 1 barangay shall be electrified in 2004 by an on-going electrification project as of the end
of December in 2003. Table 5.4.1 shows the details of that barangay. The Study excluded it as a target for the whole barangay electrification.
Table 5.4.1 On-going Electrification Project (As of end of December in 2003)
(2) Technical study for EC-grid extension (a) Creation of the regression curve for screening EC-grid extension
The screening curve is created as shown below in order to choose barangays electrified with EC-grid extension.
(i) 4 barangays with different numbers of households are chosen. (ii) The distance from the tapping point to the point where the LRMC or EC-grid extension and
that of the diesel cross is computed for each barangay. (iii) A regression curve for screening, which shows the relation between potential households
and maximum distance from tapping point, is estimated from 4 cross points.
Table 5.4.2 Regression Curve Creation Distribution Line LRMC
Figure 5.4.1 shows the results of the regression line. This figure shows that if a potential HH at 2015 and a distance from the tapping point of a barangay are located on the lower side of the line, that barangay should be electrified by distribution line extension.
Conversely, if potential households and the distance are located upper side of the line, that barangay should be electrified by a mini-grid system.
The formulas of the regression line are as below:
Base Scenario : Distance = 0.0106 x Potential HH + 1.7284 Formula 5.4.1 Reliability-Oriented Scenario : Distance = 2 x (0.0106 x Potential HH + 1.7284) Formula 5.4.2
0.00
2.00
4.00
6.00
8.00
10.00
12.00
14.00
16.00
0 500 1000 1500Potential HH at 2015
Dis
tance f
rom
tap
ping
poin
t (k
m)
Figure 5.4.1 Screening Line
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(b) Calculation of distance between barangay centers The location of the center of each barangay is determined with the GIS data. Using these data,
the distance in a straight line between barangays is created on an Excel sheet. With those distances and the results of potential household estimations, all barangays are checked by the above-mentioned Formulas 5.4.1 or 5.4.2.
(c) Checking the possibilities of EC-grid extension on the map
After checking with these formulas, distribution line routes are checked on the map. Even if a certain barangay has a suitable distance for an EC-grid extension, it still cannot be chosen if the neighbor/source barangay is not electrified or is not suitable for EC-grid extension. In other cases, when the source barangay is on the different side of a channel, the EC-grid extension also cannot be chosen. Finally only 6 barangays are selected as the barangays that are feasible to be electrified by EC-grid extension. (3) Mini-grid system (a) Diesel power plant for a mini-grid system
The Study team estimated development costs for installing a diesel power plant for a mini-grid system based on the cost data that is shown in the NPC-SPUG Development Plan 2002, and set the capacity of a diesel generator to meet the potential demand of each barangay. Table 5.4.3 shows development costs of a diesel power plant for a mini-grid system.
Table 5.4.3 Development Costs of a Diesel Power Plant for a Mini-Grid System Potential Demand Capacity9 Development Cost (Php)
30 kW – 34 kW 34 kW 979,200
– 50 kW 50 kW 1,440,000
– 63 kW 63 kW 1,814,400
– 87 kW 87 kW 2,505,600
– 108 kW 108 kW 3,110,400
(b) Micro hydropower plant for a mini-grid system
As shown in Table 4.1.14 and Figure 4.1.9, the Study team found only 1 site (Aramaywan in Mun. RIZAL) for micro hydropower in Palawan. Table 5.4.4 shows the development cost of the micro hydropower plant of Aramaywan.
Table 5.4.4 Development Cost of Micro Hydropower for Mini-Grid System
Name of Site Location Capacity Potential Demand in 2015 Development Cost (Php)
9 Assumed capacity of 90% of PERKINS’s plant capacity.
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(c) Selection of a power plant for a mini-grid system The power plant for a mini-grid system is selected by comparing the LRMC of power plants
for a target barangay. The Study team found only 1 micro hydropower site, therefore, compared both the LRMC of diesel power and micro hydropower for Bgy. Aramaywan.
Table 5.4.5 shows the LRMC of each power plant.
Table 5.4.5 LRMC Comparison of Micro Hydropower and Diesel Power for a Mini-Grid System
Plant Type Capacity Potential Demand in 2015 LRMC
Diesel power 34 kW 15.50 Php/kWh
Micro hydropower 39 kW 30.42 kW
61.22 Php/kWh
(4) Stand-alone system As a result of the screening (1)-(3) above, in the case that a stand-alone system is selected as the electrification method of a certain barangay, the type of the system is chosen from 3 options (SHS, BCS and a mini-diesel)
However, as discussed in Section 5.3.2, it is not adequate to compare the electrification cost of each type on an equal footing to evaluate superiority since the important parameters that affect the superiority are not determined and also their unit power demand assumptions vary from type to type.
Therefore, the Study team assumed the allocation ratio shown in Table 5.4.6 for the type of system. Also the number of households to be electrified for each barangay is assumed to be 20 households.
Table 5.4.6 Allocation of each Type of a Stand-Alone System and Electrification Cost
Item SHS BCS Mini-Diesel Weighted Average
Allocation Ratio 40% 30% 30% Electrification Cost per HH 30,380 Php/HH 14,308 Php/HH 3,494 Php/HH 17,493 Php/HH
5.4.3 Results of Barangay Electrification Screening
The results of barangay electrification screening in each scenario are outlined below: (1) Base scenario (Least cost electrification)
The EC-grid extension is selected for 6 barangays, a mini-grid for 23 barangays and a stand-alone system for 132 barangays.
Although one barangay, Bgy. Babuyan in Mun. PUERTO PRINCESA, has already been electrified by a stand-alone system as of the end of December in 2003, EC-grid extension is selected for this barangay because upgrading the electrification method from a stand-alone to an EC-grid is justified.
As for the timing of electrification, the Study team assumed that all mini-grid systems will be installed in 2006 in consideration of the construction period.
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EC-grid extension and stand-alone systems are allocated each year between 2004 and 2006 to level the annual costs per year.
Total investment costs up to 2006 are estimated to be 183.3 million pesos.
Table 5.4.7 Barangay Electrification Plan (Base Scenario) No. of Barangay Investment Cost (million Php)
* No. of Barangays exceeds 160 because it includes grade-up electrification ** Includes countermeasure costs for voltage drops caused by EC-grid distribution line expansion (refer to Section 5.4.4)
Table 5.4.8 Number of Barangays Electrified (Base Scenario) Number of Barangay Electrification
Status Electrification
Method Electrification
Level As of the end of 2003 2015 LEVEL III 44 44 LEVEL II 111 117 LEVEL I 57 57
EC-grid extension
Sub Total ( 212) ( 218)LEVEL II 1 29 LEVEL I 5 0 Mini-grid
Sub Total ( 6) ( 29) LEVEL II 6 184 LEVEL I 47 0 Stand-alone
Sub Total ( 53) ( 184)
Electrified
Total ( 271) ( 431) Un-electrified ( 160) ( 0)
Grand Total 431 431
Table 5.4.9 Transition of Number of Households Electrified (Base Scenario)
Table 5.4.12 Results of Screening (Base Scenario) (Continued) (Bgys. electrified by SHS, BCS, BAPA, LGU and others: 59 Bgys.)
(2) Reliability-oriented scenario (utilization of EC-grid extension)
EC-grid extension is selected for 56 barangays, the number is about 9 times that of the base scenario. On the other hand, the number of barangays electrified by a mini-grid system and a stand-alone system decreased to 15 barangays for a mini-grid and 94 barangays for a stand-alone system due to the increase in the number of barangays electrified by EC-grid extension.
As for the upgrading of the electrification method, in this scenario EC-grid extension is selected for 5 barangays electrified previously as of the end of December in 2003.
Total investment cost up to 2006 is estimated to be 427.3 million pesos, which is more than double that of the base scenario.
* No. of Barangays exceeds 160 because it includes grade-up electrification ** Includes countermeasure cost for voltage drops caused from EC-grid distribution line expansion (refer to Section 5.4.4)
Table 5.4.14 Number of Barangays Electrified (Reliability-Oriented Scenario) Number of Barangay Electrification
Status Electrification
Method Electrification
Level As of the end of 2003 2015 LEVEL III 44 44 LEVEL II 111 167 LEVEL I 57 57
EC-grid extension
Sub Total ( 212) ( 268)LEVEL II 1 21 LEVEL I 5 0 Mini-grid
Sub Total ( 6) ( 21) LEVEL II 6 142 LEVEL I 47 0 Stand-alone
Sub Total ( 53) ( 142)
Electrified
Total ( 271) ( 431) Un-electrified ( 160) ( 0)
Grand Total 431 431
Table 5.4.15 Transitin of Number of Households Electrified (Reliability-Oriented Scenario)
(3) Environment-friendly scenario (utilization of hydropower resources) The selected electrification methods are the same as those in the Base Scenario. This scenario
gives priority to the development of hydropower. Therefore, micro-hydropower for a mini-grid system is selected for 1 barangay (Bgy. Aramaywan in Mun. QUEZON).
Total investment cost up to 2006 is estimated to be 202.4 million pesos.
Table 5.4.19 Barangay Electrification Plan (Environment-Friendly Scenario) No. of Barangay Investment Cost (million Php)
* No. of Barangays exceeds 160 because it includes grade-up electrification ** Includes countermeasure cost for voltage drops caused by EC-grid distribution line expansion (refer to Section 5.4.4)
Table 5.4.20 List of Barangays Electrified by Mini-grid System (Environment-Friendly Scenario)
Total 134.1 *Including the cost of secondary distribution lines in the center of the barangay (refer to Section 5.4.4)
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5.4.4 Check of Selected EC-Grid Extension and Mini-Grid System (1) Supply voltage check
Voltage drops in each distribution feeder are calculated based on the estimated demand at 2015. There is no definite criterion for 13.2kV distribution line voltage drop in PALECO. In this study, a voltage drop criterion is set to 5% of nominal voltage. If it exceeds 5%, supply voltage for the tail end low voltage customer is less than 90% of nominal voltage. As impedances are used for the calculation of each feeder’s voltage drops, and not the value of NEA BULLETIN DX3430 and Table 3.4.2 of this report, and so the value shown in the Table 5.4.21 is adopted so that a power-factor may be reflected.
In the voltage calculations of PALECO’s feeder, it is considered that the main distribution lines are AWG2/0. But in the calculation of BISELCO’s feeder, actual sizes obtained from their line maps are used.
The demand is computed in proportion to the number of households in 2015, and measurement values, which PALECO holds, are rectified. And information on new big customers is also considered. The power factor is set up to 90%. The results of calculation are shown in Table 5.4.22. Calculation data sheets are shown in Tables 5.4.23 to 5.4.27.
Table 5.4.22 Results of Calculation on Voltage Drop Power/Sub Reliability-Oriented Scenario Base Scenario
Station Feeder /Circuit 2015 2006 2015 2006
San Jose Exceed 5% at Bacungan
Exceed 5% at Bacungan -- Exceed 5%
at Bacungan Puerto Princesa City
Iwahig OK -- -- --
Aborlan Exceed 5% at Isaub OK Exceed 5%
at Kamuning OK Narra
Quezon Exceed 5% at Calategas -- -- Exceed 5%
at Ipilan To East OK -- -- --
Brooke’s Point Bataraza Exceed 5% at Bono Bono
Exceed 5% at Ocayan OK --
Coron Busuanga OK -- -- --
The feeder that has more than a 5% voltage drop needs a voltage regulator or capacitor on the feeder to compensate voltage. The Narra-Aborlan feeder will have a voltage drop exceeding 5% at Barangay Kamuning. However, since the Puerto Princesa-Iwahig feeder has a margin in its voltage drop, barangays Kamuning, Inagawan and Inagawan Sub-colony will be able to be supplied by the Iwahig feeder. The Narra substation will not have enough capacity to meet demand in the near future. Therefore, NPC-SPUG is planning the construction of a new substation under the way of the backbone transmission line near Barangay Abo-Abo. After this construction, the Narra-Quezon feeder will be divided into two feeders.
(2) Grid expansion plan (a) Base scenario Based on the plan of the new substation by NPC-SPUG, and the results of voltage calculation, the distribution line extension plan in the Base scenario is decided as follows.
Figure 5.4.2 EC-Grid Expansion Plan (Base Scenario)
The expense of a project is calculated using the distance of the required distribution line investigated by ECs, and the unit price mentioned in Table 3.4.9.
Table 5.4.28 Project Cost of EC-Grid Extension (Base Scenario) KMS. Of Line Year Municipality Barangay Tapping Point 3Ph 1Ph OS UB
(b) Reliability-oriented scenario In this scenario, a voltage regulator is needed also for Bataraza. A voltage drop will not become a problem if there is a new substation for supply in the Bataraza area. There is actually a plan for a new substation in the area, since transmission line construction is required. It may take a long time to complete, so the installation of a voltage regulator is considered as measure for the time being.
Figure 5.4.3 EC-Grid Extension Plan (Reliability-Oriented Scenario)
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Figure 5.4.3 EC-Grid Extension Plan (Reliability-Oriented Scenario) (Continued)
SUB TOTAL 97.00 23.15 19.40 55.00 97,519323.51 62.20 66.95 195.33 321,144
TAY TAY
TOTAL
QUEZON
ROXAS
SOFRONIO ESPANOLA
TAY TAY
2006
Voltage RegulatorPUERTO PRINCESA
BATARAZA
EL NIDO
Voltage Regulator
EL NIDO
PUERTO PRINCESA
ROXAS
Year
2004
TAY TAY
BATARAZA
2005
BATARAZA
CORON
EL NIDO
PUERTO PRINCESA
ROXAS
KMS. OF LINEMUNICIPALITY BARANGAY TAPPING POINT
Project cost of the EC-grid extension is shown as Table 5.4.29.
Table 5.4.29 Project Cost of EC-Grid Extension (Reliability-Oriented Scenario)
(c) Environment-friendly scenario
The results of the environment-friendly scenario are the same as those of the base case.
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(3) Mini-grid system plan The estimates for a distribution line extension plan by ECs are used in construction expense
calculations for the distribution line of a mini-grid system in the same manner as the expense calculations for an EC-grid extension plan. However, most planned three-phase distribution line lengths are the portions needed for connection with the next/source barangay. For this reason, halves of the values, which ECs planned, are added up as three-phase distribution line lengths in a mini-grid system.
Project costs for mini-grid systems are shown in Table 5.4.30 for the base scenario, Table 5.4.31 for the reliability-oriented scenario and Table 5.4.32 for the environment-friendly scenario.
Table 5.4.30 Project Cost of Mini-Grid System (Base Scenario)
Table 5.4.31 Project Cost of Mini-Grid System (Reliability-Oriented Scenario)
Table 5.4.32 Project Cost of Mini-Grid System (Environment-Friendly Scenario)
5.5 Sensitivity Analysis on Household Electrification Improvement
All barangays in the province will be electrified by an appropriated method up to 2006, and then barangay electrification of Palawan is expected to be 100%.
After the barangay electrification target is achieved by 2006, the focus will then shift to the improvement of household electrification.
MEDP 2003 has the target of 90% household electrification (entire Philippines) by 2017. Therefore, a study targeting the household electrification level is needed for Palawan.
In the Study, two cases for the sensitivity analysis of a household electrification ratio are prepared.
5.5.1 Setting Target Household Electrification Ratio
The improvement of household electrification requires electrification in areas (e.g. sitio) far from a tapping point in a barangay. A stand-alone system is assumed to be the electrification method for the electrification of such areas in the Study10.
Figure 5.5.1 shows the image of improvement of household electrification in a barangay.
10 It is assumed that the number of connected households will increase to keep a constant household electrification ratio in a barangay electrified by
Figure 5.5.1 Image of Household Electrification Improvement
Table 5.5.1 shows these cases for sensitivity analysis.
Table 5.5.1 Cases for Analysis on Household Electrification Improvement Electrification Method
Year EC-Grid Mini-Grid Stand-Alone
2006 Target : Barangay Electrification Ratio = 100% 2007
2015
Case 1 50 35 35 Target of HH Electrification Ratio
(%) Case 2 80 35 35
5.5.2 Results of Sensitivity Analysis Tables 5.5.2 to 5.5.4 show the results of the sensitivity analysis. Table 5.5.2 Results of Sensitivity Analysis on Household Electrification Ratio (Electrification Ratio)
Scenario / CASE 2003 2006 2010 2015no Target of HH e-Ratio 40.4% 41.6% 41.3%Case 1 40.4% 48.3% 54.5%
5.6 Scenario and Case for the Master Plan In Section 5.4 the reliability-oriented scenario and environment-friendly scenario are studied
as alternatives to the base scenario (least expensive electrification scenario). In the reliability-oriented scenario, the investment cost will be 427.3 million pesos, which is more than double the cost for the base scenario. And for the environment-friendly scenario, one site for micro hydropower will be feasible even when an incentive is given.
The least expensive method will be the optimum electrification method for achieving the whole barangay electrification target, considering the finances that are available. Therefore, the Study team decided to employ the base scenario for the Master Plan.
On the other hand, 2 cases for sensitivity analysis on household electrification ratio are studied
in the Section 5.5. For case 1 under the base scenario, total investment cost will be 848.5 million pesos and it will be 1,338.3 million pesos for case 2 under the base scenario.
Considering the target household electrification level in MEDP, funding availability and villagers’ capacity to pay for electricity, the Study team decided to select case 1 for the Mater Plan.
The summary of the Base Scenario (Case 1) is shown as the Master Plan in Chapter 7.
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5.7 Economic and Financial Analysis of Palawan Rural Electrification 5.7.1 Economic Benefits
This section deals with the economic benefits of the current rural electrification plans. (1) The Methodology
There are numerous uses for electricity with varying kinds and levels of benefits. However, as the socio-economic survey in the study has revealed, the largest use of electricity in rural electrification is lighting, followed by radio and TV.
For lighting, the majority of the un-electrified households use kerosene lamps. Compared to kerosene, electric lighting provides more light with less cost per lumen. The consumer surplus from that difference is the economic benefit from electrification.
Source; Barnes et al.11
Figure 5.7.1 Economic Benefits from Electrification
The actual lumens from the lamps in use have not been measured directly by the current study,
but there are numerous existing studies. The household expenditure for lighting has been determined to be 350-400 pesos. The power demand of the households is considered to be the same with the standard households in this study. Based on these assumptions, the surpluses for various electrification methods have been determined and are shown in Table 5.7.1.
11 Barnes et al. “Quantitative Measures of Benefits from Rural Electrification in the Philippines” 2000,
If the electrification proceeds as expected and the households can enjoy the expected amount
of power, there will be significant benefits regardless of the electrification method. Even in the lowest case of SHS, the monthly benefit will amount to 1,219 pesos per household. In the highest case of a mini-grid system, this will amount to 2,000 pesos12.
In another survey (Barnes et al. 2000), the monthly household benefits per household is calculated to be US$36.75. This corresponds with the mini-grid benefit calculated above13.
Based on these figures, the economic benefits of the electrification program have been calculated for each of the electrification methods. Assumptions for each method are basically identical to those employed in the method selection. Also, the following assumptions are made for the operation; (i) EC-grid extension
It is assumed that the current PALECO/BISELCO operations will continue. Based on the financial analysis of these two ECs, they maintain stable operations. The cost has been contained except for the purchased power cost which they have no control over, and the operations suggest a reliable level in terms of technical competence.
12 The case for grid extension has not been calculated, although it will obviously produce a higher benefit due to lower cost and longer supply. 13 There is criticism of this method, which points out that the light itself seldom provides any direct benefits. Also, not all the light will be actually
“consumed”, and the consumed light will also be subject to significant diminishing marginal utility. Due to these criticisms, Barnes 2000 and others have attempted to calculate the benefit in a more direct manner. They measured benefits from TV viewing, increased education and employment. These cannot be added to the benefits from the increased lumen consumption, since that would overlap. However, the results suggest that the direct benefits are comparable or even higher than the lumen based benefits, which suggests that benefits measured by this manner cannot be overvalued.
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(ii) Mini-grid system For mini-grids, it is assumed that operations similar to the existing mini-grids will be
undertaken. For investment, the units used for method selection has been employed. For operational costs, figures similar to those of Port Barton have been used, where operations have continued long enough and have stabilized. (iii) Stand-alone system
In this calculation, half of the stand-alone systems will use SHS, and the rest will use stand- alone diesel generators. The units are based on the assumptions used for the method selection.
Table 5.7.2 Economic Analysis of the EC-Grid Extension Grid Extension Unit; HH, million Peso
In all cases, it is obvious that there are significant economic benefits to be gained from rural
electrification. 5.7.2 Financial Analysis
It has been determined that there will be significant economic gains from electrifying the rural areas, provided that the intended target households will use the expected amount of power. This will depend largely on the tariff. The standard households in this study will use 166 kWh annually. Socio-economic surveys suggest that the energy expenditure of these households is 350-400 pesos per month. If we assume that this entire amount will be allocated for electricity, the tariff should be 32 Php/kWh. This should provide considerably higher benefits, due to the difference in the quality of the energy. On the other hand, the tariff of the EC grid system is 5.6 Php/kWh and the tariffs for BAPAs is 15 Php/kWh. Therefore, 30 Php/kWh will be considered to be unfairly high and unacceptable.
Here, we shall determine the level of necessary tariff without any subsidy (i.e., the necessary level of tariff to achieve 12% IRR). Next, the level of necessary subsidy for the initial investment will be determined. (1) EC-grid extension
The financial analysis for the grid extension is shown in the next table.
Table 5.7.6 Financial Analysis of the EC-Grid Extension Grid Extension Tariff= 11.5 php/kWh Unit; HH, million Peso
In order to achieve 12% IRR, the necessary tariff level would be 11.5Php/kWh, significantly higher than the current 5.6Php/kWh. One reason for the higher tariff is the limited level of demand that the model assumes, although since most of the new connections are assumed to be households, this is not an unreasonable condition. Obviously, this level is rather high. It is difficult to achieve sufficient returns with a large amount of investment.
If we maintain the current tariff, the initial investment needs to be subsidized. Based on the model, the investment amount needs to fall to 11% of the current level, which means that 89% of the investment needs to be subsidized. (2) Mini-grid systems
In the case of mini-grids, the tariff needs to become 23 Php/kWh. Compared to the current BAPA rate of 15Php/kWh, this is high. The difference reflects the fact that the current tariff is made possible only by PGP covering the initial investment.
Table 5.7.7 Financial Analysis of the Mini-Grid System Mini Grid Tariff= 23 php/kWh Unit; HH, million Peso
For the 15 Php/kWh tariff to prevail, similar arrangements need to be made to decrease the
initial investment. The initial investment needs to become1/5 of the current level. This means that 80% of the initial investment needs to be subsidized in some way. (3) Stand-alone systems (Diesel)
For stand-alone systems (diesel), the necessary tariff will become 41 Php/kWh. Since the facility is small in scale, and the efficiency is lower, the unit cost (i.e. tariff) necessarily becomes higher.
Table 5.7.8 Financial Analysis of the Stand-Alone System (Diesel) Stand Alone Grid Tariff= 41.1 php/kWh Unit; HH, million Peso
Of course, there are cases where users pay higher tariffs. However, such high rates are only borne by those who are willing to pay that amount. The situation should differ for cases where the electrification ratio will be increased as a pseudo-universal access policy. The extreme difference among electrification methods will not be easily justified.
If we were to achieve the current BAPA tariff level of 15 Php/kWh, the investment must come down to 18% of the current level. This means that more than 80% of the investment needs to be subsidized for each generator. (4) Stand-Alone Systems (SHS)
For stand-alone systems (SHS), it is difficult to apply a tariff structure since the usage cannot be monitored and the users will virtually own the unit. Here, we will assume a loan that would include future battery replacements.
In this case, with a 10% (4000 pesos) down payment, a monthly fee of about 400 pesos will be required, which is similar to the current energy expenditure of 350-400 pesos. However, the 10% down payment will be difficult for most users. Some method will be needed to ease this burden. 5.7.3 Necessary Funds
Based on the analysis, it is obvious that the current scheme cannot be self-financed. In order to achieve an acceptable tariff level, the funds that can be generated internally will be only 11% of the necessary investment for grid extension, 20% for mini-grids, and 18% for the stand alone diesel systems. Also with stand-alone systems (SHS), some form of down payment assistance will be needed, which should amount to 2 million pesos annually.
This means that for the 220 million pesos investment that would be necessary before 2006, 130 million pesos will need to be financed from outside, and of the 310 million pesos required before 2015, 250 million will need to be financed from some outside source.
6-1
Chapter 6 EC-Grid Power Development Plan 6.1 EC-Grid Power Demand Forecast
As mentioned in Section 5.2, there are two general methods for making power demand forecasts, one is a macro-method and the other one is a micro-method. The macro-method is a rational method if it is possible to collect time-series data on economic indicators and power demand in the long run, because the data used in this method is objective information, and this method is also simple.
In the case of employing this method for a small power system like the Palawan system, however, enough attention should be paid to the future development plan in the commercial and industrial sectors, because such demand greatly affects the future power demand. Such demand should be estimated individually and be added to the forecast made by the macro-method.
According to “Medium-term Development Plan 2003 - 20121,” the development plan in the trade and industry sector is focused on tourism and agriculture, and there is no development plan for large commercial or industrial facilities. Therefore, the study does not cover the development of such large demand until 20122.
The Study employs a historical trend analysis for the EC-grid power demand forecast in Palawan. This is because the major industries in Palawan are agriculture3 and service (see Table 6.1.1), and there are little correlations between power demand and Gross Provincial Domestic Products (GPDP). In addition, there is a close correlation between population and residential demand in general. However, the only official data on population is “The Census of Population and Housing” conducted by the National Statistics Office every five years. Therefore, it is impossible to analyze a correlation of power demand with population or the number of households adequately.
Total 11,801,691 12,799,073 13,829,871 14,876,746 16,408,905 Source: PPDO
1 Prepared by the provincial development council, Province of Palawan, October 2, 2003 2 According to the interview with PALECO, a cannery (1,500 kW) and sanitary land (500 - 750 kW) will be in operation in Puerto Princesa City
in 2004. 3 Agriculture includes fishery and forestry.
6-2
6.1.1 Energy Sales Forecast
Table 6.1.2 shows the historical data on energy sales of ECs and an annual average growth rate (AAGR) by consumer type. Though the ratio of industrial consumers was about 20 % until 1997, the ratio has been under 10 % since 1998.
Table 6.1.2 Energy Sales by Consumer Type in Palawan (Unit: MWh)
PALECO Y1995 Y 1996 Y 1997 Y 1998 Y 1999 Y 2000 Y 2001 AAGRResidential 19,511 22,135 26,980 32,468 33,034 35,776 38,843 12.16%Commercial 7,350 8,498 10,390 19,761 20,396 21,980 21,278 19.38%Industrial 10,963 10,912 12,085 6,153 6,762 6,995 7,158 5.17%4
Sub Total 1,690 1,903 2,301 2,270 2,537 2,988 3,138 10.86%Total 47,041 51,481 60,903 68,950 71,785 78,273 81,229 9.53%
Source: NEA
Table 6.1.7 shows the energy sales forecast from 2004 to 2015 for each consumer type in Palawan, which is estimated by the actual energy sales of each consumer type in 2001 and the annual average growth rate of each consumer type shown in Table 6.1.2.
Next, energy sales for each consumer type are allocated to each municipality on the basis of the historical share of each municipality. Table 6.1.3 shows the 6-year average share of the energy sales in each municipality from PALECO. Puerto Princesa City is the top municipality in terms of energy sales with an average share of over 70% for all consumer types. The second is Narra, and the third is Brooke’s Point. These three municipalities, which are connected together through the backbone-grid, consume 90% of the total electric energy supplied by PALECO. When Roxas and Taytay connect to the backbone-grid in 2005, the share of energy sales in the five municipalities connected to the backbone-grid will reach nearly 95%.
4 Even though the actual annual average growth rate for industrial consumers from 1995 to 2001 was negative, the study employs the annual
average growth rate for the four years from 1998 to 2001, because industrial consumers are still in business.
The Study assumes that energy sales for each consumer type in Balabac, Cagayancillo and Agutaya are as much as 1, 1/2, 1/3 times the energy sales in Araceli, respectively in terms of peak demand and supply hours in each municipality. The Study also uses the municipality share for 1998 in all consumer types in the BISELCO service areas, because the fluctuation of the municipality share in energy sales is small, as shown in Table 6.1.4.
Table 6.1.4 Share of Energy Sales for each Municipality by Consumer Type PALECO Area Residential Commercial Industrial Public Bldg. Others
Table 6.1.8 shows the energy sales forecast from 2004 to 2015 for each municipality in Palawan, which is estimated by the energy sales forecast by consumer type and the share of energy sales for each municipality shown in Table 6.1.4.
6-4
6.1.2 Gross Generation Forecast
Gross generation is calculated using the formula below. The Study uses the system loss rate that NPC-SPUG uses in demand forecasting (see Table 6.1.5). Table 6.1.9 shows the gross generation forecast from 2004 to 2015 by municipality.
Source: NPC-SPUG Note: Including station use, transmission and distribution loss.
Rate Loss System1(MWh) SalesEnergy (MWh) Generation Gross
−=
6-5
6.1.3 Peak Demand Forecast
Peak demand is calculated using the formula below. The Study uses the load factor for each system in 2001, which was calculated on the basis of actual gross generation and peak demand (see Table 6.1.6). Table 6.1.10 shows the peak demand forecasts from 2004 to 2015 per system.
Table 6.1.6 Load Factor of each System
PALECO Area Load Factor BISELCO Area Load Factor Backbone Grid 0.62 Busuanga* 0.54 Cuyo* 0.37 Coron* 0.54 Roxas* 0.52 Culion** 0.21 Taytay** 0.22 Linapacan** 0.16 Araceli*** 0.24 El Nido** 0.20 San Vicente** 0.13 Balabac**** 0.24 Cagayancillo**** 0.24 Agutaya**** 0.24
Figure 6.1.1 Results of Power Demand Forecast (NPC-SPUG and ECs Area)
6.1.4 Demand Forecast Adjustment based on Results of Screening
The results of the screening of electrification methods mentioned in Section 5.4.3 identified that it is optimum for the barangays listed below to employ an EC-grid expansion method.
Table 6.1.11 and Table 6.1.12 show the barangays electrified with EC-grid expansion using the Base scenario and the Reliability-oriented scenario5. Regarding the supply hour conditions for estimating potential demand of these barangays, a 24-hour supply is assumed instead of a 6-hour supply, because these barangays are supplied with electricity from EC-grids that offer a 24-hour electricity supply.
Table 6.1.11 List of Barangays Electrified by EC-grid Extension (Base Scenario)
Municipality Barangay Potential HH Target HH Demand Energy Sales Gross Gen. EC-Grid
BROOKE'S POINT Imulnod 480 168 17.81 68.54 77.89PUERTO PRINCESA CITY (CAPITALBabuyan 695 209 22.15 85.27 96.9QUESON Malatgao (b) 622 218 23.11 88.94 101.07BACK BONE GRID TOTAL ADD 3955 1351 143 551 627
BACK BONE
BATARAZA
5 The result of the environment-friendly scenario is the same as the base scenario.
6-11
Table 6.1.12 List of Barangays Electrified by EC-Grid Extension (Reliability-Oriented Scenario) Municipality Barangay Potential HH Target HH Demand Energy Sales Gross Gen. EC-Grid
Name Name 2015 (Center, 2006) (kW) (MWh) (MWh) NameABORLAN Sagpangan 470 165 17.49 67.32 76.5
EL NIDO GRID TOTAL ADD 4857 1703 181 695 772SAN VICENTE ADD Santo Nino (c) 237 66 7 27 30 SAN VICENTE
SOFRONIO ESPANOLA
BACK BONE
BUSUANGA
EL NIDO
PPC
QUEZON
ROXAS
TAYTAY
BATARAZA
CORON
EL NIDO
Tables 6.1.13 through 6.1.18 show the revised EC-grid demand forecasts that consist of the
demand forecasts of Section 5.2.2 and the potential power demand of the barangays electrified by EC-grid extension mentioned above. In this connection, the potential demand is allocated between twelve years from 2004 to 2015.
6-12
AA
GR
14.1
6%
14.3
2%
15.5
1%
13.7
7%
14.5
4%
13.7
9%
14.2
7%
15.5
0%
14.6
4%
15.9
2%
14.2
7%
14.2
5%
14.3
6%
14.2
9%
AA
GR
18.2
5%
18.2
5%
18.2
5%
18.2
5%
18.2
5%
14.4
8%
2015
349,
500
62,4
77
36,3
74
13,8
16
13,7
78
2,64
1
1,17
8
2,78
8
1,49
8
2,03
0
1,17
8
394
602
488,
256
2015 2,33
2
22,7
58
3,34
3
1,04
1
29,4
74
517,
730
2014
303,
509
54,2
18
31,2
86
12,0
77
11,9
45
2,30
6
1,02
4
2,40
0
1,29
8
1,77
4
1,02
4
343
523
423,
727
2014 1,89
7
18,5
15
2,72
0
847
23,9
79
447,
706
2013
263,
999
47,1
22
26,9
42
10,5
68
10,3
70
2,01
5
892
2,06
8
1,12
6
1,55
0
892
299
455
368,
298
2013 1,55
8
15,2
04
2,23
3
696
19,6
91
387,
989
2012
230,
017
41,0
18
23,2
31
9,25
8
9,01
5
1,76
4
778
1,78
4
978
1,35
2
778
260
397
320,
630
2012 1,29
1
12,5
97
1,85
0
576
16,3
15
336,
945
2011
200,
750
35,7
61
20,0
57
8,12
0
7,84
8
1,54
6
679
1,54
1
850
1,18
0
679
227
346
279,
584
2011 1,07
9
10,5
26
1,54
6
482
13,6
33
293,
217
2010
175,
513
31,2
28
17,3
39
7,13
0
6,84
1
1,35
7
593
1,33
3
741
1,02
7
593
199
302
244,
196
2010 90
9
8,86
6
1,30
2
406
11,4
83
255,
679
2009
153,
720
27,3
13
15,0
09
6,26
8
5,97
2
1,19
2
519
1,15
4
646
892
519
174
264
213,
643
2009 77
1
7,52
3
1,10
5
344
9,74
3
223,
386
2008
134,
875
23,9
30
13,0
10
5,51
6
5,22
1
1,04
9
455
1,00
0
564
771
455
152
231
187,
230
2008 65
8
6,42
5
944
294
8,32
1
195,
551
2007
118,
555
20,9
99
11,2
93
4,85
9
4,57
1
925
399
868
494
664
399
134
203
164,
362
2007 56
6
5,51
9
811
253
7,14
8
171,
510
2006
104,
403
18,4
58
9,81
5
4,28
5
4,00
8
816
351
754
432
567
351
118
178
144,
536
2006 48
8
4,76
6
700
218
6,17
2
150,
708
2005
92,1
11
16,2
51
8,54
4
3,78
4
3,51
9
721
308
656
379
479
308
103
156
127,
321
2005 42
4
4,13
5
607
189
5,35
5
132,
676
2004
81,4
18
14,3
33
7,44
7
3,34
4
3,09
5
638
272
571
333
400
272 91 138
112,
350
2004 36
9
3,60
1
529
165
4,66
4
117,
014
PALE
CO
AR
EA
Puer
to P
rince
sa C
ity
Nar
ra
Bro
oke's
Poi
nt
Cuy
o
Rox
as
Tayt
ay
Ara
celi
El N
ido
San
Vic
ente
Bat
araz
a
Bal
abac
Cag
ayan
cillo
Agu
taya Su
b To
tal
BIS
ELC
O A
REA
Bus
uang
a
Cor
on
Cul
ion
Lina
paca
n
Sub
Tota
l
Tot
al
(in M
Wh)
Tabl
e 6.
1.13
Ene
rgy
Sale
s For
ecas
ts fr
om 2
004
to 2
015
by M
unic
ipal
ity (N
PC-S
PUG
and
EC
s Are
a, B
ase
Scen
ario
)
6-13
AA
GR
14.1
6%
14.3
2%
15.5
1%
13.7
6%
14.7
7%
14.0
2%
14.2
6%
15.5
0%
14.6
5%
15.9
3%
14.2
6%
14.2
3%
14.3
5%
14.3
0%
AA
GR
18.2
5%
18.2
5%
18.2
4%
18.2
5%
18.2
5%
14.4
8%
2015
397,
160
70,9
96
41,3
34
15,3
51
15,6
57
3,00
2
1,30
9
3,09
8
1,66
4
2,30
8
1,30
9
406
621
554,
215
2015 2,68
0
26,1
58
3,71
4
1,15
7
33,7
09
587,
924
2014
344,
896
61,6
10
35,5
52
13,4
18
13,5
74
2,62
0
1,13
8
2,66
7
1,44
2
2,01
5
1,13
8
353
540
480,
963
2014 2,18
1
21,2
81
3,02
2
941
27,4
25
508,
388
2013
299,
998
53,5
46
30,6
17
11,7
42
11,7
84
2,29
0
991
2,29
8
1,25
1
1,76
0
991
308
469
418,
045
2013 1,79
1
17,4
76
2,48
1
773
22,5
21
440,
566
2012
261,
382
46,6
09
26,4
00
10,2
87
10,2
45
2,00
4
864
1,98
3
1,08
6
1,53
6
864
268
409
363,
937
2012 1,48
4
14,4
80
2,05
6
641
18,6
61
382,
598
2011
228,
124
40,6
36
22,7
93
9,02
3
8,91
8
1,75
7
754
1,71
2
945
1,33
9
754
234
357
317,
346
2011 1,24
0
12,0
99
1,71
8
535
15,5
92
332,
938
2010
199,
446
35,4
86
19,7
05
7,92
2
7,77
4
1,54
2
659
1,48
1
823
1,16
5
659
205
312
277,
179
2010 1,04
4
10,1
91
1,44
7
451
13,1
33
290,
312
2009
174,
681
31,0
38
17,0
58
6,96
4
6,78
7
1,35
5
577
1,28
2
718
1,01
1
577
179
272
242,
499
2009 88
6
8,64
7
1,22
8
383
11,1
44
253,
643
2008
153,
266
27,1
93
14,7
86
6,12
8
5,93
3
1,19
2
506
1,11
1
627
874
506
157
238
212,
517
2008 75
7
7,38
5
1,04
9
327
9,51
8
222,
035
2007
134,
721
23,8
63
12,8
34
5,39
9
5,19
5
1,05
1
444
964
548
752
444
138
209
186,
562
2007 65
0
6,34
4
901
281
8,17
6
194,
738
2006
118,
639
20,9
75
11,1
56
4,76
2
4,55
5
927
390
838
480
642
390
121
183
164,
058
2006 56
1
5,47
8
778
242
7,05
9
171,
117
2005
104,
670
18,4
69
9,71
0
4,20
4
3,99
9
819
343
729
421
543
343
107
161
144,
518
2005 48
7
4,75
3
675
210
6,12
5
150,
643
2004
92,5
19
16,2
88
8,46
2
3,71
6
3,43
9
709
302
635
370
454
302 94 142
127,
432
2004 42
4
4,13
9
588
183
5,33
4
132,
766
PALE
CO
AR
EA
Puer
to P
rince
sa C
ity
Nar
ra
Bro
oke's
Poi
nt
Cuy
o
Rox
as
Tayt
ay
Ara
celi
El N
ido
San
Vic
ente
Bat
araz
a
Bal
abac
Cag
ayan
cillo
Agu
taya Su
b To
tal
BIS
ELC
O A
REA
Bus
uang
a
Cor
on
Cul
ion
Lina
paca
n
Sub
Tota
l
Tot
al
(in M
Wh)
Tabl
e 6.
1.14
Gro
ss G
ener
atio
n Fo
reca
sts f
rom
200
4 to
201
5 by
Mun
icip
ality
(NPC
-SPU
G a
nd E
Cs A
rea,
Bas
e Sc
enar
io)
6-14
AA
GR
14.6
7%
13.7
6% - -
14.2
9%
15.5
0%
14.6
4%
14.2
9%
14.2
6%
14.4
1%
14.1
5%
AA
GR
18.2
3%
18.2
5%
18.2
3%
18.2
7%
18.2
5%
14.4
1%
2015
96,9
71
4,75
8
- - 630
1,76
1
1,41
2
630
195
299
106,
656
2015 56
8
5,55
2
2,04
5
817
8,98
2
115,
638
2014
84,1
43
4,15
9
- - 548
1,51
6
1,22
4
548
170
260
92,5
68
2014 46
3
4,51
7
1,66
4
664
7,30
8
99,8
76
2013
73,1
25
3,63
9
- - 477
1,30
6
1,06
2
477
148
226
80,4
60
2013 38
0
3,70
9
1,36
6
546
6,00
1
86,4
61
2012
63,6
53
3,18
8
- - 416
1,12
7
922
416
129
197
70,0
48
2012 31
5
3,07
3
1,13
2
452
4,97
2
75,0
20
2011
55,4
98
2,79
7
- - 363
973
802
363
113
172
61,0
81
2011 26
3
2,56
8
946
378
4,15
5
65,2
36
2010
48,4
69
2,45
5
- - 317
842
698
317 99 150
53,3
47
2010 22
1
2,16
3
797
318
3,49
9
56,8
46
2009
42,4
01
2,15
8
- - 278
729
609
278 86 131
46,6
70
2009 18
8
1,83
5
676
270
2,96
9
49,6
39
2008
37,1
56
1,89
9
- - 244
632
532
244 76 115
40,8
98
2008 16
1
1,56
7
578
231
2,53
7
43,4
35
2007
32,6
16
1,67
3
- - 214
548
465
214 66 101
35,8
97
2007 13
8
1,34
6
496
198
2,17
8
38,0
75
2006
28,6
80
1,47
6
- - 188
476
407
188 58 88
31,5
61
2006 11
9
1,16
3
428
171
1,88
1
33,4
42
2005
25,2
63
1,30
3
- - 165
414
357
165 51 77
27,7
95
2005 10
3
1,00
9
372
148
1,63
2
29,4
27
2004
21,5
17
1,15
2
758
373
145
361
314
145 45 68
24,8
78
2004
90 878
324
129
1,42
1
26,2
99
PALE
CO
AR
EA
Bac
kbon
e G
rid*
Cuy
o
Rox
as**
Tayt
ay**
Ara
celi
El N
ido
San
Vic
ente
Bal
abac
Cag
ayan
cillo
Agu
taya Su
b To
tal
BIS
ELC
O A
REA
Bus
uang
a
Cor
on
Cul
ion
Lina
paca
n
Sub
Tota
l
Tot
al*T
he b
ackb
one-
grid
incl
udes
Pue
rto P
rince
sa C
ity, N
arra
, Bro
oke's
Poi
nt, a
nd B
atar
aza.
**R
oxas
and
Tay
tay
will
be
conn
ecte
d to
the
back
bone
-grid
in 2
005.
(in k
W)
Tabl
e 6.
1.15
Pea
k D
eman
d Fo
reca
sts f
rom
200
4 to
201
5 by
Mun
icip
ality
(NPC
-SPU
G a
nd E
Cs A
rea,
Bas
e Sc
enar
io)
6-15
AA
GR
14.1
7%
14.3
3%
15.5
6%
13.7
7%
14.9
5%
15.4
5%
14.2
7%
16.8
3%
14.7
7%
17.5
2%
14.2
7%
14.2
5%
14.3
6%
14.3
4%
AA
GR
18.2
5%
18.2
6%
18.2
5%
18.2
5%
18.2
6%
14.5
3%
2015
349,
985
62,6
04
36,8
00
13,8
16
14,3
24
3,09
9
1,17
8
3,48
3
1,52
5
3,24
8
1,17
8
394
602
492,
238
2015 2,33
2
22,8
41
3,34
3
1,04
1
29,5
57
521,
795
2014
303,
956
54,3
35
31,6
78
12,0
77
12,4
43
2,72
3
1,02
4
3,03
8
1,32
0
2,89
5
1,02
4
343
523
427,
379
2014 1,89
7
18,5
92
2,72
0
847
24,0
56
451,
435
2013
264,
407
47,2
29
27,3
00
10,5
68
10,8
18
2,39
0
892
2,64
8
1,14
6
2,57
4
892
299
455
371,
618
2013 1,55
8
15,2
74
2,23
3
696
19,7
61
391,
379
2012
230,
386
41,1
15
23,5
55
9,25
8
9,41
3
2,09
7
778
2,30
6
996
2,27
9
778
260
397
323,
618
2012 1,29
1
12,6
60
1,85
0
576
16,3
78
339,
996
2011
201,
080
35,8
48
20,3
47
8,12
0
8,19
6
1,83
7
679
2,00
5
866
2,01
0
679
227
346
282,
240
2011 1,07
9
10,5
82
1,54
6
482
13,6
89
295,
929
2010
175,
804
31,3
05
17,5
95
7,13
0
7,13
9
1,60
6
593
1,73
9
755
1,76
0
593
199
302
246,
520
2010 90
9
8,91
5
1,30
2
406
11,5
32
258,
052
2009
153,
972
27,3
80
15,2
31
6,26
8
6,22
0
1,40
0
519
1,50
2
658
1,52
7
519
174
264
215,
635
2009 77
1
7,56
5
1,10
5
344
9,78
5
225,
420
2008
135,
087
23,9
87
13,1
98
5,51
6
5,42
0
1,21
5
455
1,29
0
574
1,30
9
455
152
231
188,
890
2008 65
8
6,46
0
944
294
8,35
6
197,
246
2007
118,
728
21,0
46
11,4
46
4,85
9
4,72
0
1,05
0
399
1,10
0
502
1,10
5
399
134
203
165,
690
2007 56
6
5,54
7
811
253
7,17
6
172,
866
2006
104,
537
18,4
95
9,93
4
4,28
5
4,10
7
899
351
928
438
911
351
118
178
145,
532
2006 48
8
4,78
7
700
218
6,19
3
151,
725
2005
92,2
06
16,2
78
8,62
8
3,78
4
3,56
8
763
308
772
383
726
308
103
156
127,
985
2005 42
4
4,14
9
607
189
5,36
9
133,
354
2004
81,4
73
14,3
50
7,49
7
3,34
4
3,09
5
638
272
629
335
550
272 91 138
112,
682
2004 36
9
3,60
8
529
165
4,67
1
117,
353
PALE
CO
AR
EA
Puer
to P
rince
sa C
ity
Nar
ra
Bro
oke's
Poi
nt
Cuy
o
Rox
as
Tayt
ay
Ara
celi
El N
ido
San
Vic
ente
Bat
araz
a
Bal
abac
Cag
ayan
cillo
Agu
taya Su
b To
tal
BIS
ELC
O A
REA
Bus
uang
a
Cor
on
Cul
ion
Lina
paca
n
Sub
Tota
l
Tot
al
(in M
Wh)
Tabl
e 6.
1.16
Ene
rgy
Sale
s For
ecas
ts fro
m 2
004
to 2
015
by M
unic
ipal
ity (N
PC-S
PUG
and
EC
s Are
a, R
elia
bilit
y-O
rient
ed S
cena
rio)
6-16
AA
GR
14.1
7%
14.3
3%
15.5
6%
13.7
6%
15.1
8%
15.6
9%
14.2
6%
16.8
3%
14.7
8%
17.5
4%
14.2
6%
14.2
3%
14.3
5%
14.3
5%
AA
GR
18.2
5%
18.2
7%
18.2
4%
18.2
5%
18.2
6%
14.5
4%
2015
397,
711
71,1
41
41,8
18
15,3
51
16,2
78
3,52
2
1,30
9
3,87
0
1,69
4
3,69
1
1,30
9
406
621
558,
721
2015 2,68
0
26,2
54
3,71
4
1,15
7
33,8
05
592,
526
2014
345,
403
61,7
44
35,9
98
13,4
18
14,1
39
3,09
2
1,13
8
3,37
1
1,47
0
3,29
0
1,13
8
353
540
485,
094
2014 2,18
1
21,3
69
3,02
2
941
27,5
13
512,
607
2013
300,
461
53,6
69
31,0
24
11,7
42
12,2
92
2,71
5
991
2,93
8
1,27
6
2,92
4
991
308
469
421,
800
2013 1,79
1
17,5
56
2,48
1
773
22,6
01
444,
401
2012
261,
801
46,7
21
26,7
67
10,2
87
10,6
97
2,38
2
864
2,55
9
1,10
8
2,58
9
864
268
409
367,
316
2012 1,48
4
14,5
52
2,05
6
641
18,7
33
386,
049
2011
228,
499
40,7
36
23,1
20
9,02
3
9,31
4
2,08
8
754
2,22
4
964
2,28
2
754
234
357
320,
349
2011 1,24
0
12,1
63
1,71
8
535
15,6
56
336,
005
2010
199,
776
35,5
74
19,9
94
7,92
2
8,11
4
1,82
6
659
1,92
9
839
1,99
7
659
205
312
279,
806
2010 1,04
4
10,2
47
1,44
7
451
13,1
89
292,
995
2009
174,
967
31,1
14
17,3
07
6,96
4
7,07
0
1,59
2
577
1,66
6
731
1,73
4
577
179
272
244,
750
2009 88
6
8,69
5
1,22
8
383
11,1
92
255,
942
2008
153,
508
27,2
57
14,9
97
6,12
8
6,16
0
1,38
1
506
1,43
1
637
1,48
6
506
157
238
214,
392
2008 75
7
7,42
5
1,04
9
327
9,55
8
223,
950
2007
134,
919
23,9
15
13,0
06
5,39
9
5,36
5
1,19
3
444
1,22
0
556
1,25
4
444
138
209
188,
062
2007 65
0
6,37
6
901
281
8,20
8
196,
270
2006
118,
793
21,0
16
11,2
89
4,76
2
4,66
8
1,02
2
390
1,03
0
486
1,03
3
390
121
183
165,
183
2006 56
1
5,50
2
778
242
7,08
3
172,
266
2005
104,
779
18,4
98
9,80
5
4,20
4
4,05
6
867
343
857
425
823
343
107
161
145,
268
2005 48
7
4,76
9
675
210
6,14
1
151,
409
2004
92,5
84
16,3
05
8,51
9
3,71
6
3,43
9
709
302
699
372
624
302 94 142
127,
807
2004 42
4
4,14
7
588
183
5,34
2
133,
149
PALE
CO
AR
EA
Puer
to P
rince
sa C
ity
Nar
ra
Bro
oke's
Poi
nt
Cuy
o
Rox
as
Tayt
ay
Ara
celi
El N
ido
San
Vic
ente
Bat
araz
a
Bal
abac
Cag
ayan
cillo
Agu
taya Su
b To
tal
BIS
ELC
O A
REA
Bus
uang
a
Cor
on
Cul
ion
Lina
paca
n
Sub
Tota
l
Tot
al
(in M
Wh)
Tabl
e 6.
1.17
Gro
ss G
ener
atio
n Fo
reca
sts fr
om 2
004
to 2
015
by M
unic
ipal
ity (N
PC-S
PUG
and
ECs
Are
a, R
elia
bilit
y-O
rient
ed S
cena
rio)
6-17
AA
GR
14.7
2%
13.7
6% - -
14.2
9%
16.1
0%
14.7
0%
14.2
9%
14.2
6%
14.4
1%
14.2
1%
AA
GR
18.2
3%
18.2
8%
18.2
3%
18.2
7%
18.2
7%
14.4
7%
2015
97,8
18
4,75
8
- - 630
1,94
2
1,41
9
630
195
299
107,
691
2015 56
8
5,57
4
2,04
5
817
9,00
4
116,
695
2014
84,9
24
4,15
9
- - 548
1,68
1
1,23
0
548
170
260
93,5
20
2014 46
3
4,53
7
1,66
4
664
7,32
8
100,
848
2013
73,8
35
3,63
9
- - 477
1,45
6
1,06
7
477
148
226
81,3
25
2013 38
0
3,72
7
1,36
6
546
6,01
9
87,3
44
2012
64,2
92
3,18
8
- - 416
1,26
2
926
416
129
197
70,8
26
2012 31
5
3,08
9
1,13
2
452
4,98
8
75,8
14
2011
56,0
66
2,79
7
- - 363
1,09
3
805
363
113
172
61,7
72
2011 26
3
2,58
2
946
378
4,16
9
65,9
41
2010
48,9
66
2,45
5
- - 317
947
700
317 99 150
53,9
51
2010 22
1
2,17
5
797
318
3,51
1
57,4
62
2009
42,8
27
2,15
8
- - 278
819
610
278 86 131
47,1
87
2009 18
8
1,84
5
676
270
2,97
9
50,1
66
2008
37,5
11
1,89
9
- - 244
707
532
244 76 115
41,3
28
2008 16
1
1,57
5
578
231
2,54
5
43,8
73
2007
32,9
00
1,67
3
- - 214
608
465
214 66 101
36,2
41
2007 13
8
1,35
2
496
198
2,18
4
38,4
25
2006
28,8
93
1,47
6
- - 188
521
407
188 58 88
31,8
19
2006 11
9
1,16
7
428
171
1,88
5
33,7
04
2005
25,4
05
1,30
3
- - 165
444
357
165 51 77
27,9
67
2005 10
3
1,01
1
372
148
1,63
4
29,6
01
2004
21,5
88
1,15
2
758
373
145
376
314
145 45 68
24,9
64
2004
90 879
324
129
1,42
2
26,3
86
PALE
CO
AR
EA
Bac
kbon
e G
rid*
Cuy
o
Rox
as**
Tayt
ay**
Ara
celi
El N
ido
San
Vic
ente
Bal
abac
Cag
ayan
cillo
Agu
taya Su
b To
tal
BIS
ELC
O A
REA
Bus
uang
a
Cor
on
Cul
ion
Lina
paca
n
Sub
Tota
l
Tot
al*T
he b
ackb
one-
grid
incl
udes
Pue
rto P
rince
sa C
ity, N
arra
, Bro
oke's
Poi
nt, a
nd B
atar
aza.
**R
oxas
and
Tay
tay
will
be
conn
ecte
d to
the
back
bone
-grid
in 2
005.
(in k
W)
Tabl
e 6.
1.18
Pea
k D
eman
d Fo
reca
sts fr
om 2
004
to 2
015
by M
unic
ipal
ity (N
PC-S
PUG
and
ECs
Are
a, R
elia
bilit
y-O
rient
ed S
cena
rio)
6-18
6.2 Technical Study on the EC-Grid Power Development Plan 6.2.1 Basic Policy for the EC-Grid Power Development Plan
The EC-grid Power Development Plan will be established based on the demand forecasts including not only existing grid demand but also newly connected demand coming from the barangay electrification plan.
The EC-grid defined here contains the backbone grid (Brooke’s Point – Narra - Puerto Princesa City – Roxas – Taytay) and 10 isolated grids.
The system capacity of the backbone grid accounts for more than 80% of all grid demand in Palawan. Furthermore, it consists of several power plants and transmission facilities. Therefore, the power development planning method applied in the Philippine main grid should also be adopted for the planning in the backbone grid.
On the other hand, each of the isolated grids will have kept the same power supplying style, which composes of only a generator and distribution lines for the time being. Therefore, only a generation development plan to meet the forecasted demand should be needed for the isolated grids.
It is technically possible to interconnect between the backbone grid and other isolated grids, for example with a submarine cable. However, it is obvious that such a project is only a dream when considering the extremely expensive costs that are associated. Instead of an interconnection project, the transfer of a generator in the backbone grid system may become a good option, because a small generator in the backbone grid system tends to be more useful in a small isolated grid.
For this reason, the power development plan for the EC-grids shall be separated for the backbone grid and for isolated grids. In addition, the possibility of transferring generators to the isolated grids from the backbone grid shall be studied as one option for the optimal power development plan. (1) Basic policy for the generation development plan of the backbone grid
In order to formulate an optimal generator development plan, the study shall be conducted based on the following basic policies. (i) Optimization function should be “Least Cost”
Several different scenarios can be applied as an objective function for the optimal master plan. But the basic policy should be "least cost", under the LOLP target, environmental or other such restrictions. In the detailed study, "WASP-IV" is used for the optimization of the generation development plan, since this software is able to consider those restrictions sufficiently.
(ii) Only diesel and hydropower should be considered as a candidate plant types
A diesel generator is still the most applicable generator type in Palawan. According to the mini and micro hydropower potential survey, several potential sites seem to be listed as
6-19
candidates. But other generator types popular in the Philippine main grid, such as a gas turbine, may have no chance even if this Master Plan covers considerations up to 2015. Because the power system capacity will still be small and the infrastructure of fuel transportation may still be restricted.
Therefore, only diesel and hydropower generators should be treated as candidates to be developed in this Master Plan.
Incidentally, the locations of the potential sites can be specified, while the locations of diesel power plants to be developed are not specified even in the generation development plan of NPC-SPUG. This derives from the political matter that a new generator should be basically developed by the private sector. Therefore, some typical locations suitable for a diesel power plant shall be studied in the transmission development plan. (iii) Bunker C fuel is prohibited in the base scenario.
Though SOx emission issues affect not only this Master Plan, but also the master plan all over the Philippines, diesel generation using bunker C fuel cannot be adopted as a candidate due to the resulting violation of environmental laws. Therefore, the fuel for newly developed generators is assumed to be 'diesel' in the base scenario. However, the impact of using bunker C fuel shall be studied as a sensitive analysis in the Master Plan. (2) Basic policy for the transmission development plan of the backbone grid
Taking into account the issues regarding transmission facilities and their operations described in Section 3.5.6, a basic policy for the transmission development plan of the backbone grid should include the following direction. (i) Technical study on the grid expansion of the existing backbone grid
The existing backbone grid including on-going projects (Brooke’s Point – Narra - Puerto Princesa City – Roxas - Taytay) will have power system demand of around 97MW and a maximum power flow around 20MW between Irawan S/S and Narra S/S in 2015.
Since the transmission capacity of the 69kV transmission line is 54MW, the existing transmission line may have enough capacity until the final year of the Master Plan, and a voltage increase from 69kV to 138kV may not be proposed.
On the other hand, the total capacity of the existing transformers in 69/13.8kV substations is 40MVA, which is smaller than the total demand in 2015. Therefore, some additional transformers will be needed especially at Irawan, Narra, and Brooke’s Point S/Ss. Other technical issues may emerge from the detailed study such as voltage, reactive power and short circuit capacity. There is the possibility that those issues demand a further transmission expansion. To cope with those issues, the power system simulation software named "PSS/E" will be used for the technical study. PSS/E is well-known software around the world for power system analysis and it is also used in TRANSCO or DOE for the purpose of formulating the transmission development plan in the Philippine main grid.
6-20
(ii) Technical study on the new extension of the backbone grid According to the NPC-SPUG transmission development plan, two projects for extending the
backbone grid are planed. One is the southern extension to Bataraza and the other is the northern extension to El Nido. Moreover, a new substation between Narra S/S and Brooke’s Points S/S was proposed from PALECO for the purpose of supporting stable power supply. In this study, the necessity of those projects shall be verified mainly from the technical viewpoints.
Regarding a grid extension to a new power plant, a transmission extension project for a hydropower plant shall be studied concretely because its location can be specified. However a transmission extension project for a diesel power plant shall be examined based on a typical location because its location cannot be estimated as explained in the policy for a generation development plan. (iii) Technical study on existing system improvement
As pointed out in Section 3.5.6, the existing backbone grid has two pressing issues. The first is the need to improve the power system configuration around Puerto Princesa City, and the second is the need to improve the capacity limitation of the Power Barge. The second issue will disappear after the transfer of the Power Barge in 2004.
To solve the first issue, an improvement project shall be planed in consideration of other transmission expansion plans, not within the issue itself, because transmission expansion around Puerto Princesa City will be essential to meet the increase in power demand in the near future. So it is supposed to be a more economical way to study this issue in cooperation with those projects. (3) Basic policy of the power development plan for isolated grids
In the ten isolated grids, the basic configuration in which a power plant sends electricity to distribution directly will not be changed until the final year of the Master Plan. For this reason, only a generation development plan shall be studied for those areas.
Incidentally, the transfer of existing generators may become a good option because the worth of an existing small generator in the backbone grid becomes lower after an interconnection. Therefore, the transfer option of existing generators from the backbone grid to isolated grids will be considered in the planning. 6.2.2 Procedure of the EC-Grid Power Development Plan (1) Procedure of the power development plan for the backbone grid
The procedure of the power development plan for the backbone grid will be applied basically in the same method as for the Philippine main grid. However, such an orthodox planning procedure has not been applied to the formulation of the power development plan for Palawan until now. This means that there is no example data for power development planning.
Therefore this study starts from the collection of primary data and proceeds along the workflow described in Figure 6.2.1. At the same time, the data arranged through the study will be transferred to the related organizations as one of the outcomes.
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Figure 6.2.1 Workflow for the Power Development Plan of the Backbone Grid
In the generation development plan, the load duration curve and target reliability (LOLP)
shall be determined as the basic parameters of the Master Plan based on the demand forecasts studied in Section 6.1.3. After that, an optimal generation development plan shall be studied using the power development simulation software “WASP-IV”.
In the transmission development plan, power demand by region needed for power flow analysis is estimated based on the demand forecasts. Then an optimal transmission development plan shall be examined using the power system simulation software “PSS/E”.
Finally, a generation and transmission development plan shall be merged into the optimal power development plan.
The main procedures adopted for this study are as follows. (2) Procedure for the estimation of a load duration curve
In a generation development plan, the economics are changeable due to the hourly or seasonal fluctuation of power demand. WASP-IV is able to analyze the production costs for each power plant by modifying power demand features into a seasonal load duration curve.
Unfortunately, power demand data of the backbone grid, which has no computer system such as SCADA or EMS, has been recorded in handwriting. So the Study team built up a load duration curve based on operation records from January to December of 2003.
Data Collection for Existing Generator
Data Collection for Candidate Generator
Load Duration Curve Estimation
Determination of Reliability Target (LOLP)
Simulation of Power Development
Optimal Generation Development Plan
Generation Development Plan
Data Collection for Existing Grid
Data Collection for Expanding
Criteria for Grid Expansion
Regional Power & Load Balance
Simulation of Power System Analysis
Optimal Transmission Development Plan
Transmission Development Plan
Optimal Power Development Plan
Barangay Electrification Plan
Demand Forecast in the EC-gridPeak Demand & Gross Generation (System Total)
Regional Peak Demand
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The actual records of power demand include blackout or brownout incidents. Moreover, the load factor of the actual records is unequal to the estimated one for the future.
In order to use a generation development plan, a load duration curve is arranged from the original data using the following procedure. (i) Correction to avoid the influence of blackout
After examining the power demand records of daily load curves, records affected by blackouts were corrected from the previous and later weeks’ data.
An example of a daily load curve before and after correction is shown in Figure 6.2.2.
Figure 6.2.2 Result of Correction to Avoid the Influence of Blackouts (ii) Correction to adjust the load factor to the forecasted demand
In the demand forecast, peak demand is estimated with gross generation and a load factor. However the load factor of the actual records is not always the same as the forecasted one. That's the reason why this correction was necessary to adjust the load factor.
The load factor after the correction in (i) was 58.58% in 2003, while the forecasted one was 62.5%. The load duration curve after the adjustment by the load factor is shown in Figure 6.2.3.
Figure 6.2.3 Result of Correction to Adjust the Load Factor
(iii) Formulation of the seasonal load duration curve WASP-IV has a function to simulate a power development plan with less than 12 terms in
each year. In this study, dividing the load duration curve into 2 terms per year is supposed to be reasonable, taking into account the power demand features of the water flow characteristics.
The final result of the load duration curve for the generation development plan is shown in Figure 6.2.4.
Figure 6.2.4 Seasonal Load Duration Curve for the Generation Development Plan
(3) Procedure for the determination of the target reliability (LOLP)
In order to apply an orthodox planning procedure in the Philippine main grid to the backbone grid, consensus of the optimal system reliability, which has been unclear in the missionary electrification area, is seen as being essential.
In this section, the procedure for the determination of the target reliability and its trial calculation results are discussed. (i) Procedure for the determination of the LOLP target
In consideration of additional cost for upgrading reliability, benefits to the community and economic conditions of Palawan, optimal system reliability is studied for the transmission and distribution network of the Palawan main island.
In general, power system reliability is divided into two components; namely the sufficiency (Adequacy) of regular power generation and transmission and distribution capacity, and the stability (Security) of the network at the time of failure.
Both components are important in a highly developed power system. However, since the electric power system of the province of Palawan is still expanding, the sufficiency of installed generation capacity becomes the more important component. For this reason, the Study team will make an assessment using the following steps, based on the viewpoint of optimum installed capacity (reserve capacity).
Load Duration Curve (1st Harf)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Load Duration Curve (2nd Harf)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
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(a) Analysis of reserve capacity and LOLP (Loss-of-Load Probability) The correlation between the reserve capacity (margin) and LOLP is analyzed quantitatively
by using the recent data of the generator maintenance interval, generator tripping probability, annual power duration curve and other pertinent data. (b) Analysis of MC and LOLP
After making the quantitative analysis concerning incremental capacity and its marginal cost with the data of fixed cost and variable cost for generator, the correlation between MC and LOLP is analyzed quantitatively in accordance with the result of (a). (c) Analysis of the optimal power system reliability
The optimal power system reliability can be estimated through a comparison between the MC-LOLP curve and the benefit from the reliability improvement if the benefit can be ascertained. In this Study, the opportunity cost named “Energy Not Served (ENS)” in WASP is used as this benefit. The ENS is normally 0.5 to 2.0 $/kWh in Southeast Asian countries. However as these countries decide the optimal LOLP firstly from a political viewpoint, and so the basis of the ENS value is not clear. Therefore, the Study team decides the optimal system reliability in collaboration with the related counterparts in consideration of the result of the sensitivity analysis about the ENS or the standard level of the LOLP in the Philippine grid. (ii) Assumptions for trial calculation
The assumptions used for the trial calculation of LOLP are shown in Table 6.2.1.
Table 6.2.1 Assumptions for the Trial Calculation of LOLP Item Assumption for LOLP Analysis
(0.5MW Step Variable) Load Duration Curve Record in 2003 (Jan-Dec) Forced Outage Rate 4%(NPC-SPUG) - 7%(IPP) Maintenance Day 22 days/year (Mid. Speed) – 37 days/year (High Speed) Spinning Reserve 10%, 1MW Energy Not Served Cost 0.5$/kWh Exchange Rate 55PHP/$ Calculation Software WASP-IV
In this trial, the target year for the assessment is 2006, when additional capacity will become
necessary. In order to evaluate the relationship between the reliability and capacity reserves, expansion capacity is changed from 0 to 7MW by 0.5MW increments.
In these assumptions, a forced outage rate (FOR) is one of the key factors for the system reliability. FOR is very difficult to estimate, because it is changeable by year or by maintenance conditions. The typical FOR figure is applied to this trial calculation.
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(iii) Trial calculation result of LOLP (a) Analysis of reserve capacity and LOLP (Loss-of-Load Probability)
The trial calculation result for LOLP is shown in Figure 6.2.5. If the reserve ratio goes up, LOLP becomes lower. This relationship is easily conveyed in this graph.
The main concern is what target number should be applied to the backbone-grid. In the Philippine main grid, the LOLP target is set at 1day/year, while the target for the reserve margin is also set at 13.2%. According to the study results for the Philippine main grid, which was carried out by another JICA project, 1 day/year of LOLP is equivalent to around 11% in a reserve margin.
If the LOLP target is set at 1 day/year in the backbone grid, around 18% in a reserve will be needed, since the required reserve becomes higher when the grid is smaller.
Figure 6.2.5 Trial Calculation Result for Relationship between LOLP and Reserve Ratio (b) Analysis of MC and LOLP
In order to estimate the optimal system reliability, the trial analysis is studied from an economical approach. Figure 6.2.6 shows the relationship between incremental benefit and loss for a different LOLP.
In this figure, additional cost includes additional capacity cost, additional operation cost and smaller increase in sales revenue. On the other hand, recovered un-served loss is the worth of recovered social loss, and it is calculated with “recovered un-served energy” multiplied by “Energy Not Served Cost”. In this trial study 0.5$/kWh is applied for the “Energy Not Served Cost”.
From this graph, it can be seen that the most economical target for LOLP is around 6 days/year. The figure of 6 days/year is equivalent to approximately 7% of the reserve ratio. This, however, seems to be too low.
0
1
2
3
4
5
6
7
8
9
0% 5% 10% 15% 20% 25% 30%
Reserve Ratio (%)
LOLP
(D
ay/Y
ear)
Target of Philippine Main Grid LOLP: 1 day/year Reserve Ratio: 13.2%
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Objective Function: B = SUM (I-S+F+M+U)
in discounted net present valueI : Capital Cost S : Salvage Value F : Fuel Cost M : O&M Cost (Operation & Maintenance)U : Un-served Energy Cost
(c) Analysis of the optimal power system reliability Generally speaking, a LOLP target is decided from a political viewpoint, not from an
economical viewpoint. Taking into account the limited missionary electrification budget, a LOLP target in the backbone-grid will be more than 1 day/year. However, if the target exceeds 3 days/year, significant brownout will be observed.
In conclusion, 2 days/year is recommended for the LOLP target in the backbone-grid. Therefore the technical study hereafter is progressed based on the LOLP target of 2 days/year. Figure 6.2.6 Trial Calculation Result of Optimal LOLP from the Viewpoint of Cost & Benefit (4) Simulation method of the generator development plan
In order to formulate an optimal generation development plan, WASP-IV used all over the world is adopted as the simulation software in this study. WASP-IV can determine the optimal solution by using a dynamic programming method. Furthermore, as it was already introduced to the Department of Energy through another JICA Development Study, the power development plan can be studied with the common software in the Philippines.
The feature of the calculation method in WASP-IV is as follows.
(i) Object function The object function inside of WASP-IV is "Least
Cost" with restrictions on target reliability. The cost considered in the object function consists
of capital cost, fuel cost, O&M cost and also un-served energy cost.
Regarding the capital cost, the Salvage Value defined as the remaining worth of the remaining lifetime makes it possible add considerations for depreciation.
0
200
400
600
800
1000
1200
1400
1600
1800
0 1 2 3 4 5 6 7 8 9
LOLP (day/year)
Incr
emen
tal B
enef
it &
Los
s(1
00
0$
/Yea
r)
Additional Cost
Recovered Unserved Loss
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(ii) Power demand The power demand inside of WASP-IV is expressed with the load duration curve, not with
the chronological load curve. By using this load duration curve and the forecasted peak demand, the power demand characteristics for the simulation are generated. The merit ordered dispatching similar to the actual operation is simulated by taking the variable cost of each power plant into consideration.
Moreover WASP-IV can make simulations with different load duration curves for each term of the year, because the power demand feature or the water flow characteristics are sometimes different from term by term.
Figure 6.2.7 Data Input Image of Power Demand in WASP-IV (iii) Generator characteristic
WASP-IV can simulate every type of generator, such as hydropower, thermal and nuclear power plants. As for a hydropower plants, the probability of the generator output is expressed with the seasonal data of water flow rate, average output and minimum output. In regards to thermal plants, cost data such as heat value, heat rate, O&M cost (fix, variable) and probabilistic output data (for example forced outage rate, spinning reserve ratio and maintenance day) are input into WASP-IV to calculate an optimal solution for the generation development plan. (iv) Optimization
Firstly, WASP-IV calculates the merit order of each existing power plant based on the variable cost. Secondly, the merit order of candidate plants is calculated in the same way. Finally, the optimal generation development pattern including capital cost of a candidate plant is calculated automatically by using a dynamic programming method.
(5) Simulation method of the transmission development plan
In the transmission development plan, the power system simulation software PSS/E is applied for this study. PSS/E is very famous around the world and can calculate every type of power system analysis such as power flow, short-circuit capacity and dynamic stability. PSS/E is also introduced to TRANSCO and DOE. Therefore the result of the transmission development plan in Palawan may be used commonly in the Philippines.
6.2.3 Technical Study on the Generation Development Plan for the Backbone Grid (1) Scenario of the generator development plan
The scenario of the generation development plan is studied here based on the basic policy described in Section 6.2.1, taking into account the demand forecasts determined in accordance with the three scenario of the barangay electrification plan in Section 5.1.2. (i) Base scenario
The base scenario is defined as the generation development plan based on "Least Cost", which is the same policy as the barangay electrification plan. In the base scenario, the forecasted demand consists of the existing EC-grid demand and newly electrified demand in 6 barangays where the distribution line is extended.
Incidentally, only one pattern for the forecasted demand is considered in the EC-grid study, because there is no difference for the EC-grid demand, even if the electrification ratio is changed in the barangay electrification plan after 2006. (ii) Reliability-oriented scenario
The reliability-oriented scenario corresponds to "Reliability-oriented electrification method (Alternative Case 1)" in the barangay electrification plan. In this case, the power demand is slightly bigger than the base scenario, as the number of electrified barangay by distribution line extension becomes 56.
Other conditions are the same as those in the base scenario. (iii) Environment-friendly scenario
The environment-friendly scenario corresponds to "Environment-friendly electrification method (Alternative Case 2)" in the barangay electrification plan. In the barangay electrification plan, it is assumed that hydropower and renewable energy are given special weightings in selecting the electrification method, while soft loans are applied only to hydropower in the EC-grid power development plan. Some case studies will be carried out on condition that the discount rate is lower than the NEDA standard of 12%.
Other conditions are the same as those in the base scenario. (iv) Environment deregulation scenario
As discussed in the policy for the generation development plan, developing a diesel generator using bunker C fuel is prohibited in the base scenario. However, PDP 2004, which is the power development plan for the Philippine main grid, assumes there will be the development of diesel generators using bunker C fuel. If this issue becomes a big problem throughout the Philippines, there is the possibility that the environment law will deregulated and diesel generators with bunker C fuel become a candidate. Therefore the study will be conducted based on the bunker C fuel in this scenario. Other conditions are the same as those in the base scenario.
Those four scenarios are summarized in Table 6.2.2.
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Table 6.2.2 Scenarios for the Generation Development Plan Scenario System Demand LOLP Diesel Fuel Discount Rate
Base Scenario Existing EC-grid Demand + 6 Barangay Demand
2 days/year Only Diesel 12% (NEDA)
Reliability-Oriented Scenario
Existing EC-grid Demand + 56 Barangay Demand
2 days/year Only Diesel 12% (NEDA)
Environment Friendly Scenario
Existing EC-grid Demand + 6 Barangay Demand
2 days/year Only Diesel Diesel: 12% (NEDA) Hydro: Discounted Rate
Environment Deregulation Scenario
Existing EC-grid Demand + 6 Barangay Demand
2 days/year Bunker C or Diesel
12% (NEDA)
After the study of these four scenarios, sensitivity analysis will be conducted against the key
assumptions in the base scenario. The items for sensitivity analysis are shown in Table 6.2.3.
Table 6.2.3 Sensitivity Analysis for the Generation Development Plan
Scenario Object of Sensitivity Analysis Case Study LOLP 1 day/year, 3 days/year Diesel Plant Construction Cost 30% off from Base Svenario
Base Scenario
Transfer of Gen Set in Roxas & Taytay DPP Transfer in 2007 (2) Assumptions for the generation development plan (i) Assumptions for the generation development simulation
The presumed parameter for the generator development simulation by WASP-IV is described in Table 6.2.4.
The figure of the parameter is determined based on the following direction.
Study year The calculation output of WASP-IV tends to be advantageous to a small generator near the
final year of the study, because the capital cost becomes lower. In order to avoid this influence, final year of the study was set at 2020, 5 years longer than the Master Plan period.
No. of periods
2 periods per year are selected, since the power demand feature and hydropower generator characteristics are different between the rainy season and dry season.
LOLP
2 days/year (0.548%) was determined as the reliability target in the base scenario in accordance with the pre-study results. The magnitude of the LOLP target figure will be verified in the sensitivity analysis.
Plant data
Plant data is determined based on the monthly operation report (2002-2003) and planning data (2004) by NPC-SPUG.
6-30
Table 6.2.4 Basic Assumptions for the Generator Development Simulation
Category Items Assumption Data Source Study Year 2003-2020 No of Period 2 periods per year No of Hydro Conditions 2 conditions per year LOLP 2 days/year (=0.548%)
General Index
Depreciation Method Straight Depreciation Method Generator Capacity Past Record of Dependable Capacity NPC-SPUG Monthly Report Heat Rate Past Record of Heat Rate NPC-SPUG Monthly Report Fuel Cost Past Record of Fuel Cost NPC-SPUG Monthly Report O&M Cost Planed O&M for Universal Charge NPC-SPUG MEDP 2004 Forced Outage Rate NPC-SPUG : 4% Typical for Diesel Scheduled Maintenance Mid. Speed : 22 days/year (6%) JICA Capacity Building
Existing Plant Data
Spinning Reserve 10% Operating Target of NPC-SPUG
(ii) Projects considered in the generation development plan
As of January 2004 the projects that were already approved or supposed to be approved by NPC-SPUG were considered in this Master Plan. Table 6.2.5 shows the list of the projects.
The transfer of Power Barge 106 from Palawan to Iloilo was suddenly decided in January 2004, because of the urgent need for a countermeasure against the power shortage caused by the restriction of Panay-Negros Interconnection. At the same time, the diesel generator temporarily leased (capacity is not certain as of January in 2004) will be installed inside of the Irawan substation. The contract term of the lease is 1 year, however, the contract may be extended at least in 2006. Therefore, plans in this study call for the removal of this temporary generator in 2006.
By the way, the existing generators in Roxas and Taytay can be used in the isolated grids after realizing the backbone transmission. This transfer plan is not considered in the base scenario, but will be evaluated in the sensitivity analysis.
Table 6.2.5 Projects Considered in the Generation Development Plan Year Project Dependable Capacity Remark
Transfer of Power Barge 106 -8.4MW Approved by NPC-SPUG Installation of Temporal Gen Set in Irawan S/S +8.4MW Approved by NPC-SPUG Transfer of Gen Set in Brooke’s Point DPP - Already not operational
2004
Transfer of Gen Set in Narra DPP - Already not operational 2006 Removal of Temporal Gen Set in Irawan S/S -8.4MW Supposed by the Study team
Remark: The dependable capacity of the temporal genset in Irawan S/S is based on assumptions by the Study team.
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(iii) Candidate generator models for the generation development plan Diesel and hydropower generators are presumed to be the candidate generator types. The assumed specifications of a candidate generator are as follows.
(a) Candidate model for diesel generation The assumed specifications of a diesel generator for the generation development plan are as
follows. Generator capacity
5 types of capacity from 500kWto 20,000kW are prepared, taking economics of scale into consideration.
The unit capacity should be lower than from 5% to 10% against the power system capacity in contemplation of the Spinning Reserve Ratio (10%) or frequency dropping influence in the case of generator tripping. As the peak demand in 2015 is estimated at 96,989kW, the unit capacity was selected to be 5,000kW with a maximum of 10,000kW.
Available capacity is set at 90% of the rated capacity, because dependable capacity tends to decline year by year.
Construction cost (including interest during construction term)
The construction cost is estimated based on the project budget in 2004 by NPC-SPUG, in consideration of the assumed construction cost in the Philippine main grid study assisted by JICA (50MW, 1,140$/kW, without interest).
The construction cost should be determined carefully, because this assumption sometimes changes the results dramatically. In this study, the construction cost is calculated from the project budget, because NPC-SPUG has not been dealing with a big generator project recently. According to NPC-SPUG, this budget is calculated under the condition of a reliable generator, such as one made in Europe or Japan. The study has to pay attention to the cost since the construction cost will be reduced if a cheaper generator is adopted.
Therefore, a sensitivity analysis will be conducted regarding the construction cost.
Fuel type The fuel type is presumed to be diesel except for the environment deregulation scenario. In the environment deregulation scenario, the fuel type is assumed to be bunker C fuel for a
generator with more than 1,500kW.
Fuel cost, heat rate, O&M cost The fuel cost is estimated from the actual records over the 12 months in 2003 by
NPC-SPUG. The fuel cost is very different between Puerto Princesa City and the isolated grids where transportation cost is high. In the generation development plan, the location of a candidate diesel generator is not specified, but fuel cost is applied at the level around Puerto Princesa City.
Regarding the heat rate, a 500kW generator is determined from the operation records held by NPC-SPUG, while a 1,500kW or greater generator is estimated from the Delta-P IPP model. The O&M cost is estimated from the operation records held by NPC-SPUG.
Plant life
Plant life is set at 15 years, from the assumption that the generator life is around 100,000 hours and the capacity factor is around 75%.
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Table 6.2.6 shows the assumptions of candidate generator models for diesel generation.
Table 6.2.6 Candidate Generator Model for Diesel Generation Abbreviation D005 D015 D050 D100 D200 Rated Capacity kW 500 1,500 5,000 10,000 20,000 Capacity by Unit kW 1x500 1x1,500 1x5,000 2x5,000 2x10,000 Dependable Capacity kW 450 1,350 4,500 9,000 18,000 Construction Cost $/kW 1,600 1,452 1,399 1,353 1,310
Fuel Type Diesel Except Environment Deregulation Case: Diesel Environment Deregulation scenario: Bunker C
Heat Rate (at 25%) Kcal/kWh 2,780 2,595 Incremental Heat Rate Kcal/kWh 2,288 1,995 Fixed O&M Cost $/kW-month 8.12 4.86 2.76 2.00 1.45 Variable O&M Cost c/kWh 2.20 Life Time Year 15 Construction Period Year 2
(b) Candidate model for hydropower generation
In regards to hydropower generation, as studied in Section 4.1.1, 7 candidate sites where the production cost is reasonable and grid access is feasible are studied in the generation development plan. Among those points, only Babuyan has a reservoir and the others are the run-of-river type. In the case of the run-of-river type, there is the possibility that the output becomes 0MW during drought conditions. In the WASP-IV, the probability of output is calculated based on the water flow probability.
The candidate generation model for hydropower is shown in Table 6.2.3. In this table, the data is translated into the WASP-IV format.
Among those candidates, only Babuyan will need 3 years for the construction period. This means that the commissioning year will be later than 2007 even if the construction project starts in 2004. Therefore, it is stipulated in the generation development simulation that Babuyan is available later than 2007.
Tabl
e 6.
2.7
Can
dida
te S
ites f
or H
ydro
pow
er G
ener
atio
n A
bbre
viat
ion
BY
N
BD
Y1
MTG
B
RB
R
TAL
CB
B
BR
K
BB
Loca
tion
Bab
uyan
B
indu
yan
Mal
atga
o B
aron
g B
aron
g Ta
laka
igan
Cab
inbi
n B
arak
i B
atan
g B
atan
g In
stal
led
Cap
acity
K
W
5,60
0 60
0 2,
200
620
990
800
840
6,70
0 D
epen
dabl
e C
apac
ity
KW
5,
600
600
2,20
0 62
0 99
0 80
0 84
0 6,
700
Stor
age
Cap
acity
M
Wh
50.0
0
Con
stru
ctio
n C
ost
$/kW
3,
765.
9 1,
984.
4 2,
423.
4 2,
329.
6 2,
516.
8 2,
641.
0 3,
802.
1 3,
267.
5 Pe
riod
1-C
ondi
tion
1 M
Wh
7,76
8.0
801.
0 3,
924.
0 77
0.0
1,80
0.0
975.
0 1,
462.
0 3,
406.
0 Pe
riod
2-C
ondi
tion
1 M
Wh
14,1
35.0
2,
241.
0 7,
335.
0 2,
328.
0 3,
364.
0 32
82.0
2,
914.
0 15
,956
.0
Perio
d 1-
Con
ditio
n 2
MW
h 10
,772
.0
1,96
0.0
6,81
1.0
2066
.0
3,12
4.0
2809
.0
2,70
6.0
11,0
09.0
In
flow
Ene
rgy
Perio
d 2-
Con
ditio
n 2
MW
h 16
,822
.0
2,62
8.0
9,63
6.0
2715
.0
4336
.0
3504
.0
3,67
9.0
28,4
47.0
Pe
riod
1-C
ondi
tion
1 M
Wh
6125
.0
0 Pe
riod
2-C
ondi
tion
1 M
Wh
1311
6.0
0 Pe
riod
1-C
ondi
tion
2 M
Wh
9423
.0
0 M
inim
um
Gen
erat
ion
Perio
d 2-
Con
ditio
n 2
MW
h 16
067.
0 0
Perio
d 1-
Con
ditio
n 1
kW
5600
.0
182.
9 89
6.0
175.
9 41
1.1
222.
7 33
3.8
777.
7 Pe
riod
2-C
ondi
tion
1 kW
56
00.0
51
1.7
1,67
5.0
531.
7 76
8.2
749.
6 66
5.4
3,64
3.0
Perio
d 1-
Con
ditio
n 2
kW
5600
.0
447.
7 1,
556.
0 47
1.8
713.
3 64
1.4
617.
9 2,
514.
0 Av
erag
e C
apac
ity
Perio
d 2-
Con
ditio
n 2
kW
5600
.0
600.
0 2,
200.
0 62
0.0
990.
0 80
0.0
840.
0 64
95
Fixe
d O
&M
Cos
t $/
kW-m
onth
0.89
2.
89
Con
stru
ctio
n Pe
riod
Year
3
2 Pl
ant L
ife
Year
40
6-33
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(3) Results of the technical study on the generation development plan (i) Optimal generation development plan for each scenario (a) Base scenario
The simulation results for a generation development plan in the base scenario are shown in Table 6.2.8.
Table 6.2.8 Simulation Results for the Generation Development Plan (Base Scenario)
In the base scenario the generation development plan of Hydropower: 11.05MW (6 sites),
Diesel: 79.5MW (Dependable Capacity: 71.55MW), Total: 90.55MW (Dependable Capacity: 82.6MW) is the one with the least cost. (b) Reliability-oriented scenario
The simulation results for a generation development plan in the reliability-oriented scenario are shown in Table 6.2.9. The simulation conditions are the same except for the power demand.
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Table 6.2.9 Simulation Results for the Generation Development Plan (Reliability-Oriented Scenario)
In the reliability-oriented scenario, the order of the generator development is a little different
from the base scenario due to slightly increased demand. At the same time, the amount of developed capacity became a little more than that in the base scenario. Since the reliability-oriented scenario is given almost the same power demand as that in the base scenario, there is no significant difference between these two scenarios. (c) Environment-friendly scenario
In the environment-friendly scenario, assuming the usage of a soft loan only for hydropower generation, the discount rate for the construction cost is changed from 11% to 8%.
The simulation results for the generation development plan in the case of an 8% discount rate are shown in Table 6.2.10, and in the case of a 11% discount rate in Table 6.2.11.
Table 6.2.10 Simulation Results for the Generation Development Plan (Environment-Friendly Scenario: Discount Rate=8%)
Since the economical advantage of hydropower increases, all of the hydropower candidates
are to be developed, including Batang Batang, which was not to be developed in the base scenario.
Seeing this result from a different angle, the economical inferiority of Batang Batang against a diesel generator is very small. So this inferiority is covered if the discount rate is decreased to under 11%. (d) Environment deregulation scenario
In the environment deregulation scenario, it is presumed that diesel is used for 500kW generators and bunker C fuel is used for 1,500kW and greater generators.
The simulation results for the generation development plan in this scenario are shown in Table 6.2.12.
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Table 6.2.12 Simulation Results for the Generation Development Plan (Environment Deregulation Scenario)
Although the economical advantage of diesel is improved, the amount of the developed
generator capacity until 2015 becomes the same as that for base scenario. This result shows that 6-point hydropower candidates, except Batang Batang, have an economical advantage against a diesel candidate using bunker C fuel. However, SOx environment regulations affect the power development plan including the policy on electric tariffs. Therefore, attention will be given to this issue when the Master Plan is revised. (ii) Comparison among the scenarios from discounted cash flow
Except when the environment-friendly scenario adopts different discount rates, the three scenarios are compared from the viewpoint of a discounted cash flow.
The discounted cash flow defined here is based on the object function of WASP-IV; the formula is as follows.
"Capital Cost - Salvage Value (worth of remaining life) + Fuel Cost +O&M Cost"
Figure 6.2.8 shows the yearly and accumulated discounted cash flow in each scenario. It is
common that the cost will increase in 2006 because of the removal of the temporary generator. The result in the reliability-oriented scenario is almost the same as the base scenario. The result in the environment deregulation scenario shows that it is the least expensive
development plan and there is a significant difference from the other two scenarios. The accumulated discounted cash flow for 12 years, from 2004 to 2015, is $10.54 Million (-8.1%) lower than that of the base scenario. This difference is equivalent to the cost for the environmental protection.
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Figure 6.2.8 Comparison of the Discounted Cash Flow by Scenario (iii) Sensitivity analysis (a) Sensitivity analysis of LOLP target
The LOLP target in the backbone grid is assumed to be "2 days/year" until here. In this sensitivity analysis, the LOLP target is changed to "1 day/year" and "3 days/year" in the case of the base scenario.
Figure 6.2.9 shows the comparison of the LOLP and reserve ratio when the LOLP target is changed.
Figure 6.2.9 Comparison of LOLP and Reserve Ratio
If the LOLP target is set at 3 days/year, reserve capacity becomes lower than the maximum generator unit capacity (Installed Capacity: 5,000kW, Dependable Capacity: 4,500kW) in several years. This result means that the risk of power shortages becomes larger, especially in the case of generator trouble involving the largest unit.
On the other hand, if the LOLP target is set at 1 day/year, the amount of the developed
generator capacity until 2015 becomes 95.55MW, while 90.55MW in the base scenario. Furthermore, reserve capacity will exceed 10MW in the later years when using the 1 day/year scenario.
Secondly, the comparison result from discounted cash flow is shown in Figure 6.2.10.
Figure 6.2.10 Comparison of the Discounted Cash Flow by LOLP Target
If the LOLP target is set at 1 day/year, the accumulated DCF for 12 years from 2004 to 2015 is $2.9Million (+2.2%) higher than that in the base scenario, while in for the 3 day/year scenario it is $1.3Million (-1.0%) lower. Those differences are equivalent to the cost for reliability. (b) Sensitivity analysis of construction cost for a diesel generators
Generally the price of a diesel generator depends on the production maker or its quality. In the base scenario, the construction cost of the candidate diesel generator is presumed to be
a reliable one, such as one made in Europe or Japan. In this sensitivity analysis, the construction cost is assumed to be 30% lower than that in the base scenario in order to verify its influence.
The assumed construction cost for the sensitivity analysis is shown in Table 6.2.13
This simulation result of the optimal generation development by WASP-IV is the same as
the results in the base scenario, although the discounted cash flow is increased. From this result, it can be said that the impact on the construction cost of a diesel generator is
Base Scenario (Yearly) LOLP 1d/y (Yearly)LOLP 3d/y (Yearly) Base Scenario (Accm.)LOLP 1d/y (Accm.) LOLP 3d/y (Accm.)
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(c) Sensitivity analysis in the case of transferring the existing generators After the backbone grid extension to Roxas and Taytay, Roxas DPP (Dependable Capacity:
870kW) and Taytay DPP (Dependable Capacity: 550kW), which are operated in the isolated grids, will no longer be essential. Moreover, the production costs of those power plants are higher than the cost of a generator around Puerto Princesa City due to the difference in fuel transportation cost. Therefore the plan to transfer the generators in Roxas DPP and Taytay DPP to the isolated grids is assumed to be reasonable.
Nevertheless, the schedule for the generator transfers has to be planed in accordance with the Palawan Backbone Transmission Project for the northern area, because the project will be delayed even if its commissioning is planned in 2004 as explained in Section 3.5.6.
For this reason, the commissioning year of the transmission line is assumed to be in 2006 and the transfer of the generators is planed for 2007 in this sensitivity analysis.
The simulation results of the generation development plan by WASP-IV are shown in Table 6.2.14.
Table 6.2.14 Simulation Result of Generation Development Plan (Sensitivity Analysis of the Existing Generator Transfer)
In comparison with the base scenario, the year to be developed is changed from 2009 to
2007 for Babuyan and from 2010 to 2009 for Baraki. The total capacity of the generator development becomes 92.05MW (Dependable Capacity: 83.95MW), which is larger than 90.55MW (Dependable Capacity: 82.6MW) in the base scenario because of the reduced existing capacity by the transfer.
From the viewpoint of the discounted cash flow including capital cost, the accumulated discounted cash flow in this case is increased by $0.99Million in comparison with the one in the base scenario. This result indicates that there is no advantage if those generators are simply abolished. However, seeing this result only from the perspective of O&M cost, the accumulated discounted cash flow of the O&M cost is decreased by $2.3Million in comparison with the one in the base scenario as shown in Figure 6.2.11. Since the transfer cost per one
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generator is expected to be less than around $0.01 Million, the total transfer cost for 7 generators will be recovered easily.
In conclusion, the project to transfer the existing generators in Roxas DPP and Taytay DPP should be included in the Master Plan for the purpose of more economical planning.
Figure 6.2.11 Comparison of the Discounted Cash Flow in O&M Cost (Sensitivity Analysis of the Existing Generator Transfer)
(4) Summary of the generation development plan (i) Summary of the simulation results for the generation development plan
The simulation results of the generation development plan in each scenario and each sensitivity analysis are summarized in Table 6.2.15.
Table 6.2.15 Summary of Results for the Generation Development Plan Additional
Dependable Capacity(2004-2015, MW) Scenario
Diesel Hydro
Implication from Technical Study
Base Scenario 71.55 11.05 6 sites of hydro power plant are developed. Reliability-Oriented Scenario 72.90 11.05 The total capacity of generator development increases due
to the raised demand. Environment Friendly Scenario 68.40 17.75 If a soft loan with interest of less than 11% is applied, all of
the hydro power plants (7 sites) are developed Environment Deregulation Scenario 71.55 11.05
The result is almost the same as that in the Base Scenario. (6 sites of hydro power plants still have an economical advantage in comparison with Bunker C diesel generator.)
LOLP 1 day/year 76.05 11.05 The accumulated DCF is increased by 2.0%. Generators with small capacity tend to be developed.
LOLP 3 day/year 70.20 11.05 The accumulated DCF is decreased by 1.0%. The reserve ratio becomes lower than the capacity of largest unit in some years.
Diesel Const. Cost 71.55 11.05 Even if the construction cost is cheaper by 30% than the one in the Base Scenario, the simulation results for the generator development plan is the same as that in the Base Scenario.
Sens
itivi
ty A
naly
sis
Gen. Transfer 72.90 11.05
The transfer of generators in Roxas DPP and Taytay DPP after the accomplishment of Palawan Backbone Transmission to the northern part makes the generator development plan more economical.
Taking into account of above results, the generator development policy for the backbone grid
should be as follows.
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Generator Development Plan Scenario
The demand forecast for the generator development plan is based on the one in the base scenario, because the difference of the forecasted demand coming from the scenario of barangay electrification is not so large.
Regarding the concrete project, the on-going projects planed by NPC-SPUG are considered in the Master Plan. Plans call for the existing generators in Roxas DPP and Taytay DPP to be transferred to other isolated grids in 2007.
As for the finalized optimal generator development plan, not only the basic scenario, but also an optional scenario including the development of Batang Batang is recommended taking account of the feasibility of the soft loan for a hydropower generation.
SOx Environmental Regulations SOx environmental regulations do not affect the generation development plan
since 6 hydropower candidates have an economical advantage over diesel with bunker C fuel. However, it may affect the power development policy including the electric tariff. Therefore, regulation trends should be watched carefully in the rolling plan.
LOLP Target The recommended LOLP target is around 2 days/year in the backbone grid. If the
target is set at more than 3 days/year, the risk of power shortage increases because the reserve ratio may become lower than the capacity of the maximum generator unit. On the other hand, if the target is set at 1 day/year, the generation cost increases by 2.2%, and this results in higher supplying cost in Palawan where a subsidy is required from the Philippine main grid.
(ii) Optimization of the generation development plan
Up to this point, the generation development plan was discussed based on the simulation result optimized in theory. As the result, for example small generators with 1,500kW capacity were developed in 2004 in the base scenario. This result derives from the calculation method that optimizes the cost during the period until 2020.
In order to avoid this issue, the generation development plan is re-optimized into a more practical one. To put it concretely, a new assumption that the diesel generator capacity developed after 2011 is restricted at 5MW.
In the Study, the base scenario is shown in the Master Plan for power development. Table
6.2.16 shows the case of "Base Scenario for the Optimal Generation Development Plan". At the same time, "Option Scenario for the Optimal Generation Development Plan" where
soft loans for hydropower generation are considered is shown in Table 6.2.17.
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Table 6.2.16 Generation Development Plan (Base Scenario for the Optimal Generation Development) Diesel Hydro
The scenario of the transmission development plan studied here is based on the basic policy described in Section 6.2.1 and the results of the generation development plan.
(i) Base scenario
In the base scenario, the transmission development plan is studied based on the demand-and-supply conditions obtained from "Base Scenario for the Optimal Generation Development".
The technical issues in Table 6.2.18 will be also be verified in this study.
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Table 6.2.18 Technical Issues and Related Projects for the Transmission Development Plan Technical Issue Project
Construction of Puerto Princesa S/S Construction of Abo-Abo S/S
Existing Grid Expansion
Additional Transformer (Puerto Princesa City, Narra, Brooke's Point) Construction of Bataraza Transmission Line & S/S New Grid Expansion Construction of El Nido Transmission Line & S/S
Improvement of System Configuration around Puerto Princesa City
Separation of Generator Circuit and Distribution Circuit
(ii) Option scenario
In the Option Scenario, the transmission development plan is studied based on demand and supply conditions obtained from "Option Scenario for the Optimal Generation Development".
Since the demand-and-supply conditions are the same as those in the base scenario until 2013, the study will be carried out only on the condition that 2015 is the representative year. (2) Assumptions for the transmission development plan (i) Access transmission to a power plant (a) Access transmission to a hydropower plant
The optimal method is to have an access transmission line connected to an existing substation directly, taking account of the system reliability against a system fault. However the construction cost tends to become too much especially in the case that the location of hydropower plant is far from a substation. Therefore, for the access transmission it is presumed that the line is connected to the existing substation if the connecting location is near the substation, while the line is tapped to the existing transmission line in other scenario.
As for Cabinbin Hydropower Plant with 800kW capacity, a pre-feasibility study was carried out in the past on the assumption that the power plant is tapped to the existing 13.8kV distribution line at Brooke’s Point. In this study, only Cabinbin is assumed to be constructed in this configuration, because it is the least cost method and sufficiently technically feasible.
The geographical location of hydropower plant and the power system diagram is shown in Figure 6.2.12 and Figure 6.2.13.
(b) Access transmission to a diesel power plant
As discussed at "Basic Policy for the Generation Development Plan" in Section 6.2.1, the concrete location of the future diesel generator is not specified. But two locations suitable for the generation development can be pointed out on the assumption that the generator is constructed only by NPC-SPUG. These locations are shown on Figure 6.2.14.
Inside of the Irawan substation
Inside the Irawan substation is the most suitable location for a land-based diesel power plant, because the Irawan substation has enough land owned by NPC-SPUG and this location is moderately far from the city center of Puerto Princesa City. Furthermore the
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cost for the access transmission is very cheap because the Irawan substation is the base of the backbone grid.
Sta Lucia area
The Sta Lucia area is located just in the opposite side from the city center of Puerto Princesa City across the Puerto Princesa Bay. In this location, there is a port that was equipped by a quarry company in the past, but is not used at present. As the port has a water depth of 8ft, a power barge with large capacity can be anchored here. Moreover, the distance from the port to the existing 69kV backbone transmission is only 4.2km. Therefore the Sta Lucia area is the most suitable location for a power barge diesel power plant.
In the transmission development plan of the Study, the location of the developed diesel
power plant is presumed to be inside of the Irawan substation, which is the most feasible and suitable location for a land-based diesel power plant.
(ii) Standards for the transmission expansion planning of the backbone grid
Since NPC-SPUG recently started the construction of transmission in the missionary electrification area, the standards for the transmission expansion planning have not been clearly determined.
In this Master Plan, the transmission development plan will be formulated based on the following standards.
(a) Standard for system reliability
The "N-1 rule" is generally adopted as a standard for system reliability in the world including the Philippine main grid. The "N-1 rule" means that no interruptions happen even if one of the transmission facilities becomes out-of-service.
However, the present backbone grid cannot meet the "N-1 Rule", because it consists of single transmission lines and single transformers.
For this reason, the necessity of transmission development is judged from the condition that all facilities are in service.
(b) Standard for transmission capacity
The transmission capacity is usually decided from "thermal limit", "voltage limit" and "system stability limit" in a regular grid like the Philippine main grid. In the backbone grid, the transmission capacity will be judged in the same way fundamentally.
The figure of thermal limitation for a transmission line is applied as the same number used in NPC-SPUG. Regarding transformers, the rated capacity is used as its limitation. The voltage deviation is allowed within 5%.
As for the system stability, it is expected that there is no technical problems in the backbone grid. Therefore, some typical faults are checked through dynamic simulation.
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(c) Point of time and condition for the power flow study The point of time for the power flow study will be selected at the time of the maximum
demand. Although the output of hydropower power plants is changed with probability, the output is
set at the average output because the average output nearly equals the rated capacity in the 2nd half when the maximum demand is recorded.
The power factor is set at 80%; the standard figure in NPC-SPUG.
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Figure 6.2.12 Power System Map of the Backbone Grid (2015)
Barong Barong ('06)
Malatgao ('06) Talakaigan ('06)
Bataraza S/S
Baraki ('09)
Babuyan ('07)
Batang Batang ('15op)
Cabinbin ('06)
Brooke’s Point S/S (Tr: '12)
Narra S/S (Tr: '08, '13)
Irawan S/S
Puerto Princesa DPP
Delta-P IPP
Roxas S/S ('06)
Taytay S/S ('06)
Abo-Abo S/S ('06)
El Nido S/S ('15)
Existing Transmission Line Planed Transmission Line (On-going project) Planed Transmission Line (Proposed Project) Existing Substation Planed Substation (On-going project) Planed Substation (Proposed Project)
Puerto Princesa S/S ('09, Tr: '14)
Power System Map of the Backbone Grid
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Brooke’sPoint
Narra
Roxas
Taytay
Puerto Princesa
Irawan Delta-P
PowerBarge
El Nido
Bataraza
Babuyan
Malatgao
Talakaigan
Baraki
Batang Batang
Barong Barong
Cabinbin5.0km
7.0km
13.0km
9.1km
9.3km
8.8km
25.0km
17.5km
4.8km
7.8km
56.9km
40.2km
70.9km
76.61km
86.96km
111.09km
65.14km
Abo-Abo 32.0km
44.6km
11.0km 7.0km
5.2km
28.0km
75.0km
Power System Diagram of the Backbone Grid
Figure 6.2.13 Power System Diagram of the Backbone Grid (2015)
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Irawan S/S
Puerto Princesa DPP
Sta Lucia DPP
0 1 2 3 4km
Power Barge 10666 6 99 9 kk k VV V PP P aa a ll l aa a ww w
aa a nn n BB Baa a cc c kk k bb b oo o nn n ee e TT T rr r aa a nn n ss s mm m
ee e ll l tt t aa a PP P -- - PP P PP P DD DPP P PP P LL L
ii i nn n ee e
Irawan DPP
Figure 6.2.14 Power System Map around Puerto Princesa City
Power System Map around Puerto Princesa City
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(3) Results of the study on the transmission development plan (i) Expansion of the existing backbone grid (a) Construction of Puerto Princesa substation
At present, the transformer capacity in the Irawan substation is 20MVA, while the line capacity of the 13.8kV tie line (single circuit) from the Irawan substation to Puerto Princesa City DPP is 12.5MVA. This means the capacity sent to the center of Puerto Princesa City is restricted by the capacity of the 13.8kV tie line.
On the other hand, the power flow on the 13.8kV tie line is nearly equal to the figure when subtracting the total output in Delta-P and Puerto Princesa City DPP from the demand in Puerto Princesa City. Here the output of these power plants is assumed as the following two cases, the power flow on the 13.8kV tie line with 90% of a load factor is shown in Figure 6.2.15.
Case A: Dependable Capacity of Delta-P (15,000kW) Case B: Dependable Capacity of Delta-P and Puerto Princesa City DPP (20,400kW)
Figure 6.2.15 Forecast Power Flow on the 13.8kV Tie Line
The 13.8kV tie line between the Irawan substation and Puerto Princesa City DPP is originally designed with a double circuit and 69kV insulator as shown Figure 6.2.16. Although the tie line is used at a single circuit due to the broken insulator in one circuit, the capacity becomes double (25MW) if the insulators are repaired. Therefore the doubled circuit is an essential condition in 2008 when the power flow is expected to exceed the present capacity at a single circuit (Case A).
Secondly, an additional transformer will be needed at the Irawan substation in 2009 when the power flow will exceed the present transformer capacity (Case A). However the transformer addition in the Irawan substation is not seen as a good solution, because other countermeasures will be essential in the distribution system to send power from the Irawan substation to the city center of Puerto Princesa City.
If the tie line can be energized at 69kV and a new 69/13.8kV substation is constructed inside of the Puerto Princesa City DPP, this plan may became the optimal plan with the least cost and with a reliable configuration. According to the rough study, some wood poles of the tie line are not suited for use at 69kV because the distance between a conductor and a pole is too narrow. But it is feasible enough to use the tie line at 69kV as long as reinforcements are planed.
For this reason, the construction of the Puerto Princesa substation is recommended in 2009.
To summarize the technical study results, the transmission development plan becomes as follows.
2008 Doubled circuits for the 13.8kV tie line 2009 Voltage step-up for the tie line from 13.8kV to 69kV
Construction of the 69/13.8kV Puerto Princesa substation (40MVA) 2014 69/13.8kV additional transformers (40MVA) in the Puerto Princesa substation
(b) Construction of the Abo-Abo substation
At present, the Quezon area located on the west coast of the Palawan main island is supplied from the Narra substation through a distribution line owned by PALECO. In this area, there is a problem in that the voltage becomes low due to the long distribution line. For this reason, PALECO is requesting NPC-SPUG to construct a new substation that supplies the power to the Quezon area.
This issue was already studied in Section 6.2.4, and it was recommended that a new substation should be installed around Abo-Abo. In conclusion, the transmission development plan considers the construction of an Abo-Abo substation in 2006, taking into account its construction term. (c) Additional transformer in the Narra and Brooke's Point substation
The forecasted power flow of the existing transformer in the Narra and Brooke's Point substation is shown in Figure 6.2.17. In this case, the power factor is regulated at 90% by installing the capacitor at 13.8kV bus.
According to this result, additional transformers should be planed as follows. 2008 69/13.8kV Additional Transformer (5MVA) in the Narra substation 2012 69/13.8kV Additional Transformer (5MVA) in the Brooke's Point substation 2013 69/13.8kV Additional Transformer (5MVA) in the Narra substation
Figure 6.2.16 Present Tie Line
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Figure 6.2.17 Forecasted Power Flow on the Transformer in the Narra S/S, Brooke's Point S/S (ii) New extension of the backbone grid (a) Construction of the Bataraza transmission line and substation
According to the transmission development plan by NPC-SPUG, construction projects involving a new transmission line from Brooke's Point to Bataraza and a new substation in Bataraza are planed in 2007. It is said that a nickel mining company in Bataraza requested NPC-SPUG to send power, and that's the reason those projects are planed. This nickel mining company already has generators of its own. Since there is no contract between NPC-SPUG and the nickel mining company, these projects cannot be accepted formally in the Master Plan.
One the other hand, the Bataraza area is already supplied from the Brooke's Point substation through a distribution line owned by PALECO. According to the studies from the distribution side, a new substation in Bataraza is not essential from the viewpoint of power supply for the residential demand.
For these reasons, the construction project of the Bataraza transmission line and substation is not included into the Master Plan. After a contract is realized, these projects should be planed formally. (b) Construction of the El Nido transmission line and substation
According to the transmission development plan by NPC-SPUG, construction projects of a new transmission line from Taytay to El Nido and a new substation in El Nido are planed for 2007. The El Nido area is already supplied from the El Nido DPP owned by NPC-SPUG wit 12-hour operations. This means the project should be for the purpose of economical supply, and the construction cost of those transmission facilities should be recovered from the benefit of the generation cost being reduced by the interconnection.
For this reason, those projects are evaluated from the economical standpoint. The assumption for the evaluation of grid extension to El Nido and the study results are
shown in Tables 6.2.19 and 6.2.20.
02,0004,0006,0008,000
10,00012,00014,00016,000
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
Pow
er F
low
, Cap
acity
(kV
A)
Power Flow (Narra Tr)Power Flow (Brooke's Point Tr)Existing Tr Capacity
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Table 6.2.19 Assumptions for the Evaluation of Grid Extension to El Nido El Nido Isolated Grid backbone grid
Table 6.2.20 Evaluation Results of Grid Extension to El Nido
10 year 15 year 22 year NPV 1000$ -2,972 -1,398 1,574 IRR % -6% 8% 15%
It can be said that the larger the power system capacity grows the better the economic benefit becomes; however the benefit is still small around 2010.
For this reason, the construction project of the El Nido transmission line and substation is planed for 2015, the final year of the Master Plan. (iii) Improvement of the power system configuration around Puerto Princesa City
Since Power Barge 106 will be transferred and temporary diesel generator will be installed inside of the Irawan substation in 2004, the system configuration will be improved at the same time. Moreover the system configuration will be improved after the construction of the Puerto Princesa substation that is recommended for 2009.
Therefore, the improvement project for the purpose of the separation of the generator circuit and the distribution circuit should be planed in collaboration with the Puerto Princesa substation project.
In conclusion, the recommended system configuration in 2009 is shown in Figure 6.2.18.
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Figure 6.2.18 Recommended System Configuration around Puerto Princesa City (4) Results of the power system simulation
In order to verify the technical study results for the transmission development in detail, a power system simulation using PSS/E was carried out. (i) Results of the power flow analysis
The power flow analysis was executed under the conditions for 2006 and 2015 as the typical years. Two calculation scenarios, with/without Batang Batang, were executed for the conditions in 2015.
Through the analysis, it is verified that there are no technical problems as long as the recommended projects are put into practice. For example, the power flow calculation result is shown in Figure 6.2.19. (ii) Result of the short circuit capacity analysis
The short circuit capacity analysis was executed under the same conditions as the power flow analysis. The results indicated no technical problems. For example, the short circuit capacity calculation results are shown in Figure 6.2.20.
PALECO DPP
S/S
Puerto Princesa
Irawan
Delta-P PowerBarge
PALECO
S/S
Irawan
Delta-P
DPP
S/S
DPP
Puerto Princesa
PALECO
Present in 2009
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(5) Summary of the transmission development plan As the result of the technical study, the Master Plan should include the following
transmission development plan. Access transmission lines to power plants
The access transmission lines to hydropower plants are planed in accordance with the hydropower generation development plan.
The access transmission lines to diesel power plants are ignored in the Master Plan, because no transmission facility will be required as long as a generator will be installed in the Irawan substation. It is also the most practical plan.
Expansion projects of the backbone grid The following projects shown in Table 6.2.21 are considered in the Master Plan.
Table 6.2.21 Expansion Projects of the Backbone Grid Year Transmission Substation 2006 69kV Puerto Princesa City - Roxas T/L
2008 Doubled Circuit of 13.8kV Tie Line 69/13.8kV Add. Tr . in Narra S/S 2009 Voltage step-up of Tie Line to 69kV 69/13.8kV Puerto Princesa S/S 2012 69/13.8kV Add. Tr . in Brooke's Point 2013 69/13.8kV Add. Tr . in Narra 2014 69/13.8kV Add. Tr in Puerto Princesa S/S 2015 69kV Taytay-El Nido T/L 69/13.8kV El Nido S/S
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Figure 6.2.19 Power Flow Calculation Result in the Backbone Grid (2015)
Transmission line, Transformer Upper: active power (MW) Lower: reactive power (MVar)
Bus Upper: voltage (PU) Lower: voltage (kV)
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Figure 6.2.20 Short Circuit Capacity Calculation Result in the Backbone Grid (2015)
Upper: short circuit current (A) Lower: phase of current (degree)
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6.2.5 Technical Study on the Power System Operation Plan for the Backbone Grid (1) Basic policy for the power system operation plan of the backbone grid
The power system operation of the backbone grid just started in 2000. Since the system capacity is still small, the facilities for operation are very simple and the power systems operation relies on manpower. According to the generation development plan of the backbone grid, the peak demand will reach 96,971W with 120,550kW of installed capacity in 2015 and there is the possibility that the system operations will be beyond its ability without reinforcement for these operation.
In this section, the necessity of the reinforcement for the system operation will be discussed mainly from the technical viewpoint.
The investment for the power system operation is basically for the purpose of improving reliability. So decisions should be made taking into account the priorities compared with other investment such as the electrification project. (2) Technical study on the power system operation plan
In the backbone grid at present, the minimum facility is equipped for the power system operation, for instance radio equipment or protection relays. In a large power system like the Philippine main grid, for example, the following equipment are installed.
SCADA/EMS System EMS (Energy Management System) controls the generator automatically, while
SCASA (Supervisory Control And Data Acquisition System) controls a switch-gear in a substation remotely. These computer systems are installed in the dispatching center where the whole power system is managed.
In the Philippine main grid, the computer system previously installed was replaced in 2002 with a brand-new system through the National Load Dispatching Center Project loaned by World Bank.
System Stabilizing Equipment
The System Stabilizing Equipment prevents system-wide blackouts by performing emergency control such as load shedding.
In the Philippine main grid, ALD (Automatic Load Dropping) is installed throughout the power system, which executes load shedding in accordance with the settings shown in Table 6.2.22 automatically when system frequency declines.
Other equipment named SPS (System Preservation Scheme) is also installed to prevent generator step-out.
The necessity of this type of equipment is studied hereafter.
Table 6.2.22 ALD Setting in the Philippine Main Grid
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(i) Necessity of dispatching center According to the transmission development plan, the number of substations will become 6
(7 if Abo-Abo S/S is included) by 2015, which is still small from the viewpoint of the necessity of the SCADA system. But 6 sites for the hydropower plan will be developed by 2009 from the result of the generation development plan. A diesel power plant where fuel is stored is difficult to operate remotely, while a hydropower plant is easy as it is operated remotely in Japan. Therefore it is worth studying a dispatching center that controls not only a substation but also a hydropower plant remotely. (a) Estimated construction cost of Palawan dispatching center
The construction cost of the EMS/SCADA system for the National load dispatching center where the Philippine main grid is managed is 19.2 million US$, and the construction cost of telecommunication system reaches 35 million US$. For the backbone grid, where the system capacity is very small, a cheaper edition of the SCADA named “Mini-SCADA” can be applied.
The roughly estimated construction cost of the Palawan dispatching center using the Mini-SCADA is shown in Table 6.2.23.
Table 6.2.23 Estimated Construction Cost of the Palawan Dispatching Center
Category Particulars Foreign (thousand US$)
Local (thousand Php)
SCADA System (Hardware & Software) 300 Remote Terminal Unit (RTUs) 260
SCADA System
Intelligent Electronic Device (meters) 120 Uninterruptible Power Supply (UPS) 40
Control Center 3 Substations 6 Relay Stations (with genset) 36
Chargers and Batteries
Hydro Power Stations 18 Telecom System Option 1: Microwave Radio System
Option 2: UHF Radio System Option 3: VSAT Communication System
1,000 700 500
Building 10,000Control Center Air-conditioning & Ventilation System 1,000Building 2,900Relay Stations
(Not needed for VSAT) Air-conditioning & Ventilation System 120Total Option 1: Microwave Radio System
Option 2: UHF Radio System Option 3: VSAT Communication System
1,763 1,463 1,263
14,02014,02011,000
(b) Economic evaluation of the Palawan dispatching center
The dispatching center will contribute to the cost reduction for the operator by controlling a substation and a hydropower plant remotely. On the other hand, the additional operation cost for a technical expert and the additional maintenance cost for SCADA and telecommunication systems are required.
Here the economic considerations for the Palawan dispatching center are roughly evaluated based on the following assumptions.
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Number of employees (in comparison with no dispatching center)
No of Site No of Engineer No of Electrician Substation 6 - -24 Hydropower Plant 6 -6 -24
Construction cost of SCADA and telecom system 1,263,000$ + 11,000,000PHP (VSAT Communication System)
Equipment life of SCADA and telecom system 15 years
Maintenance cost (per year) SCADA and telecom: 1% of the construction cost Building: 0.8% of the construction cost
Discount rate 12%
The evaluation result is NPV: -53 million pesos and IRR: -7.2%. This results show that
there is no benefit for the dispatching center from just the economic standpoint. However the operation in the backbone grid will become complex in 2015, since the grid
will have more than 30 generator units (diesel & hydropower) and more than 100MW in installed capacity.
Therefore the dispatching center should be constructed in 2015, taking into account such benefits as the O&M cost reduction and the system reliability improvement. (ii) Necessity of system stabilizing equipment
As described in Section 3.5.4, 2% of the gross generation was lost due to blackouts; mostly caused by system-wide blackouts. The fundamental cause is derived from the system configuration around Puerto Princesa City, however, some parts of the loss may be recovered if system stabilizing equipment were installed.
On the other hand, system blackouts can be restored in 30 minutes now. However, it will take more than one hour in 2015, when the system capacity will be around 100MW.
In the transmission development plan, an expansion project around Puerto Princesa City is recommended in 2009 in accordance with the constriction of the Puerto Princesa substation.
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This project will contribute greatly to improved system reliability. But the risk of system blackouts cannot be removed completely. If ALD can recover 0.1% of the gross generation, the energy sales will be increased by 0.53GWh. This figure is equivalent to 2.9 million pesos of income on the condition the electricity price being 5.5Php/kWh. Taking into consideration the investment cost for ALD, which is estimated at around 1 million pesos, this project is supposed to be feasible enough.
In conclusion, it is recommended that ALD should be installed in 2009, when the system
configuration is improved around Puerto Princesa City. (iii) Necessity of modernization of work for power system operations
Modernization is required not only for a dispatching center, but also for fundamental operations of the power system. For example, power system analysis, which is essential for power system planning grid system operations, is not carried out sufficiently within NPC-SPUG. As for the recording of operation, not only is a great deal of effort spent on making these records, but also the data of the operations is not managed well because there are no personal computers in the power plants and the substations.
The construction of the dispatching center is recommended in 2015. However, these improvements for the daily operations should be addressed with as soon as possible. (3) Summary of the Power System Operation Plan
As the result of technical study for the power system operation plan, the following plan should be included into the Master Plan.
Dispatching Center
The dispatching center should be installed around 2015, the final year of the Master Plan.
But this plan should be revised in the rolling plan taking into account the actual operation condition, because this project has insufficient economic benefits.
System Stabilizing Equipment ALD, which can prevent system blackouts in the case of frequency dropping,
should be installed in 2009 when the system configuration around Puerto Princesa City is improved.
6.2.6 Technical Study on the Power Development Plan for the Isolated Grids (1) Assumptions for the power development plan of the isolated grids
The power development plan for the other isolated grids will be studied based on the basic policy described in Section 6.2.1.
The assumptions for the power development plan of isolated grids are as follows.
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Reserve capacity In the isolated grids where a few generators are operated, the reliability target of LOLP
is not useful, because the probability of calculated reliability is not linear and too complex. For this reason, the "Reliability Index" explained in Section 3.5.2 is applied for the
decision of power development. If the plan becomes a two-year consecutive development plan, two units will be developed at the same time.
New generator installation project As of January in 2004, the on-going projects approved by NPC-SPUG are presumed to
be put into service in 2005. Busuanga : 2 x 500kW Cuyo : 4 x 500kW
Type of diesel generators and its selection The candidate type of diesel generator and the conditions in order to select the
generator type are shown in Table 6.2.24. The capacity of the generator shall be selected in consideration of the power system
capacity. So the condition to select the generation type is based on the peak demand, except for the transferred generator from the backbone grid.
Table 6.2.24 Diesel Generator Type and its Selection
The transfers of the existing generators whose worth decreases after the accomplishment of the backbone grid are considered in order to use those generators in the isolated grids. But the generators in the Narra and Brooke's Point DPP are abolished in this plan, because the generators already reach their expected lifespan.
Concretely, the following generators are planed for use within the Palawan Province.
Table 6.2.25 Generators Transferred from the Backbone Grid
Renovation of Generators Some of the existing generators will need to be renovated before 2015, because some of
those are already near their expected lifespan. However, the Master Plan does not refer to the renovation.
(2) Result of the technical study on the power development plan for the isolated grids (i) Developed capacity
The study results on the developed capacity in each isolated grid are shown in Table 6.2.26. Power shortages will happen in some areas in 2004. However, the feasible year of generator
construction is assumed to be 2005 except for Busuanga and Cuyo, where the power development projects are now on-going.
In Table 6.2.26, 6 generators developed in 2007 (marked in the table) are transferred from the backbone grid. One 260kW gen-set is assumed to be transferred to another province.
Table 6.2.26 Results of Developed Capacity in the Isolated Grids
The study results for the Reliability Index in each isolated grid are shown in Figure 6.2.21. In 2004, the Reliability Index becomes below "1" in El Nido, San Vicente, Culion,
Linapacan and Agutaya. In fact, in Linapacan the Reliability Index actually becomes minus. Therefore, a very severe situation for supplying power can be expected even if all generators are in service.
Figure 6.2.21 Result of Reliability Index in the Isolated Grids
(3) Summary of the Power Development Plan for the Isolated Grids The technical study results for the isolated grids are summarized as follow.
Power Development
The total capacity developed during 2004 to 2015 is 23,532kW in rated capacity and 21,280kW in dependable capacity, including the transferred generators from the backbone grid.
In 2004 some generators are being developed in Busuanga and Cuyo. However, the shortage of power is expected in the other islands. Therefore, the power development project should be started as soon as possible to complete it by 2005.
Generator Transfer from the Backbone Grid On the assumption that the backbone grid will be completed in 2006, the transfer
of generators to the isolated grids is planned for 2007. In this Master Plan, the generators with 260kW capacity are transferred to San Vicente, Linapacan and Araceli, while the generators with 163kW are transferred to Balabac, Cagayancillo and Agutaya.
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Chapter 7 Master Plan for the Power Development in Palawan Province 7.1 Current Status of Power Sector in Palawan Province 7.1.1 Status of Electrification (1) Status of Barangay Electrification
Table 7.1.1 Status of Electrification (As of end of December, 2003)
7.3.2 Power Development Plan for the Backbone Grid
(1) Power development plan for the backbone grid (a) Generation development plan for the backbone grid
As a result of the detailed technical study, the generation development projects based on the optimal generation development plan are shown in Table 7.3.2.
For 2014 and 2015 the JICA Study team recommends two scenarios for optimal generation development. One is the Base Scenario (A) and the other is the Optional Scenario (B) that takes into consideration the environment.
Table 7.3.2 Project List for the Generation Development Plan of the Backbone Grid
Year Project GeneratorType
Rated Capacity
(kW)
Dependable Capacity
(kW) Remark
(Transfer of Power Barge 106) Bunker C (14,400) (8,400) On-going 2004
7.3.3 Transmission Development and Power System Operation Plans for the Backbone Grid (1) Transmission development and power system operation plans in the backbone grid
The proposed projects for the development of transmission lines, substations and system operation equipment are shown in Tables 7.3.4, 7.3.5 and 7.3.6
Table 7.3.4 Project List for the Transmission Line Development Plan
Year Project Project Type
Distance (km) Note
69kV Puerto Princesa-Roxas T/L New T/L 111.1 On-going
69kV Roxas-Taytay T/L New T/L 65.1 On-going
69kV Malatgao Hydro T/L New T/L 9.1 69kV Barong Barong Hydro T/L New T/L 7.0 69kV Talakaigan Hydro T/L New T/L 9.3
2006
13.8kV Cabinbin Hydro S-T/L New S-T/L 5.0 2007 69kV Babuyan Hydro T/L New T/L 25.0 2008 13.8kV Tie Line (Doubled Circuit) Rehabilitation 11.0
69kV Baraki Hydro T/L New T/L 8.8 2009 69kV Tie Line (Voltage step-up ) Rehabilitation 11.0 A 69kV Taytay-El Nido T/L New T/L 75.0 Base Scenario
69kV Taytay-El Nido T/L New T/L 75.0
2015
B Batang Batang Hydro T/L New T/L 13.0
Option Scenario
Table 7.3.5 Project List for the Substation Development Plan
Year Project Project Type
Capacity (kVA) Note
69/13.8kV Roxas S/S New S/S 5,000 69/13.8kV Taytay S/S New S/S 5,000
2006
69/13.8kV Abo-Abo S/S New S/S 5,000 2008 69/13.8kV Transformer (Narra S/S) Additional Tr. 5,000 2009 69/13.8kV Puerto Princesa S/S New S/S 40,000 2012 69/13.8kV Transformer (Brooke's S/S) Additional Tr. 5,000 2013 69/13.8kV Transformer (Narra S/S) Additional Tr. 5,000 2014 69/13.8kV Transformer (Puerto S/S) Additional Tr. 40,000 2015 69/13.8kV El Nido S/S New S/S 5,000
Table 7.3.6 Project List for the Power System Operation Plan Year Project Project Type Remark 2009 ALD System System Stabilizing Equipment 2015 Palawan Dispatching Center SCADA/ EMS System
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(2) Future power system configuration of the backbone grid The power system map and configuration of the backbone grid in 2015 are as shown in
Figures 7.3.4 and 7.3.5.
Figure 7.3.4 Power System Map of the Backbone Grid (2015)
7.3.4 Investment Costs for the EC-Grids Power Development Plan The investment costs for the EC-grid power development plan are summarized in Table
7.3.7. In this table, investment costs for one project are calculated at the commissioning year with the interest for construction term. Costs for the temporally leased generator projects in 2004 are not included.
Table 7.3.7 Investment Costs for the EC-Grids Power Development Plan
(million Php) Generation Transmission
Year Backbone Isolated Subtotal T/L S/S Operation Subtotal
Chapter 8 Recommendations for Achievement of the Master Plan for Power Development in Palawan Province
8.1 Issues in Implementation of the Master Plan 8.1.1 Outlook for Assurance of Funding Sources for Electrification in Palawan Province
The electrification of all barangays in Palawan Province by the end of 2006 as noted in the master plan would require the electrification of the 160 barangays there that had not been electrified as of December 2003 over a period of about three years. However, the financing required for this work is still under heavy constraints. As compared to the island of Luzon, Palawan is saddled with poor geographical conditions that would drive up facility construction costs considerably. (In Luzon, the cost of electrification by extension of the grid averages an estimated 1 million pesos per barangay, but the corresponding cost in Palawan is about three times as much.) The financial constraints are therefore particularly serious in its case.
Let us consider the financial outlook for electrification plans in 2004. The main prospective
funding sources are outlays from independent power producers (IPPs) under the Adopt-a-Barangay Program, subsidies from the National Electrification Administration (NEA) for electric cooperatives (ECs), amounts budgeted under the Missionary Electrification Development Plan (MEDP) promoted by the Small Power Utility Group (SPUG) of the National Power Corporation (NPC) and the adaptable program loan (APL) package currently being negotiated between the Philippine government and the World Bank. Nevertheless, there are several factors of uncertainty in this outlook.
Regarding the funding from IPPs, under the framework of the Adopt-a-Barangay Program
to which KEPCO and Mirant1 are already committed, the former is to electrify 34 barangays in 2004, and the latter, 50 barangays in 2004 and 2005.
As for the second source (NEA subsidies), ECs have thus far applied such funds in
electrifying three or four barangays a year. However, the NEA tends to be slow to execute its budget; the 2003 budget was executed in October of that year.
There are some apprehensions about future subsidies from the NEA. The NEA dismissed
all 700 of its staff in late 2003 and is going to rehire 400 in 2004 as it instates a shakeup. Even under this shakeup, the NEA will reportedly continue to provide subsidies from the General Appropriation, but it is not clear at present whether there will be a change in its policy. 1 KEPCO decided to design the project and procure funds itself for electrification of 34 barangays, and launched the project in January 2004. It
intends to complete the project, inclusive of field studies, determination of electrification method, and construction of facilities, by the end of 2004. The Mirant project had already electrified 17 of the 50 barangays as of January 31, 2004, but the construction cost per barangay was far in excess of the 1 million pesos originally anticipated. The project has consequently gone far over budget, and the handling of the remaining 33 barangays was left to the Department of Energy (DOE). In subsequent negotiations with the DOE, Mirant sought a list of barangays that would be candidates for electrification, and received one from ECs. The remaining 33 barangays are to be electrified over the two-year period of 2004-2005.
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Thirdly, the NPC-SPUG has announced its intention to electrify 20 barangays in 20042. Nevertheless, these 20 barangays have not yet been included in the electrification plans for which budget is to be executed in the first half of 20043. Therefore, budget will be executed for these plans no earlier than the second half of 2004.
Lastly, a final determination has not yet been made on the APL package from the World Bank
for the prospective electrification of 40 barangays (the loans are expected to be received by June 2004).
Even if all of the aforementioned projects were executed, there would still be no outlook for
funding for electrification of 20 to 30 barangays (the possibility that the budget may not be available for even the other projects cannot be denied). In other words, even in Palawan there remains the problem of a shortage of funds that must be procured over the next three years4. The financial difficulties should become even worse in the next phase that begins in 2007, which is aimed at increasing the electrification rate on the household basis.
Table 8.1.1 Current Status of the Barangay Electrification Projects
Funding sources Number of barangays
Target year Comments
Mirant 17 33
2003 2004-05
− Virtually completed as of January 2004 − Presentation of a list of candidate barangays by
ECs KEPCO 34 2004 − Execution of all tasks from preparation of
drawings to funding procurement by KEPCO − Electrification methods including mini-grids
and stand-alone power systems 2002 NEA subsidies 5 2003 − Construction completed at 3 barangays and
underway for 1 barangay − Shelving of budget execution for 1 barangay
2003 NEA subsidies 4 2004 − 2003 budget execution delayed until October 2004 NEA subsidies 3 2004 − Under negotiation World Bank APL 40 2004-06 − Under negotiation between the government and
the World Bank UNDP/PGP/DOE 2 2004 − Under negotiation NPC-SPUG/MEDP 20 2004 − Not included in the budget execution in the first
half of 2004 (no earlier than the second half) Notice: APL: Adaptable Program Loan; BEP: Barangay Electrification Program Source: Prepared by the JICA Study Team based on interview findings
2 This is to be done by constructing a photovoltaic battery charge station. 3 These plans envision the electrification of 116 barangays nationwide. The SPUG has also announced plans for the electrification of 426
barangays over the three-year period ending with 2006. 4 See Section 2.5.2
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8.1.2 Limits of the Current Electrification Scheme
It would, in reality, be extremely difficult to achieve barangay electrification solely through the ECs and the SPUG as the two major principals of rural electrification (RE). The biggest reason is the aforementioned financial constraints.
Obviously, the ECs are expected to play the largest role in RE promotion. With the structural
reform in the power sector, however, the NEA has become unable to provide ECs with funding other than the subsidies from the General Appropriation. As such, for future investment, ECs will have to obtain funds through the market based on earnings from their power distribution business. This is to say that they must procure funds on their own responsibility as power distributors. As viewed from this standpoint, it will become increasingly difficult to extend distribution lines into areas that do not afford good earning prospects.
There are clearly also limits to the financial capabilities of the NPC-SPUG, which is
responsible for missionary electrification. The passage of the Electric Power Industry Reform Act (EPIRA) led to recognition of the imposition of a universal charge as a funding source for missionary electrification. At present, however, there is a big gap between the amount applied for by the NPC-SPUG and that authorized by the ERC5. Moreover, most of the income (subsidies) obtained through the universal charge "disappears," in that it is used to compensate for the deficits at existing facilities. Funding available for investment in new projects is extremely limited6.
In other words, both the ECs and the NPC-SPUG have very restricted resources to fund
further investment. As a means for supplementing the activities of the ECs and the NPC-SPUG, local
government units (LGUs) are installing diesel generators known as "gen-sets" for the supply of power to barangays. This approach is also saddled with many problems. To be sure, gen-sets can be installed with funding from the Provincial Government of Palawan (PGP), but the LGUs lack the ability to maintain and manage the gen-sets themselves. In some cases, gen-sets are being left idle due a lack of fuel because of budget shortages7. At present, LGUs clearly lack the capability needed for operation of power supply on the project basis.
In light of the limits associated with the current scheme for electrification, it will not be
possible to attain the RE targets in Palawan without introducing some new mechanism to compensate for these limits.
5 The universal charge approved for imposition in missionary electrification in 2003 was only 3.37 centavos per kilowatt-hour as opposed to
that of 9.52 centavos in the NPC-SPUG application. 6 See Section 2.3.4 7 CERF/International Institute for Energy Conservation - Asia 2002
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Shell Solar is already expanding its sales of solar home systems (SHSs) in Palawan based on financial assistance from the Government of the Netherlands. In the context of the Palawan New and Renewable Energy and Livelihood Support Project (PNRELSP), the PGP is also attempting to build a new mechanism for financial programs, toward the success of the SHS sales business model introduced by Shell with funds from the United Nations Development Programme Global Environment Facility (UNDP-GEF). Similarly, efforts are being made to promote SHS diffusion and launch private-sector distribution projects based on mini-grids in place of ECs and the NPC-SPUG, with APLs from the World Bank.
There is a limit to the funds that can be prepared by the government, and also to the
capabilities of the existing ECs and the NPC-SPUG. The situation demands the construction of a scheme for diversified project promotion that will give full play to private-sector funds and aid from bi- and multi-lateral institutions, and thereby resolve the difficulties now being confronted. Unless this is done, the master plan described in this study cannot be achieved. 8.1.3 New Electrification Projects with Poor Prospects for Retrieval of Costs
The un-electrified districts in Palawan that are the targets for future electrification are farther
away from the installed transmission and distribution grids, and also have a lower demand density. This naturally results in a higher level of construction cost per kilowatt of capacity and operating cost per kilowatt-hour of service. It consequently becomes even harder to retrieve costs.
Grid extension by ECs into un-electrified districts has been lagging because of difficulties
in two major aspects: securing earnings from the additional investment and procuring the requisite funds.
It would be hard for ECs to make new investments for the electrification of barangays not affording
good prospects for retrieval of costs without some scheme enabling the procurement of funds and retrieval of costs (which ultimately would mean a hike in rates or dependence on subsidies). In particular, a rate hike would probably deepen dissatisfaction and opposition among the existing EC members.
Steps must be taken not only to reduce construction costs but also to resolve such problems
with the operations. This cannot be done merely by according priority to expansion of distribution service by ECs; other electrification methods must be incorporated to curtail the investment cost as much as possible. For example, electrification based on off-grid systems and stand-alone power systems for installation in individual households could be adopted. These methods must be actively incorporated into programs for barangay electrification.
In addition, the construction of this new framework for additional electrification projects
will require a new scheme for the procurement of funds. Mere technical feasibility is not enough; without assurance of operating methods and funding sources, it will be impossible to electrify Palawan as envisioned in the master plan.
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8.2 Advisable Setup for Promotion of Barangay Electrification 8.2.1 Importance of Incorporating Stand-Alone Power Systems
Viewed from the standpoint of beneficiaries, grid extension is naturally the most preferable of all the electrification methods in various respects, including supply potential and stability.
In reality, however, methods other than grid extension must be applied due to constraints in
the cost aspect (e.g., low demand density and long distances from existing grids) as well as in the aspects of fund procurement and the environment, such as Environmentally Critical Areas Network (ECAN) zoning.
As described above, there are as yet no prospects for procuring funds for electrification of 20
to 30 barangays by the end of 2006. In the case of these barangays, all options must be considered, including that of beneficiary burdens. In addition, seeing that the provision of additional funding in large amounts cannot be expected within the next three years, the practical approach would lie in devising electrification methods that curtail costs to the lowest possible level.
For these reasons, it is thought that supply through mini-grids and the installation of
stand-alone systems such as battery charge stations (BCSs) and SHSs will have a vital role to play for electrification of a fairly large proportion of the remaining un-electrified barangays. 8.2.2 Need for Diversification of the Project Setup and Issues related to New Project Models
The operation of stand-alone power systems requires the instatement of diverse new project models. There are already several models that could serve as archetypes. Some examples are listed below. (1) Barangay power associations
One such model is the barangay power association (BAPA), which is operated by the barangay residents. However, BAPAs also have many problems. They generally lack the technical foundation needed for operation and maintenance (O&M) as required for running the works. They also tend to be on very weak financial ground. At present, the barangays take over facilities constructed by ECs or LGUs and use them to supply power to the residents. When the facilities break down or otherwise require repair, the BAPAs have no choice but to depend on the ECs or LGUs. The facilities are therefore at risk of being left idle and un-repaired.
In addition, residents may feel discontent over the cost burden. As compared to the EC
retail rate of 5.8 pesos per kilowatt-hour, the cost burden of the beneficiaries in BAPA distribution service, which is on the order of 15 pesos per kilowatt-hour, must be termed extremely high.
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(2) SHS dealers The diffusion of SHSs is another option. There are two major methods of SHS sales: 1)
leasing of SHSs to customers and collection of a monthly fee for use, and 2) outright purchase by customers and provision of post-sales services by dealers for a fee. In its current business in Palawan, Shell applies the latter method. Leasing holds a high risk of non-payment of the leasing fees, and past experience made Shell decide against it.
Shell's business is smoothly expanding, but it is being supported by subsidies from the
Dutch government for initial investment (the cost of purchase)8. In other words, it cannot be denied that the expanded sales of SHSs rest on these subsidies. The Dutch government has appropriated 5 million dollars for the subsidies, which are to be discontinued once 15,000 systems have been sold.
As such, there is a limit to the direct provision of subsidies, and the preparation of a
financial scheme enabling individual beneficiaries to procure funds will eventually assume more importance for the widespread diffusion of SHSs. (3) Distribution service by qualified third parties using mini-grids
Distribution service may also be provided through mini-grids with "qualified third parties" as defined in EPIRA serving as the operators. Based on concession agreements, this approach may be taken in districts where there are no prospects for grid extension by ECs. This model has already been incorporated into the World Bank APL package, and plans are being made for its implementation in 40 barangays in Palawan. It is also one of the options in the KEPCO "Adopt-a-Barangay" program.
Nevertheless, the economic feasibility varies with the number of customers as one of the
preconditions, and therefore must be assessed on a case-by-case basis. In the World Bank APL package, there are plans to prepare 66 million dollars in funding. The way has also been paved for subsidies from a universal charge.
In the mechanism for this project, the incentives for investors (operators) would greatly
differ depending on the level at which rates can be set for final customers and the amount of subsidies available. Thus far, the DOE has taken a definite stance of providing subsidies only for initial investment and not for operating costs, in order to see that operators maintain disciplined operation.
As in the case of BAPAs, rates could possibly be higher than those offered by ECs. It
consequently could be difficult to find a point of compromise between the assurance of operator profits and curtailment of discontent among customers.
8 The standard 50-Wp model costs about 33,000 pesos without subsidies, but sells for 18,360 pesos with the subsidies.
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(4) Power supply using privately owned power systems (POPSs) In areas where the demand is too small to support a power supply as a self-sufficient
business, use of systems owned by individuals for supplying power to neighboring homes must be considered as one of the options. The premise here is the use of small generators for supplying power to neighboring households by running distribution lines to them or by connecting BCSs to them.
The facilities are completely privately owned and are by no means installed for business
purposes. As such, the supply may not be accompanied by a definite contract relationship with the beneficiaries receiving the power, or by the setting of authorized rates. These points constitute some cause for apprehension about how to assure social credibility and sustainability as a power supply scheme. 8.2.3 Preparation of a New Electrification Setup in Palawan and Role of PGP
For the success of the master plan, various service models must be put into practical application. It will be impossible to raise the funds needed for electrification without mobilizing those in the private sector and individuals, instead of depending solely on public-sector funds. To this end, much must be expected of the PGP as regards encouraging a lot of entrants to participate in the market and preparing conditions conducive to the operation of their businesses. For this reason, the PGP must more clearly define its role and the tasks to be tackled from now on. (1) Clarification of the PGP role
The PGP ought to act as a policy-maker; it would not be advisable for it to get directly involved in the operation of businesses.
One of the main reasons for this is that the capabilities of official agencies are quite different
from those needed by operators. This is evidenced by cases in which generation facilities owned by LGUs lie idle because of the lack of adequate O&M capabilities and budgetary backing. Furthermore, an assumption of responsibility extending to O&M by the PGP in order to avoid such situations could swell the PGP organization into areas that are not within its proper jurisdiction. There is also the strong possibility that this would expand the administrative cost burden.
In contrast, the role that is most desired of the PGP, as policy-maker, is to petition the
national government and assembly for action on various matters, such as policy support for the service plans of the NPC-SPUG and ECs. Depending on the case, it may also have to make overtures that are political in nature. Funds from the national government (including NEA subsidies, DOE budget and funds for aid from overseas donors) are extremely important to the electrification of Palawan. The PGP must take the initiative in making the systemic (institutional) arrangements required for promoting electrification.
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(2) Review of the Master Plan and drafting of an electrification program The Master Plan is a blueprint for electrification in the province up to 2015 as part of the
expanded rural electrification (ER) program on the national governmental level. However, this blueprint ought to be revised as actual progress is made in electrification, and these points to a need for reviews at regular intervals.
For the execution of electrification, the PGP should draft a medium-term program for
specific actions based on the Master Plan, and furnish support for the individual projects making up this program.
The PGP must define targets for each year up to and including 2015, and formulate
individual projects needed for attaining these targets. It also must stay constantly apprised of the progress of each project already under way, and propose countermeasures or alternative projects in the event of delays or major changes. In addition, it must approach concerned parties (e.g., ECs, the SPUG, private enterprises, beneficiaries, the national government and overseas aid institutions) on behalf of the project. All of these activities are vital parts of the PGP role.
The instatement of a scheme for implementing new business models is a field where the
PGP must furnish formidable support. This is especially true in the case of operations led by residents, such as BAPAs and POPSs. While these are expected to be of crucial importance for expanded electrification, resident-centered organizations tend to have extremely frail foundations in both financial and technical terms. To obtain the requisite funding and the technical capabilities needed for O&M, it is indispensable for them to have the support of local banks and ECs in Palawan. The PGP must make the requisite arrangements for such support. (3) Necessity of establishment of a dedicated energy section in the PGP
As described above, to secure the implementation of the master plan proposed in this study, the PGP must establish a diversified institutional and organizational framework for electrification, show its leadership as policymaker, and plan electrification programs and projects. In this sense, the role of the PGP is very important and critical.
In the PGP organization, however, there is no dedicated section that oversees energy issues including power development. In the current situation, only six personnel from the Planning and Development Office were assigned to be engaged in the Master Plan Study.
It is strongly recommended that this tentative organization be strengthened as an independent and dedicated section (e.g., a provisional energy department) and also that its capacity be reinforced. This provisional energy department must carry out the following tasks:
• Periodical review and revision of the master plan; • Planning of individual power development and electrification programs and projects; • Preparation and analysis of necessary data for planning electrification programs and
projects, and establishment of a system for such data that relevant organizations and persons can freely access;
8-9
• Coordination of and policy support for individual power projects, which are carried out by various stakeholders such as EC, NPC-SPUG, private investors, and beneficiaries;
• Promotion of development and use of new-and-renewable energies for power development;
• Provision of policy necessary for implementing the master plan, and negotiation with and petition to the national government and assembly for necessary policy and funding support; and
• Establishment and management of a scheme for fundraising required for power development (A concrete rural electrification funding scheme is shown in the section 8.3)
In addition, to see that these organizational capabilities function effectively and to improve
staff skills, it is necessary to continue programs of capacity building, not only for the organization but also for each staff member.
8.3 Establishment of an RE Fund and Construction of a Scheme for Mobilizing Funds
Organizations with a budgetary foundation, such as ECs and the SPUG, may face problems
but are generally able to procure funds. In contrast, funding is hard to obtain for the diffusion of residential SHSs and mini-grid service, which have a vital role to play in electrification over the coming years. Provisions must be made to mobilize funds for them.
As an additional means of fund procurement, the Master Plan proposes the establishment of a
rural electrification fund pool (REFP) managed by the PGP, as well as the promotion of RE with funds from this pool. 8.3.1 Funding Sources
The REFP would be a pool that manages several funds in the interest of administering
funding available from various institutions. Its objective is to use these funds for additional investments on the project basis and for the provision of O&M budgets for existing facilities. Its major sources of base funds are as follows.
(1) Energy Regulation 1-94
Energy Regulation 1-94 (ER 1-94) is a funding source that is manageable by the PGP (see Section 2.3.2). To fund RE, the PGP could use the entire 0.5 centavos per kilowatt-hour from the Electrification Fund and a part of the 0.25 centavos per kilowatt-hour from the Livelihood Fund.
The Livelihood Fund was set up for applying funds to projects aimed at bettering the life of
residents. Nevertheless, its funds may also be used for the cost of wiring houses to promote electrification and for operating costs required for power supply.
8-10
With the effectuation of the EPIRA implementing rules and regulations (IRR), ER 1-94 came to be applied even to small generators, which had previously been exempted from its application. As a result, even Delta-P and diesel power plants operated by the NPC-SPUG in Palawan will be obliged to pay the ER 1-94 levy, and this will constitute a financial resource. (2) Share of benefits from utilization and development of natural wealth
This is stipulated in Item B, Rule 29 of the IRR. It compels any agencies, corporations or other entities engaged in the utilization and development of national wealth (i.e., natural resources) to pay to the concerned LGU whichever is higher: 1% of their sales, or 40% of the national wealth taxes, royalties, fees or charges paid to the national government.
In Palawan, the Malampaya Natural Gas Project falls under this stipulation, which
consequently can be applied to royalties from it. At present, however, there is a dispute between the PGP and the national government about whether or not the geographical location of the Malampaya gas field is actually in the province. A conclusion has not yet been reached on this question.
If the rights are recognized as belonging to the province, about 2 billion dollars in funding
could be obtained by the end of 2021. (3) Provision of funds from developed-country corporations
There are good chances for utilization of renewable energy such as mini hydropower, photovoltaic systems and biomass in Palawan electrification projects. By applying the Clean Development Mechanism (CDM) to these projects, it would be possible to build a scheme for receipt of funding from companies from developed countries.
The basic idea would be to have a CDM fund established mainly by the PGP and seek
contributions (i.e., a sort of equity) from companies that want to get quotas for greenhouse gas (GHG) emissions in other countries. The CDM fund could be used to fund investment for CDM projects. The GHG emission quotas would, in turn, be allocated among the investing companies, in proportion with their contribution.
The Philippines ratified the Kyoto Protocol in October of 2003, and therefore has footing
for the introduction of CDM schemes. A decision has already been made to set up a designated national authority (DNA) for it within the Department of Environment and Natural Resources (DENR). The national government and aid institutions are moving ahead with preparations for the launch of CDM projects applying renewable energy9. In this sense, the foundation for utilizing the CDM is now taking shape.
9 The UNDP has determined technical assistance for establishment of the DNA.
8-11
(4) Local taxes A local tax could be imposed on distribution companies in the province. The prospective
targets would be ECs. ECs receive continuous funding for the purchase of wholesale power from the SPUG,
investment in distribution lines and facility O&M. This funding enables them to hold down their rates. In contrast, rates must be set on extremely high levels by electrification entities that lack schemes for such ongoing assistance (e.g., BAPAs). The local tax would be aimed at rectifying this inconsistency, if only by a slight degree.
In the following respects, however, the imposition of such a local tax would have to be
preceded by in-depth studies among the concerned parties. It cannot be denied that BAPAs, too, receive assistance for initial investment, in that they
are furnished with facilities from LGUs and ECs virtually free of charge. Putting initial investment aside, the continuation of the service requires the retrieval of depreciation and repair costs, but arrangements have not yet been made for such funding, and this is creating problems for the business continuity. In fact, such problems are already surfacing. If all of these costs were transferred to customers under the beneficiary burden principle, the BAPA rate levels, which are already high at about 15 pesos per kilowatt-hour, could jump to 30-40 pesos with the addition of depreciation costs. Owing to such circumstances, it would in effect not be practical to transfer all costs to beneficiaries, and some kind of solution is therefore needed.
Another issue has to do with the reforms and the related actions aimed at correcting the
structure of cross-subsidization that has been practiced for electric utilities thus far in the Philippines. Naturally, some may question the appropriateness of reallocating subsidies through such a scheme. 8.3.2 Application of Funds
Expenditures from the REFP resting on the aforementioned sources would be made through the following prospective framework. (1) Promotion of SHS diffusion through the SHS fund
Sales of SHS are already being assisted by grant aid from the Dutch government. This aid is supporting their diffusion, which is smoothly proceeding.
Under these circumstances, measures are being taken for the provision of loans to
individuals from financial institutions and for the avoidance of the related risk of non-performing debt with aid from the UNDP-GEF in the context of the PNRELSP. There is also a movement for the use of APL from the World Bank to provide a financial source for the
8-12
flow of funds from commercial banks to local banks. These steps are aimed at paving the way for financing for individuals who have a low credit rating and would find it hard to borrow from ordinary commercial banks, by putting local banks and micro-credit in the middle.
In light of the risk of failure to repay loans, the establishment of a loss reserve fund to hedge
the risk of default has been proposed in the PNRELSP. At any rate, SHSs have a critical role to play in the electrification of Palawan and some
institutional arrangements must be made to expand the extension of loans to individuals and to hedge risks in order to secure these loans.
To support SHS sales, the PGP must institute such a SHS fund in a manner consistent with
the existing institutional mechanisms and use it to furnish assistance to dealers and funding to residents (e.g., public loans and partial subsidization of down payments). (2) O&M fund as a reserve for retrieval of depreciation costs and O&M expenses for
reinvestment in facilities Provisions have already been made for the loan of power generation facilities to BAPAs by
LGUs or ECs. These provisions are expected to expand over the coming years. Thus far, LGUs and ECs have lent facilities to resident organizations either for no fee or for
only a nominal fee, and the facility costs have not been recovered through rates. The problem with this setup lies in the limited service life of the facilities; unless depreciation costs are retrieved, funding has to be procured all over again for facility reinvestment. This reveals a need for preparation of a financial scheme enabling recovery of the cost of facilities lent to BAPAs.
If the facilities are owned by the ECs, they are counted as assets on the EC balance sheet and
are amortized in the context of EC financial affairs. As a result, even if depreciation costs cannot be retrieved from BAPAs, the EC can recover them from its rates (tariff revenue).
If the facilities are owned by LGUs, on the other hand, different problems would be
involved. Because governments do not have balance sheets, they also lack the concept of depreciation. In addition, at present, the Palawan LGUs take only 1 peso in facility leasing fees from BAPAs, and this is obviously far from the genuine retrieval of depreciation costs. Furthermore, arrangements have not been made for the recovery of O&M costs from rates. As such, there is no mechanism for balancing expenditures (costs) and income (cost recovery). It will consequently become impossible to keep electrification projects in operation if the government does not make budget appropriations for them every year.
In addition, there is some cause for apprehension about the emergence of future problems if
LGUs come to own even more facilities and continue to lend them to BAPAs under the current
8-13
conditions. This would lead to a steady swelling of the funds needed for reinvestment and the routine O&M costs. As a result, the financial burden on the PGP would become heavier by the year.
The objective of the O&M fund would be to resolve these problems and assume the burden
of costs that cannot be transferred to rates. (3) Investment fund for general projects
This fund would be instituted to provide funds for additional investment in electrification or for the expansion of installed facilities. Its range of application should be as wide as possible in order to furnish the funds needed for construction of facilities owned by LGUs and lent to BAPAs, and to serve as part of the funds for investment by private enterprises.
Its prospective main sources would be the ER 1-94 Electrification Fund and the share of
benefits from the utilization and development of the national wealth in accordance with IRR Item 29. (4) Investment fund for CDM projects
As described in the section on funding sources, this fund would be confined to CDM projects. It would collect contributions from overseas companies and apply funds to specific projects.
It should be noted that, because of the small scale of electrification projects in Palawan,
application of the CDM to each project individually would be unrealistic, owing to the cost of obtaining authorization for each project separately. For this reason, the PGP must lead efforts to design a project that could serve as a model, obtain CDM authorization for it and then implement many others in the same manner.
Projects for which application of this fund is desired could be automatically made into
CDM projects by following (in other words, copying) this model designed for such application. With such preparations, the work of obtaining CDM authorization would be completed with
the design of the initial model project. In this way, the concerned parties could avoid the redundant work of repeatedly obtaining authorization at the stage of project implementation.
CDM application requires considerable time and expense for the establishment of the
baseline, assessment of the GHG-reducing effect and procedures for obtaining authorization as a CDM project. This work therefore should be undertaken quickly, beginning right from the stage of instituting the fund.
8-14
EC
Universalcharge
POPS
BAPA
Rural Electrification Fund Pool(REFP)
Developed-countryinvestors
Overseas aidinstitutions
Private-sectorfinancial
institutions(banks, micro finance, etc.)
NGO
PGP
LGUs
Resourcedevelopment
WB-APL financing
IRR Rule 29, B
Provision of facilities,O&M support
Final customers
Rate (revenue) Power supply
Technical assistanceSHS sales
Electrification projects
NPC-SPUG
NEA GeneralAppropriation
Subsidies
DOE BEPbudget
Private-sectormini grid
Distributioncompanies
SHS dealers
RESCO projects
SubsidiesManagement
Initial investment expenses,O&M costs, assistance, etc.
ER 1-94
Financing
Contributions
EC
Universalcharge
POPS
BAPA
POPS
BAPA
Rural Electrification Fund Pool(REFP)
Developed-countryinvestors
Overseas aidinstitutions
Private-sectorfinancial
institutions(banks, micro finance, etc.)
NGO
PGP
LGUs
Resourcedevelopment
WB-APL financing
IRR Rule 29, B
Provision of facilities,O&M support
Final customers
Rate (revenue) Power supply
Final customersFinal customers
Rate (revenue) Power supply
Technical assistanceSHS sales
Electrification projects
NPC-SPUG
NEA GeneralAppropriation
Subsidies
DOE BEPbudget
Private-sectormini grid
Distributioncompanies
SHS dealers
RESCO projects
Private-sectormini grid
Distributioncompanies
SHS dealers
RESCO projects
SubsidiesManagement
Initial investment expenses,O&M costs, assistance, etc.
ER 1-94
Financing
Contributions
Source: Prepared by the JICA Study Team
Figure 8.2.1 Setup for Promotion of Electrification in Palawan
Rural Electrification Fund Pool (REFP)
SHS fund (includinga loss reserve fund) O&M fund General project
Investment fundCDM project
Investment fund
PGP
ER 1-94Electrification Fund-0.5 centavos/kWh
Livelihood Fund-0.25 centavos/kWh
Delta-P NCP-SPUGpower plants
New power sales tax
ECs
Developed-countryinvestors
Share of benefit from utilization and
development of national wealth(IRR Rule29, B)
Resourcedevelopmentcompanies
SHS dealers
Private-sectorfinancial
Institutions
Initial investment expenses, O&M cost, assistance, etc.
Beneficiaries
POPS
BAPA LGU ECs
Private-sector mini griddistribution companies Individuals
NPC-SPUG
NGO
Overseas aidinstitutions
ManagementRural Electrification Fund Pool (REFP)
SHS fund (includinga loss reserve fund) O&M fund General project
Investment fundCDM project
Investment fund
PGP
ER 1-94Electrification Fund-0.5 centavos/kWh
Livelihood Fund-0.25 centavos/kWh
ER 1-94Electrification Fund-0.5 centavos/kWh
Livelihood Fund-0.25 centavos/kWh
Delta-P NCP-SPUGpower plants
New power sales tax
ECs
Developed-countryinvestors
Share of benefit from utilization and
development of national wealth(IRR Rule29, B)
Resourcedevelopmentcompanies
SHS dealers
Private-sectorfinancial
Institutions
Initial investment expenses, O&M cost, assistance, etc.
Beneficiaries
POPS
BAPA LGU ECs
Private-sector mini griddistribution companies Individuals
NPC-SPUG
NGO
Beneficiaries
POPSPOPS
BAPABAPA LGULGU ECsECs
Private-sector mini griddistribution companiesPrivate-sector mini griddistribution companies IndividualsIndividuals
NPC-SPUGNPC-SPUG
NGONGO
Overseas aidinstitutions
Management
Source: Prepared by the JICA Study Team
Figure 8.2.2 REFP Scheme
8-15
8.4 Application to Other Provinces
The province of Palawan, which is the target of this Master Plan, is less economically developed than urbanized districts such as the Manila area, partly due to its geographical situation as an outlying island. As a result, the rate of electrification is also relatively low.
To the Philippines, rural economic development is a key priority that absolutely must be
achieved if the country is to eradicate poverty. In addition, the promotion of RE provides leverage for rural economic development. This is behind the RE campaign that began with the O-Ilaw Project and evolved into the current ER program.
Attainment of the goal of electrifying all barangays by the end of 2006 is almost within
reach. Both the national and local governments are continuing with efforts to attain the next goal, namely electrification of 90% of all households by the end of 2017.
As indicated in this report, the biggest problem facing RE promotion in the Philippines is
the shortage of funds. Goals cannot be achieved on the strength of public-sector funds alone. Resolving this problem will require the injection of private-sector funds and the
establishment of business models that will make this possible. As was found in the Master Plan Study for Palawan, mini-grids and stand-alone systems have a vital role to play as means of electrification. Grid extension by ECs is the approach desired by many, but it could not feasibly be applied to all projects, considering the related cost and funds that must be procured.
What is needed for RE promotion is a variety of service models for power supply by
off-grid approaches. The beneficiaries, too, must be encouraged to mount their own efforts as far as possible to have their barangays electrified and thereby build a better economy and life for themselves. In this sense, the measures to spur installation of SHSs, which will probably carry a lot of weight in the Palawan electrification program, as well as the expansion of individual loans to support it must be regarded as social experiments of crucial importance. This also applies to the projects for power supply by residents themselves based on the BAPA model and those for mini-grid distribution by qualified third parties that are the subject of World Bank APLs.
Each of these attempts is still wrought with numerous difficulties. As compared to power
supply from the distribution network, SHSs have only a limited capacity. In addition, the rates in service through mini-grids operated by BAPAs are much higher than those offered by ECs, and the service operated by private companies based on APLs might magnify the burden on beneficiaries.
Nevertheless, it will be impossible to promote RE in the Philippines unless all parties
incorporate new schemes and take up the challenge of new targets in spite of these problems. Problems cannot be resolved merely by looking for subsidies from the government for the
8-16
entire cost burden. In the midst of the far-reaching reform in the power sector, the government, too, has only limited funds and is no longer able to shoulder all costs as part of the fiscal burden.
Finally, it should be noted that the preparation of this Master Plan did not include in-depth
studies on possible increases in income levels through electrification. Even so, electrification is heavily bound up with the payment capabilities of residents. Solutions will never be found merely by repeating the line that low-income levels would prevent residents from paying bills and, conversely, projects could not be executed because costs therefore could not be retrieved.
For this reason, the preparation of RE plans and program must incorporate projects for
raising the income level of residents through electrification.
S-1
Environmental Checklist S.1.1 Existing IEE Checklist (1) Review of the Philippine environmental impact statement system
Presidential Decree (PD) No.1151, which was proclaimed on June 6, 1977 and commonly known as the Philippine Environmental Policy, is the first policy issuance on the Environmental Impact Statement (EIS) system in the Philippine. In Section 4 of PD 1151, it is declared that all agencies shall prepare an environmental impact statement for every action, project and undertaking that significantly affects the quality of the environment. Then the Philippine EIS system was formally established on June 11, 1978 by virtue of PD No.1586.
PD No.1586 declared that environmentally critical projects (ECPs) and projects within
environmentally critical areas (ECAs) require the submission of an EIS, and the proponents are not allowed to undertake or operate any part of such ECPs or projects within ECAs without first securing an Environmental Compliance Certificate (ECC).
After that the EIS system has undergone several improvements by continuously introducing
new features and requirements, and now the EIS system is operated based on the DENR Administrative Order No.37, 1996 Series (DAO 96-37). According to DAO 96-37, in order to secure an ECC, proponents of ECPs are required to submit an EIS report with the Environmental Management Bureau (EMB). On the other hand, proponents of projects within ECAs are generally required to submit an Initial Environmental Examination (IEE) report to the concerned Regional Office of DENR-EMB. It is clarified that an IEE is a form of an EIS. The basic differences between these two documents are the depth and extent of the data requirement. An EIS report may be prepared instead of an IEE report for proposed projects within ECAs at the discretion of the proponent in certain cases or upon an order from the Regional Executive Director.
The projects or undertakings covered by the EIS system are defined as “any activity,
regardless of scale or magnitude, which may have significant impact on the environment” in DAO 96-37. All of the projects and undertakings are not covered by the EIS system. In the case that the project is not covered by the EIS system, a Certificate of Non-Coverage (CNC) may be issued by the EMB or the DENR regional office upon request from a proponent.
For the selected projects with relatively small scales and magnitudes, an IEE checklist report has been developed by the DENR-EMB in line with the target of streamlining the EIS system. The IEE Checklist report is a simplified form, instead of the standard EIS document, designed to assist the proponents. The list of projects covered by the IEE Checklist is defined by the DENR-EMB Memorandum Circular No.01, 2000 Series. The Memorandum Circular also defines format, contents and implementing procedures for the IEE Checklist.
S-2
In this study, based on the review of the existing IEE Checklist Report, environmental checklists for the study of the power development master plan in Palawan Province were created.
(2) EIS process for the power facilities
Power facilities and related facilities that defined as the ECPs by DAO 96-37 are following: Major dams with storage volumes equal to or exceeding 20 million cubic meters Geothermal plants, waste-to-energy facilities, thermal power plants with capacities
equal to or exceeding 10MW Hydropower plants or any non-conventional power projects with capacities equal to or
exceeding 6MW Power barges with total capacity in excess of 32MW
In addition, a Memorandum of Agreement (MOA) on the streamlining of EIS processes for
power facilities and related facilities was reached between the DENR and DOE in 1999. This MOA, defined the kinds and scales of the projects for all facilities that were not covered by the EIS system. Also the projects covered by the EIS system are classified into following three categories; IEE checklist required, IEE report required, and EIS report required.
Regarding to the energy facilities mentioned in this MOA, Table S.1.1 shows the results for
selecting and classifying the power facilities and related facilities. According to this MOA, only the power plants with capacities equal to or less than 1MW, substations and switchyard (up to 220kV) are classified as not being covered by the EIS system. Renewable energy, hydropower, and power barges with capacities equal to or less than 10MW are classified as the projects that required an IEE checklist.
As for Palawan Province, the classifications of Table S.1.1 are not applicable directly,
because the entire province is classified as ECAs and the ECAN zoning was adopted. Although the transmission lines are classified as projects that require an IEE checklist in Table S.1.1, an EIS report is submitted to the DENR-EMB in the case of the Palawan backbone transmission line project.
S-
3
Tabl
e S.
1.1
Doc
umen
ts R
equi
red
by th
e EI
S Sy
stem
for P
ower
Fac
ilitie
s as t
o th
e K
ind
and
Scal
e in
MO
A b
etw
een
DEN
R a
nd D
OE
To b
e co
vere
d by
the
EIS
Syst
em
Proj
ect
Not
cov
ered
by
the
EIS
Syst
em*
Req
uirin
g an
IEE
Che
cklis
t R
equi
ring
an IE
E D
ocum
ent
Req
uirin
g an
EIS
Doc
umen
t G
ener
al
A
ny
ener
gy
proj
ect
that
re
quire
s si
gnifi
cant
m
echa
nica
l ear
th m
ovin
g &
ec
olog
ical
/veg
etat
ive
dist
urba
nce
activ
ities
R
enew
able
Ene
rgy
(sol
ar, w
ind,
was
te to
en
ergy
, bi
ogas
, an
d tid
al
pow
er,
geot
herm
al)
C
apac
ity
from
gr
eate
r th
an 1
to 1
0MW
C
apac
ity
grea
ter
than
10
MW
Hyd
ropo
wer
Pla
nts
C
apac
ity
from
gr
eate
r th
an 1
to 1
0MW
Or
with
le
ss
than
20
m
illio
n cu
. m
. w
ater
im
poun
dmen
t
Cap
acity
gr
eate
r th
an
10M
W
O
r w
ater
im
poun
dmen
t gr
eate
r th
an 2
0 m
illio
n cu
. m
. Th
erm
al p
ower
Pla
nts
Bun
ker,
dies
el-f
ired
and
natu
ral
gas-
fired
w
ith
capa
city
less
than
or e
qual
to
10M
W
C
apac
ity
grea
ter
than
10
MW
Pow
er B
arge
s
R
esea
rch
(sei
smic
surv
ey,
grav
ity
surv
ey,
geos
cien
tific
, ge
ophy
sica
l sur
veys
, fea
sibi
lity
stud
y, o
ther
s) a
nd d
evel
opm
ent
activ
ities
th
at
don’
t in
volv
e si
gnifi
cant
ear
th m
ovin
g an
d ec
olog
ical
/ ve
geta
tive
dist
urba
nce
activ
ities
us
ing
mec
hani
cal
equi
pmen
t th
at
affe
ct th
e en
viro
nmen
t
All
dem
onst
ratio
ns a
nd p
ilot
ener
gy p
roje
cts,
pow
er p
lant
s w
ith c
apac
ity th
at is
less
than
or
equa
l to
1MW
as
long
as
soci
al
acce
ptab
ility
gu
idel
ines
ha
ve
been
co
mpl
ied
purs
uant
to
D
ENR
an
d th
e Lo
cal
Gov
ernm
ent
Cod
e re
quire
men
ts
Cap
acity
fr
om
grea
ter
than
1 to
10M
W
C
apac
ity e
qual
to 1
0 up
to
32M
W
C
apac
ity
grea
ter
than
32
MW
Po
wer
Tr
ansm
issi
on
Syst
ems
and
Subs
tatio
ns
Su
bsta
tions
/sw
itch
yard
onl
y (u
p to
220k
V)
Po
wer
tra
nsm
issi
on
syst
em a
nd su
bsta
tions
Subm
arin
e ca
bles
* Pr
ojec
ts th
at a
re n
ot c
over
ed b
y th
e EI
S sy
stem
may
be
issu
ed C
ertif
icat
e of
Non
-Cov
erag
e (
CN
C)
by
the
EMB
or D
ENR
regi
onal
offi
ce u
pon
requ
est f
rom
the
prop
onen
t. T
here
is n
o ne
ed
for t
he p
ropo
nent
to p
repa
re th
e IE
E or
EIS
and
to se
cure
the
ECC
. So
urce
: Stu
dy te
am (b
ased
on
DEN
R-D
OE
Mem
oran
dum
of A
gree
men
t (M
OA
) on
Stre
amlin
ing
of E
IS P
roce
sses
for E
nerg
y Pr
ojec
ts)
S-3
S-4
(3) Existing IEE checklists for the power facilities Based on the DENR-EMB Memorandum Circular No.01 Series of 2000, IEE checklists
are prepared for the following power facilities; mini hydropower plant with capacity from greater than 1 to 10MW or with less than 20 million cubic meters water impoundment, power barges with capacity from greater than 1 to 10MW, and power transmission systems and substations greater than 220kV. It is possible to obtain these IEE checklists from the DENR-EMB website. And there is another example of the IEE checklist for land-based power plant (for thermal, hydropower, and renewable energy) made by DENR-EMB.
Basically the contents of the IEE checklists are as follows;
General information regarding the proponent; project location, project area description, plan/design components and activities during the development and operation phases
Information regarding the description of the existing environmental condition where the road or bridge will be located - the physical biological, socio-cultural and economic environment
Listing of possible potential impacts that may occur in the various stages of the project establishment and operation; corresponding mitigation and enhancement measures to prevent the occurrence of adverse impacts and strengthen the positive effects of the project;
Required attachments As for the environmental checklist for this Master Plan, the description of the existing
environmental condition and the impact assessment and the mitigation measures will be discussed among the above-mentioned contents of the existing IEE checklists. (a) The description of the existing environmental condition
The items included in the description of the existing environmental condition, which are described in the existing IEE checklists, are listed in Table S.1.2. They are roughly classified into the following three categories;
Natural and physical environment such as topography, geology, water, air, disaster
(erosion, flood, typhoon, earthquake, others) Biological environment such as significant wildlife, forest, vegetation, others Socio-cultural and economic environment such as settlements, infrastructures,
economic conditions, others
As for the natural and physical environments, the existing IEE checklists cover the items that are considered to have major impacts or to be strongly related to the target power facilities, such as the river characteristics and water quality for mini hydropower plants, air pollution for power barges, and typhoons, tornadoes and lightning for transmission lines. As for biological environments, almost the same items are prepared for each power facility. As
S-5
for socio-cultural and economic environments, although detailed items are not entered in the case of land-based power plant, detailed items such as health conditions, education level, employment and income are included in the case of mini hydro, power barges and transmission lines.
To describe the existing environmental conditions, the proponent will answer “Yes” or
“No” for the simple questions related to each component/parameter, select the most probable answer from among the proposed items, or describe the situation briefly. For example, Table S.1.3 shows the questions for each component/parameter and the description of remarks for the items.
S-
6
Tabl
e S.
1.2
Com
pone
nts /
Par
amet
ers f
or D
escr
iptio
n of
Exi
stin
g En
viro
nmen
t on
the
Cur
rent
IEE
Che
cklis
t La
nd-B
ased
Pow
er P
lant
M
ini H
ydro
pow
er P
lant
Po
wer
Bar
ge
Tran
smis
sion
Lin
e, S
ubst
atio
n 1.
Slo
pe an
d to
pogr
aphy
2.
Are
as w
here
soil
eros
ion
is po
ssib
le3.
In
dica
tors
of e
rosio
n, li
quef
actio
n,
land
slide
, gro
und
subs
iden
ce
4. F
lood
ing
durin
g th
e w
et s
easo
n or
typh
oon
5. B
odie
s of
wat
er w
ithin
1.5
km
such
as c
reek
s or s
tream
s 6.
Pre
sent
usa
ge o
f th
e bo
dy o
f w
ater
;bat
hing
, w
ashi
ng,
fishi
ng,
drin
king
, rec
reat
ion
7. C
ritic
al e
colo
gica
l sys
tem
: m
angr
ove,
fo
rest
land
s, aq
uife
r, sa
nctu
ary,
cor
als
8. R
ecla
imed
are
a 9.
Exi
stin
g st
ruct
ures
10
. Pub
lic o
r Priv
ate
ease
men
ts
11. E
xist
ing
envi
ronm
enta
l pro
blem
s w
ithin
500
m; w
ater
pol
lutio
n, a
ir po
llutio
n,
nois
e,
eros
ion,
flo
odin
g 12
. Exi
stin
g tre
es a
nd v
eget
atio
n 13
. Bird
s an
d w
ildlif
e w
hich
hav
e si
gnifi
cant
val
ue
14. F
ishe
ry re
sour
ces
<Nat
ural
and
Phys
ical E
nviro
nmen
t >
1. R
iver
cha
ract
eris
tics
2. F
lood
cha
ract
eris
tics
(Sta
tistic
al
Floo
d D
isch
arge
) 3.
Soi
l ero
sion
, cau
ses
4. L
ands
lides
5.
Pre
sent
use
s of
bod
ies
of w
ater
(w
ashi
ng,
recr
eatio
n,So
urce
of
dr
inki
ng,
Sani
tatio
n,
irrig
atio
n,
fishi
ng, o
ther
s)
6. P
rese
nt la
nd u
se o
f the
are
a (p
rime
agric
ultu
ral
land
, G
rass
land
, bu
ilt-u
p,
orch
ard,
m
angr
ove,
fis
hpon
d, o
ther
s)
7. P
rese
nt w
ater
qua
lity
(pH
, SS
, co
lifor
m, o
il &
gre
ase,
chl
orid
es,
copp
er,
lead
, iro
n, m
anga
nese
, to
tal
hard
ness
, al
kalin
ity,
pest
icid
es)
<Bio
logi
cal E
nvir
onm
ent>
8.
Flo
ra &
/or f
auna
of e
colo
gica
l or
com
mer
cial
si
gnifi
cant
in
th
e bo
dies
of w
ater
9.
Met
hods
& d
ata
sour
ce to
ass
ess
the
flora
& fa
una
in th
e bo
dies
of
wat
er
<Wat
er R
esou
rces
> 1.
Coa
stal/m
arin
e eco
logy
2.
Bod
ies
of w
ater
(cre
eks,
river
s, es
tuar
ies)
that
mig
ht b
e af
fect
ed
dista
nce,
dept
h, w
idth
, qua
lity
3. W
ater
on
qual
ity i
nfor
mat
ion
befo
re th
e pro
ject
4.
Exi
sting
aqua
tic fl
ora &
faun
a 5.
Exi
sting
pat
tern
s of
pol
luta
nt
sour
ces
6. D
iscus
sion
of fl
oodi
ng ev
ents
<Air
Res
ourc
es>
7. M
eteo
rolo
gica
l dat
a (T
empe
ratu
re, w
ind)
8.
Am
bien
t air
qual
ity
(Par
ticul
ate,
othe
rs)
9. S
tatio
nary
sour
ces o
f em
issio
n 10
. Mob
ile so
urce
s of e
miss
ions
<G
eolo
gic R
esou
rces
> 11
. Pro
file o
f the
area
(soi
l map
) <T
erre
stri
al E
colo
gy>
12. F
ores
t/man
grov
e re
serv
e or
a
prot
ecte
d w
ater
shed
area
< Ph
ysic
al E
nviro
nmen
t >
1. E
leva
tion
rang
e 2.
Slo
pe an
d to
pogr
aphy
3.
Gen
eral
geo
logy
4.
Indi
catio
ns o
f lan
dslid
ing
5. O
ccur
renc
es o
f flo
odin
g 6.
Soi
l typ
e 7.
Indi
catio
n of
eros
ion
occu
rring
8.
Affe
cted
riv
er o
r bo
dies
of
wat
er
9. O
ther
na
tura
l dr
aina
ge
way
s/cre
eks
that
dr
ain
tow
ards
co
mm
uniti
es
dow
nstre
am
10. R
ecor
ds o
f typ
hoon
s 11
. Rec
ords
of t
orna
does
/twist
ers
12. N
eare
st ea
rthqu
ake,
faul
t zo
ne o
r vol
cano
, oth
ers
13. L
ight
ning
strik
es
<Bio
logi
cal E
nviro
nmen
t>
14. E
xisti
ng tr
ees a
nd o
ther
type
s of
ve
geta
tion,
lis
t of
th
e sp
ecie
s 15
. Bird
s an
d ot
her
form
s of
w
ildlif
e, lis
t of t
he sp
ecie
s
S-6
S-
7
15. E
xist
ing
settl
emen
t th
at w
ill b
e af
fect
ed ;
hous
ehol
ds, l
egiti
mat
e la
ndow
ners
, ten
ants
, squ
atte
rs
16. L
ocal
org
aniz
atio
n 17
. Opp
ositi
ons
10. F
lora
&/o
r fau
na o
f eco
logi
cal o
r co
mm
erci
al s
igni
fican
ce o
utsi
de
the
bodi
es o
f wat
er
11. M
etho
ds &
dat
a so
urce
to a
sses
s th
e flo
ra &
fau
na o
utsi
de t
he
bodi
es o
f wat
er
12. L
ying
w
ithin
a
wat
ersh
ed
or
fore
st re
serv
atio
n ar
ea
<Soc
io-C
ultu
ral,
Eco
nom
ic
and
Polit
ical
Env
iron
men
t>
13.
Exis
ting
settl
emen
ts
in
the
wat
ersh
ed ar
ea (l
ocat
ion/
num
ber
of
hous
ehol
ds,
fam
ilies
&
po
pula
tion)
14
. Met
hods
& d
ata
sour
ce to
gai
n in
form
atio
n on
th
e ex
istin
g se
ttlem
ent
15.
Soci
al i
nfra
stru
ctur
es (
loca
tion
& c
apac
ity o
f sc
hool
s, he
alth
ce
nter
s, cl
inic
s, ho
spita
ls
and
othe
rs)
16.
Polit
ical
si
tuat
ion
(pea
ce
&
orde
r)
17.
Maj
or e
mpl
oym
ent
& i
ncom
e so
urce
s 18
. Exi
stin
g lo
cal N
GO
19
. So
cial
ac
cept
abili
ty
of
the
proj
ect
(com
mun
ity,
gove
rnm
ent,
NG
O)
13. L
imes
tone
ca
vern
s or
si
nkho
les i
n th
e be
droc
k 14
. Ber
thin
g or
pie
r stru
ctur
e 15
. Ero
sion
pro
ne, s
tatu
s 16
. Exi
stin
g na
tura
l haz
ards
(e
.g.
stor
m
surg
e,
land
slid
es,
gully
ing,
subs
iden
ce)
17.
Iden
tific
atio
n of
tre
es
&
othe
r veg
etat
ion
18. S
peci
es &
oth
er w
ildlif
e (k
now
n w
ildlif
e, d
omes
ticat
ed
anim
als)
<
Soci
oeco
nom
ic E
nviro
nmen
t >19
. Dem
ogra
phic
Dat
a (T
otal
po
pula
tion,
av
erag
e ho
useh
old
size
, av
erag
e ag
e/se
x di
strib
utio
n,
ethn
ic
com
posi
tion,
C
omm
unity
or
gani
zatio
ns,
empl
oym
ent
data
in
the
area
, Mal
e/fe
mal
e ra
tio,
popu
latio
n py
ram
id,
mar
ital s
tatu
s, sp
ecify
whe
ther
ru
ral
or
urba
n,
dom
inan
t la
ngua
ge/d
iale
ct
spok
en
by
the
popu
lace
, la
bor
forc
e &
em
ploy
men
t) B
enef
it fo
r lo
cal
inha
bita
nts,
cultu
ral
mor
als
&
lifes
tyle
, w
omen
’s li
velih
ood
& ro
les
20. E
duca
tion/
liter
acy
data
lit
erac
y ra
te (o
vera
ll, m
ale/
fe
mal
e),
educ
atio
nal
atta
inm
ent (
mal
e/fe
mal
e)
16. F
isher
y re
sour
ces
in
the
bodi
es o
f w
ater
, lis
t of
the
sp
ecie
s 17
. Wat
ersh
ed o
r for
est
rese
rvat
ion
area
18
. Exi
sting
fore
st re
sour
ces
(tim
ber,
fuel
woo
d, n
on-ti
mbe
r pr
oduc
ts,
food
pl
ants,
m
edic
inal
pl
ants,
w
ild
anim
als,
min
eral
s, ot
hers
) <S
ocio
-Cul
tura
l, Ec
onom
ic
and
Polit
ical
Env
ironm
ent>
19
. Exi
sting
settl
emen
ts (n
umbe
r of
hou
seho
lds
and
fam
ilies
, le
gitim
ate
land
owne
rs,
tena
nts,
care
take
rs, s
quat
ters
) 20
. To
tal
popu
latio
n of
th
e ba
rang
ays
21. A
vera
ge fa
mily
size
22
. Num
ber o
f the
hou
ses (
mad
e of
co
ncre
te,
woo
d,
bric
k,
adob
e)
23. A
nces
tral l
ands
or i
ndig
enou
s pe
ople
com
mun
ities
24
. Lea
ding
cau
ses
of m
orbi
dity
an
d m
orta
lity
25. E
xisti
ng lo
cal o
rgan
izat
ions
26
. Soc
ial i
nfra
struc
ture
s (s
choo
ls, h
ealth
cen
ter/c
linic
s, ro
ads,
com
mun
icat
ion,
pol
ice
statio
n,
com
mun
ity
cent
er,
hosp
ital,
trans
porta
tion,
ch
urch
es/c
hape
ls, o
ther
s)
S-7
S-
8
21. I
ncom
e (in
com
e fro
m th
e se
a, di
strib
utio
n,
sour
ce,
pres
ent
econ
omic
activ
ities
22
. Hea
lth D
ata
(mor
bidi
ty an
d m
orta
lity
rate
s,in
fant
mor
bidi
ty, m
alnu
tritio
n da
ta,
birth
rat
e, nu
mbe
r of
he
alth
fa
cilit
ies,
doct
ors,
nurs
es, h
ealth
serv
ices
, oth
ers
< C
urre
nt W
aste
Man
agem
ent >
23. W
aste
man
agem
ent
tech
niqu
es,
drai
nage
sys
tem
&
toile
ts
Sour
ce:
Land
-bas
ed p
ower
pla
nt D
ENR
EM
B R
QE/
9/18
/200
1/G
uide
for I
EE C
heck
list o
n La
nd-B
ased
Pow
er P
lant
s (fin
al)
Min
i hyd
ro, p
ower
bar
ge, t
rans
mis
sion
line
, sub
stat
ion
D
ENR
EM
B W
eb S
ite (h
ttp://
ww
w.e
mb.
gov.
ph/e
ia/c
heck
list.h
tm)
S-8
S-9
No.1 to 5 in the case of a land-based plant are shown in Table S.1.3. Table S.1.3 Examples for the Description of Existing Environment in the Case of a Land-Based Power Plant
Components/Parameters Yes No Remarks 1. Slope and topography of the area
covered by the project - Terrain is flat (0 - 3%) - Gently sloping our undulating (3 – 8%)- Undulating to rolling (8 - 18%) - Rolling to moderately steep (18 - 30%)- Steeply rolling (30 - 50%) - Very steep to mountainous (>50%)
2. Are there areas in the site where there are possible occurrence of soil erosion?
Cause of erosion: [ ]heavy rains [ ]unstable slope [ ]others, Specify
3. Are there indicators in the area of the following?
4. Has the area experienced any flooding during the wet season?
Period of flooding: Causes of flooding: [ ]low area [ ]poor drainage [ ]water-logged areas
5. Are there existing bodies of water within 1.5km of the proposed building such as creeks or streams?
If Yes, indicate the name and distance to the body of water.
Source: DENR EMB RQE/9/18/2001/Guide for IEE Checklist on Land-Based Power Plants (final) (b) Impact assessment and mitigation measures
The outline of the description about predicted impacts, evaluation and mitigation measures in the existing IEE checklists for each power facility are as follows;
As for a land-based power plant, various predicted impacts are listed and the proponents have
to evaluate the significance of the impacts for the pre-construction, construction, and operation phases of the project, respectively. Some mitigation/enhancement measures are also described corresponding to each predicted impact. Evaluations of the significance of the impact is composed of the following four alternatives; positive or negative, direct or indirect, long-term or short-term, and reversible or irreversible. Table S.1.4 shows the predicted impacts and mitigation/enhancement measures for a land-based power plant.
S-10
Table S.1.4 Impact Assessment and Mitigation for a Land-Based Power Plant Significance of ImpactsPredicted Impacts +/- D/In L/S R/I Mitigating/Enhancement Measures
Pre-Construction and Construction Phase of the Project 1. Increase in dust generation due to clearing, civil works and earthmoving activities
・ Regular watering of unpaved roads or exposed soil/ground
・ Remove soil/mud from tires of trucks and equipment before leaving the area
・ Hauling trucks should be covered with canvass or any equivalent materials
・ Set-up temporary fence around the construction area
2. Top soil removal and loss due to earthmoving activities, transport, access road construction
・ Stockpile the top soil in a safe place and use as final grading material or final layer
・ As soon as possible, rip-rap or re-vegetate the area
3. Erosion from exposed cuts and landslides due to earthmoving and excavation activities
・ Conduct construction activities during the dry season
・ Avoid long exposure of opened cuts ・ Installation of barrier nets
4. Sedimentation/siltation of drainage or waterways from unconfined stockpiles or soil and other materials
・ Set-up temporary silt trap/ponds to prevent siltation
・ Proper stockpiling of spoils (on flat areas and away from drainage routes
・ Disposal of spoils generated from civil works as filling materials
5. Pollution of nearby body of water due to improper disposal of construction wastes
・ Set-up temporary disposal mechanism within the construction area and properly dispose the generated solid wastes
・ Set up proper and adequate toilet facilities ・ Strictly require the contractor and its workers
to observe proper waste disposal and proper sanitation
6. Loss of vegetation due to land clearing
・ Limit land clearing as much as possible ・ Provide temporary fencing for vegetation that
will be retained ・ Use markers and fences to direct heavy
equipment traffic in the construction site and avoid damage to plants
・ Re-plant/plant indigenous tree species and ornamental plants
7. Disturbance or loss of wildlife within the influence area due to noise and other construction activities
・ Re-establish or simulate the habitat of affected wildlife in another suitable area
・ Schedule noisy construction activities during the day time
・ Undertake proper maintenance of equipment and use sound dampers
8. Noise generation that can affect the nearby residents
・ Schedule noisy construction activities during the day time
・ Undertake proper maintenance of equipment and use sound dampers
9. Generation of employment ・ Hiring priority shall be given to qualified local residents
S-11
Table S.1.4 Impact Assessment and Mitigation for a Land-Based Power Plant (Continued) 10. Right of way conflicts ・ Conduct consultations and settle agreements
before finalizing the detailed design 11. Increased traffic and possible congestion
・ Strict enforcement of traffic rules and regulations
・ Proponents should provide traffic aid during peak hours
12. Increase in the incidence of crime and accidents
・ Strictly require the contractor and its workers to follow safety rules and regulations in the construction and in the locality (in coordination with local authorities)
Operation Phase of the Project 1. Generation of domestic effluents
・ Provision of an effective (at least 3-chamber septic) tank
・ Provision of adequate wastewater treatment facilities
2. Generation of solid wastes ・ Separation of recyclable materials ・ Proper collection and disposal of solid wastes・ Proper housekeeping and waste minimization
3. Increased traffic and possible congestion as well as increase risk of vehicular related accidents
・ Strict enforcement of traffic rules and regulations
・ Placement of signs and warnings in appropriate places
Legend +/-:Positive impact/negative impact D/In:Direct impact/indirect impact L/S:Long-term/short-term R/I:Reversible/irreversible Source: DENR EMB RQE/9/18/2001/Guide for IEE Checklist on Land-Based Power Plants (final)
As for a mini hydropower plant, a total eighteen (18) items are listed as the predicted impacts regarding project location and design, construction phase, operation and maintenance, and abandonment and rehabilitation phase. The proponents have to evaluate those predicted impacts and answer the simple questions about mitigation measures.
Regarding the evaluation, it will be described for the project specifications or relevant parameters considered as being the cause of environmental impacts. The magnitude of the impact will be selected from four degrees: none, low, moderate, and high. Regarding the mitigation measures, the proponents will select the most likely measure from among prescribed measures or specify other measures. Table S.1.5 shows some examples of impact assessment/mitigation measures for a mini hydropower plant. These are extracted from the existing IEE checklist for a mini hydropower plant.
S-12
Table S.1.5 Examples of Impact Assessment / Mitigation Measures for a Mini Hydropower Plant Evaluation
Impact Relevant Subject and Parameters
Magnitude of Impact
Mitigation Measures
Project Location and Design Loss of species due to obstructions to movement of aquatic life
Height of the weir(m):_____
□ none □ low □ moderate □ high
□ No mitigation measure □ Fishway or by-pass planned.
Please describe the design and arrangement of the proposed mitigation facility and attach plans:
□ Further measures, please specify.Dying out of the riverbed between the intake and the outlet
Minimum residual flow with proposed project:
-In m3/s or l/s: ____ In % of mean annual
flow without proposed project: ___
□ none □ low □ moderate □ high
How is the residual flow provided? □ With a residual flow section in
the weir □ By-pass pipeline □ Other, please specify:
Construction Phase Contamination of soil and water due to spilling of dangerous substances (fuel, oil, lubricants, chemicals)
Storage, handling and disposal of dangerous substances
□ none □ low □ moderate □ high
□ following of the regulation of RA 6969
□ Other measures, please specify:
Operation and Maintenance Accumulation of floating debris at the intake
Design of intake □ none □ low □ moderate □ high
□ No mitigation measure □ Measures to reduce or avoid
accumulations of floating debris at the intake, please describe:
If there will be accumulations of floating debris at the intake, how will it be disposed? Please describe:
Abandonment and Rehabilitation Phase Flooding due to blocking of abandoned dam or weir
Abandonment of plant facilities including all equipment (machinery, electro-mechanical equipment)
□ none □ low □ moderate □ high
□ No mitigation measure □ Abandonment plan including
cost estimate, please describe and attach plan:
□ Other measures, please specify:
As for a power barge, a total of forty-five (45) questions are listed regarding the pre-construction/ construction, operation and maintenance, and abandonment and rehabilitation phases. The proponents have to evaluate those predicted impacts and answer simple questions about mitigation measures. The content of the questions are similar to the items for the description of the existing environments. They are composed of natural and physical, biological, and socio-economic environments including the following; excavation works and cut and fill activities during construction, impact on ecology, increase in the availability of employment, impact on indigenous people, noise, air pollution and hazardous waste during operation.
The proponents replay to the questions by answering “Yes” or “No”, and describe the process
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and impacts, as well as their mitigating/enhancement measures. There are no prescribed impacts or mitigation measures like the case of a land-based power plant or mini hydropower plant, so the proponents have to describe the impacts and mitigation measures by themselves.
Regarding the transmission lines and substations, the existing prepared format is the same as
land-based power plant. But there are no descriptions of the impacts and mitigation measures, so the proponents have to prepare these on their own.
S.1.2 Environmental Checklist for the Master Plan (1) Basic concept of making up environmental checklist
In this Master Plan an electrification method with a stand-alone system such as SHS, BCS or a mini diesel were also studied regarding the barangay electrification plan. These stand-alone systems were excluded from the target of the environmental checklist because the impacts on environment from them during installation and operation are considered very small. Regarding distribution lines, usually they will be constructed along the existing roads. In this environmental checklist, it is considered that a distribution line is the same as in the environmental checklist of a transmission line. Regarding a wind power plant, it will be considered as the target of the environmental checklist because it is impossible to deny that there will be a study or survey on wind farms in the future.
Therefore the target facilities of the environmental checklist are as follows;
Mini-micro hydropower plants Diesel power plants Power barges Transmission lines and substations Wind power plants
Again as mentioned in the foregoing paragraph, the IEE checklists have already been created
by the DENR-EMB for mini hydropower plants, power barges, transmission lines and substations. They are opened to the public on the DENR-EMB website (http://www.emb. gov.ph/eia/checklist.htm) and can be downloaded. Diesel power plants and wind power plants are not listed on the DENR-EMB website, but the IEE checklist was prepared in the past for land-based power plants.
In the case that power plants or related facilities are considered in the Master Plan, it is
necessary to study the development of those facilities. At the same time, the procedures that satisfy the existing Philippines EIS system will be necessary.
Therefore, the environmental checklist proposed by this Master Plan follows the style and the
contents that have already been employed as the existing IEE checklists for mini-micro
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hydropower plants, power barges, transmission lines and substations. Furthermore, items considered to be required will be added to the existing IEE checklist in consideration of the natural and social environments of Palawan Province.
Especially regarding transmission lines and substations, because there are no descriptions in
the existing IEE checklists forms about the predicted impacts and mitigating/enhancement measures, they should be included as much as possible.
Regarding diesel plants, the existing IEE checklist for power barges will also be used as the
checklist for a diesel power plant. It is considered that the existing IEE checklist for power barges cover the environmental consideration matters for diesel power plants such as noise or air pollution during operation
Regarding wind power plants, the environmental consideration matters will be listed with reference to other existing IEE checklists for a large-scale facility like a wind farm.
While the existing IEE checklists consist of many items, including the general information of
the project and required attachments, the environmental checklist for the power development Master Plan narrows the targets to the description of the existing environment and the impact assessment and mitigation. By corresponding with the form of the existing IEE checklists for the EIS system, it will be useful as the basic information on the necessary data for requiring EIS documents at the time of development.
(2) Environmental checklist for a mini and micro hydropower plant
The following contents will be added to the existing IEE checklist for a mini hydropower plant. (a) Description of existing environment <Natural and physical environment>
What area of the ECAN zoning is the project site located in? Are there limestone caverns or sinkholes around the project area?
< Socio-cultural, economic environment> Are there any cultural heritage sites around the project area? Are there any ancestral lands or communities of indigenous people in and around the
project area? Is the project site located in a NIPAS protected area?
(b) The impact assessment and the mitigation measures
The items shown in Table S.1.6 will be added to the existing IEE checklist. Moreover, the items indicated as the predicted impacts and mitigating/enhancement measures of a land-based power plant shown in Table S.1.4 will be also examined if necessary.
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Table S.1.6 Additional Impact Assessment / Mitigation Measure Items for a Mini Hydropower Plant Evaluation
Impact Relevant Subject and Parameters
Magnitude of Impact
Mitigation Measures
Project Location and Design Drying up of existing source of water supply along the waterway
Relationship between the proposed waterway route and existing source of water supply
□ none □ low □ moderate □ high
□ No mitigation measure □ Secure an alternative source of
water supply □ Further measures, please specify.
(3) Environmental checklist for diesel power plants and power barges
The following contents will be added to the existing IEE checklist for power barges.
(a) Description of existing environments < Natural and physical environments >
What area of the ECAN zoning is the project site located in? < Socio-cultural, economic environment >
Are there any cultural heritage sites around the project area? Is the project site located in the protected area of NIPAS?
(4) Environmental checklist for transmission lines and substations
The following contents will be added to the existing IEE checklist for transmission lines and substations, and the impact assessment and the mitigation measures will be described.
(a) Description of existing environment <Natural and physical environment>
What area of the ECAN zoning is the project site located in? <Socio-cultural, economic environment>
Are there any cultural heritage sites around the project area? Is the project site located in the protected area of NIPAS?
(b) The impact assessment and the mitigation measures
Table S.1.7 shows the impact assessment and the mitigation measures for transmission lines and substations.
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Table S.1.7 Impact Assessment and Mitigation Measures for Transmission Lines and Substations
Predicted Impacts Mitigation Measures
Pre-Construction and Construction Phases of the Project 1. Loss of vegetation due to land
clearing along the proposed route ・ Limit land clearing as much as possible ・ Provide temporary fencing for vegetation that will be
retained ・ Re-plant/plant indigenous tree species and ornamental
plants 2. Top soil removal and loss due to
earthmoving activities, transport, access road construction
・ Stockpile the top soil in a safe place and use as final grading material or final layer
・ As soon as possible, rip-rap or re-vegetate the area 3. Erosion from exposed cuts and
landslides due to earthmoving and excavation activities
・ Conduct construction activities during the dry season ・ Avoid long exposure of opened cuts ・ Installation of barrier nets
4. Sedimentation / siltation of drainage or waterways from unconfined stockpiles or soil and other materials
・ Set-up temporary silt trap/ponds to prevent siltation ・ Proper stockpiling of spoils (on flat areas and away from
drainage routes ・ Dispose of spoils generated from civil works as filling
materials 5. Pollution of nearby body of water
due to improper disposal of construction wastes
・ Set-up temporary disposal mechanisms within the construction area and properly dispose of the generated solid wastes
・ Set up proper and adequate toilet facilities ・ Strictly require the contractor and its workers to observe
proper waste disposal and proper sanitation 6. Disturbance or loss of wildlife
within the influence area due to noise and other construction activities
・ Re-establish or simulate the habitat of affected wildlife in another suitable area
・ Schedule noisy construction activities during the day time ・ Undertake proper maintenance of equipment and use sound
dampers 7. Noise generation that can affect the
nearby residents ・ Schedule noisy construction activities during the day time ・ Undertake proper maintenance of equipment and use sound
dampers 8. Generation of employment ・ Hiring priority shall be given to qualified local residents 9. Conflicts in right of way ・ Conduct consultations and settle agreements before
finalizing the detailed design 10. Significant decrease in the aesthetic
value of the area due to the tower or transmission line
・ Consider the shape and color of the tower to minimize the impact to the aesthetic value of the area
11. Increased traffic and possible congestion
・ Strict enforcement of traffic rules and regulations ・ Proponents should provide traffic aid during peak hours
12. Increase in the incidence of crime and accidents
・ Strictly require the contractor and its workers to follow safety rules and regulations in the construction and in the locality (in coordination with local authorities)
Operation Phase of the Project 13. Obstacle to the movement of
wildlife ・ Installation of trails for wildlife
14. Economic growth as the result of stable supply of electricity
・ Stable supply of electricity
15. Increased traffic and possible congestion as well as increased risk of vehicular related accidents
・ Strict enforcement of traffic rules and regulations ・ Placement of signs and warnings in appropriate places
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(5) Environmental checklist for a wind power plant The construction work of a wind power plant, including the construction of the tower to install
the wind turbine, is considered to be similar to the construction of a transmission line. The environmental checklist for transmission lines and substations will be used as the environmental checklist of a wind power plant. The features peculiar to a wind power plant should be considered. The following contents and items will be added to the environmental checklist for transmission lines and substations.
(a) Description of existing environments <Natural and physical environments >
Are there any the flyways of migratory birds around the planning site? (b) The impact assessment and the mitigation measures
Table S.1.8 shows the impact assessment and mitigation measures for a wind power plant. These will be added to the environmental checklist for transmission lines and substations.
Table S.1.8 Impact Assessment and Mitigation Measures added for a Wind Power Plant
Predicted Impacts Mitigation Measures
Operation Phase of the Project 1. Impact on migratory birds according
to the rotation of wind turbines ・ Paint the wind turbine blades with visible colors ・ Slow the rotation of the large blades to allow birds to pass
through 2. Noise of the wind turbine rotation ・ Adopt turbines that generate low noise during rotation
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Database
The Study team created a database, which consists of a wide range of data collected in the Study. The database serves many functions. It can store the data, calculate it and retrieve the data that the planers want. Additionally, the database makes it possible to update data easily.
At present, DOE and PGP have no databases for practical use for barangay electrification and power development at the provincial level. Databases can assist them in managing data related to the power sector, especially the electrification planning of un-electrified barangays.
However, the data collected in the Study is the data at present and they will change over time (e.g. population data, socio-economic data, barangay boundary data and environmental conditions will change over time). Therefore, updating data and upgrading databases will be needed in the future.
In this section, the basic concept and outline of the database is mentioned. For the details of each data item, please refer to the related individual sections.
S.2.1 Basic Concept of the Database
The database consists of the database software “ACCESS1” and GIS2 software “Arc View3”.
The basic structure of the database is shown in Figure S.2.1.
Most of the data for the database is collected by the Study team in the Study, and the spatial data for GIS is mainly from PGP.
All data are stored in 1 storage box “DATABASE”. ACCESS and ArcView share these data. This kind of database is called a “Personal Geodatabase”. ACCESS can help users to retrieve the data they want and to update the data easily by using the “Form”. On the other hand, ArcView can show not only the special data, but also attributes on the screen. Therefore, this software can help users to prepare maps for a presentation (e.g. Barangay Electrification Level Map, Hydropower Potential Classification Map, Environmental Protected Barangay Map and others).
The operation of the database is interactive on the screen for easy operation and users can select contents and retrieve the data easily.
S.2.2 Contents of the Database The database contents are summarized below; - Barangay Base Data - Electrification Condition - Demand Forecast - Distribution Line - Diesel Power - Mini-Micro Hydropower - Photovoltaic System - Barangay Electrification - Transmission Line - Environment - Power Development (WASP) - Data Updating
Figure S.2.2 Main Menu of the Database Storing these sector data in the database makes it possible to calculate and extract data that
users want by using the “Form”. Here is a part of the forms used in the database. (1) Barangay Base Data
This form shows the basic data of a barangay that was selected by users through a dialog box for a barangay selection (see Figure S.2.3).
The data contents shown in this form are listed below. - Population and number of households - Electrification level and methods - Barangay boundaries and location of a barangay center - Data from a socio-economic survey
Contents of Database
Contents of Database
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Figure S.2.3 Form of Barangay Base Data
(2) Electrification Conditions This form is useful to grasp the current electrification conditions in a province. The data is
mainly from ECs (in this case, from PALECO and BISELCO).
- Barangay electrification ratio (%) - Household electrification ratio (%) - No. of barangays by electrification level - No. of barangays by electrification method 1 (EC-grid, mini-grid or stand-alone) - No. of barangays by electrification method 2 (more detailed classification)
Figure S.2.4 Form of Electrification Condition
(3) Power Demand Forecast This form can calculate the data for power demand forecasts and show the results of power
demand forecasts for the barangay electrification and power development of the EC-grids. In this form, users can set parameters for the power demand forecasts.
Figure S.2.5 Form of Power Demand Forecasts (Daily Energy Consumption Pattern)
Select Municipality
Select Barangay
Popularion & Households Data
Location Data
Electrification Condition Data
Electrification Level
Electrification Method
Consumption Pattern for Photovoltaic System
Consumption Pattern for Mini-grid System
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Figure S.2.6 Form for Power Demand Forecasts (Results of Power Demand Forecast)
(4) Distribution Line Storing data for a distribution line with spatial information gives valuable information to planners
since the feasibility of distribution line extension for the electrification of un-electrified barangay depends on its expansion length. The database stores the location data of a barangay center, and storing these data makes it possible to retrieve data on barangays that are located around a certain barangay electrified by a distribution line.
The database also can retrieve the nearest barangay center for a target barangay and calculate distances between them automatically. Additionally, applying the criteria for the electrification level of the calculated data, the database makes it possible to find the nearest barangay electrified by a distribution line for a certain un-electrified barangay and to calculate the distance between them.
The form for a distribution line includes following items. - Barangay data connected to a distribution line (includes electrification conditions for neighboring barangays) - The nearest tapping point and distance (for a un-electrified barangay) - Cost data for distribution line extension Figure S.2.7 shows the form of a distribution line.
Figure S.2.7 Form of Distribution Line (Nearest Tapping Point)
Demand Forecast (kW)For Mini-Grid system
Demand Forecast (kWh)For Mini-Grid system
Nearest tapping point Data Target un-electrified Barangay Data Distance
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(5) Diesel Power The form shows the technical data and cost data for diesel power. The form consists of 2
components (diesel power for a mini-grid and stand-alone system, and diesel power for the backbone grid). The technical data and cost data of the candidate diesel power plant that will be developed to meet the demand of the backbone grid in the future are used in WASP analysis.
The form for distribution lines includes the following items. - Technical data and cost data (for a mini-grid and stand-alone system) - Technical data and cost data (for the backbone grid connection) - Existing power plant data
Figure S.2.8 Form of Diesel Power S.2.3 GIS Map
The database can also store spatial information for GIS. Using the GIS software application
“Arcview”, which was installed for DOE and PGP at the beginning of the Study, planners can create a variety of maps for a visual presentations. Figure S.2.9 shows the conceptual diagram of the GIS mapping.
Figure S.2.9 Conceptual Diagram of GIS Mapping
Diesel Power Plant Technical Data
DATABASE
Barangay Boundary Data
- - -
Spatial Data
Barangay Electrification Data - Electrification LEVEL
Table Data
1 2 3
LEVEL I
LEVEL II Un-Electrified
Spatial & Graphical
Add IndividualAttribute Value
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Once a planner creates a map in ArcView (saved as the “map document file” extension “.mxd”), they do not have to update the file in ArcView since table data is updated through an update form in the ACCESS software. The Study team has prepared the following map document files in the Study.
- Barangay Electrification Map (all of Palawan, detailed Map for Municipalities) - Existing Diesel Power Plant Map - Mini and Micro Hydropower Potential Location Map - River Gauging Station Map - Existing Distribution Line Map4 - Transmission Line Map5(existing and under construction transmission line) - Environment Protected Barangay Map - Indigenous People Living Location Map
Figure S.2.10 and S.2.11 shows examples of the GIS maps.
Figure S.2.10 Barangay Electrification Map (all of Palawan)
4 Distribution lines are shown as lines between barangay centers since PALECO does not have an exact location map for the existing distribution lines at present. 5 Transmission lines are plotted based on roughly estimated location maps since SPUG does not have an exact location map for the existing
backbone transmission line at present.
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Figure S.2.11 Transmission Line Location Map S.2.4 Data Updating
Data updating is an important job in order to grasp precisely the current status of electrification
in the province and this work requires database manageability. Considering that such points are required, the Study team put the form for updating data on the database. A series of forms make it easy for planners to update.
Figure S.2.12 shows a form for updating data.
Figure S.2.12 Form of Updating Data
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