Utility planning implications of electricity loss reduction in developing countries

Energy Policy 1994 22 (6) 531-537

Utility planning implications of electricity loss reduction in developing countries The case of Nepal Ram M. Shrestha and Gopal B. Bhattarai

Electricity loss as a percentage of total electricity generated is very high in most developing country utilities. The paper analyses the effects of reducing electricity losses on generation mix, capacity expansion plan, and environmental performance in the case of a predominantly hydroelectric utility in Nepal from a long-term power generation expansion planning perspective. A key finding of the study is that reductions of technical losses in transmission and distribution system do not always reduce emissions of air pollutants from power generation. Keywords: Electricity planning; Loss reduction; Environmental implications

Like most low income developing countries in the world, Nepal is faced with the problem of making electricity available to a large majority of its population; only about 9% of its people have access to electricity supply at present. Although electricity consumption has been growing rapidly (at an average annual rate of 14.3% during 1986-90), the level of electricity consumption in the country is still one of the lowest in the world in both per capita and per unit GDP terms: electricity consumption was 20 kWh per capita and 186 kWh per thousand US dollars of GDP in 1986. The power sector accounted for about 20% of the total governmental outlay for development projects in the country during the 1980s, 1 with most power Ram M. Shrestha is with the Energy Planning and Policy Program, Asian Institute of Technology, G P O Box 2754,

Bangkok 10501, Thailand; Gopal B. Bhattarai is with the Nepal Electricity Authority, Durbar Marg, Ratna Park, Kathmandu, Nepal. 0301-4215/94/06 0531-07 © 1994 Butterworth-Heinemann Ltd

projects being heavily dependent on external financing. Yet the present level of power sector investment seems to be hardly adequate to match the growing capital requirements of the sector given the low level of electrification and rapid growth of electricity demand in the country. Nepal Electricity Authority (NEA) is a public utility accounting for almost the the entire electricity supply in the country. In recent years NEA has resorted to frequent load shedding in order to cope with a severe shortage in its generation capacity. To a great extent, this situation could have been avoided but for the high level of electricity losses in its transmission and distribution system. The utility's electricity supply loss (technical and non-technical combined) as a percentage of total generation (26.6% in 1989-90) 2 was not only substantially higher than that of OECD countries taken as a whole (13.5% in 19873) but was also higher than that of many Asian developing countries. Clearly, the option of loss reduction deserves serious consideration by the utility planners, given its potential for enhancing the supply capability in the short run and the financial benefits in terms of additional capacity and generation costs that could be avoided in the long run. A number of studies have focused on the issue of transmission and distribution (T&D) loss reduction in the electricity planning literature. 4 These studies deal mostly with the techniques and/or economics of loss reduction. However, to the knowledge of the authors, none of the existing studies discusses the implications of loss reduction for a utility's power development plan and the environment. The distinctive feature of the present study is that it examines the implications of reducing the technical losses in the T&D system for a developing country's utility's 531

Electricity loss reduction in Nepal." R.M. Shrestha and G.B. Bhattarai

Energy forecast

i

I Loss reduction [

Sectoral } load shape

scenario

r__ MAE Load and load I shape forecast ~

Existing plant data Candidate plant data

I Loss cost reduction

}....

( Plant mix \~"

7-"

I

l

Total cost ) Generation ) expansion cost

/ Generation ) ~ expansion plan

I ~ Generation rnix )

(?nvironmental)implications

Figure 1. Flowchart of methodology.

generation plan and for the environment within a comprehensive long-term utility planning framework.

Methodology Figure 1 presents a schematic diagram of the methodology used in this study. Since loss reduction programmes would result in a change in system load shape and peak load, it is necessary to estimate the likely changes in system load duration curve (LDC) and peak load in each year of the planning horizon in order to derive the corresponding optimal generation expansion plan. The Model for Analysis of Energy Demand (MAED) 5 is used to forecast annual peak load and load shape for a reference case (defined as the base case in the next section). LDC under a given loss reduction scenario is derived from the LDC in the reference case following the methodology as discussed in Appendix 1. The Wien Automatic System Planning (WASP) model 6 is then employed to derive the optimum generation expansion schedule, capacity and generation mix from the available set of candidate plants and the corresponding total generation cost. A planning horizon of 20 years (1991-2010) is considered in this study. 532

Scenario definitions The following planning scenarios are considered in this study: • Base case: this is based on the medium scenario energy forecast of NEA. 7 Under the scenario, total electricity consumption was projected to be 616 GWh in 1991 and to grow at an annual average rate of 10.6% during 1991-2000 and 8.2% during 2001-10. Total electricity losses were projected to be 24% in 1991 and were assumed to improve to 18% by 2010. 8 As already mentioned, peak load forecast here is derived by using the MAED model. The characteristics of the candidate plants considered in this study are shown in Table 1. • Case 1: in this scenario, total system loss would be reduced to 17% of the total generation in 1994 (as compared to the corresponding figure of 22% in the base case) and would be maintained at that percentage each year thereafter during the planning horizon. All other things remain the same as in base case. • Case 2: this is a rather optimistic case where total system loss would be reduced to 12% of total generation in 1994 (as compared to 22% in the Energy Policy 1994 Volume 22 Number 6

Electricity loss reduction in Nepal." R.M. Shrestha and G.B. Bhattarai Table 1. Characteristics of candidate power plants.

Plant name Hydro plants Arun III Arun-III A Arun-III B

Bagmati Burhi Gandaki Kali G a n d a k i II Kali Gandaki A

Kankai Sapta Gandaki Upper Arun Upper Karnali West Seti Thermal plant Diesel (typical unit)

Capacity (MW)

Firm energy (GWh/yr)

Average energy (GWh/yr)

Total cost at 1989-90 prices b (US$ million)

SH SH ROR MPH ROR ROR ROR SH

402 268 134 140 600 660 90 60 225 360 240 360

2585 1990 595 540 2550 2790 580 210 1465 2450 1755 1960

2875 2155 720 625 2815 3040 640 245 1590 2680 1845 2095

672.6 581.5 91.1 453.7 986.6 1106.2 201.7 223.0 700.9 559.9 440.8 554.3

Diesel

20

Type a ROR ROR ROR

MPH

18.0

a R O R = run of river; MPH = multipurpose hydro; SH = storage hydro.

b The costs are based on border prices and include transport costs. Source: Nepal Electricity Authority, Update of the Least Cost Generation Expansion Plan, Vols 1 and 2, K a t h m a n d u , 1990.

base case) and would remain at that percentage each year thereafter during the planning horizon. Figure 2 shows the growth of estimated annual peak load during the planning horizon for these cases.

Generation planning implications In general, a loss reduction programme can affect a utility's generation expansion plan in terms of its capacity mix, scheduling of capacity additions and generation mix. For the scenarios considered, these effects can be summarized as follows.

have, in general, a longer gestation period than thermal plants.

Scheduling of plant additions The schedules of new plant additions under the selected cases are presented in Table 3. It can be seen from the table that the selection as well as scheduling of new hydro plants in case 1 would be the same as that in the base case. In case 2 the set of 1200

Capacity mix From the generation expansion planning exercise carried out with WASP-Ill model, it was found that a total of 863 MW of run of river (ROR) type of hydro capacity and 220 MW of thermal capacity would be added during the planning horizon in the base case. The total hydro capacity additions in cases 1 and 2 during the planning horizon were found to be the same as in the base case. As compared to the base case, total thermal capacity added would be 80 MW less in case 1 and 20 MW more in case 2. As can be seen in Table 2, the share of thermal capacity was relatively high during the initial years and mostly declining during the planning horizon in all the cases. This could be for mainly two reasons. First, only a small hydro capacity was committed for construction and expected to be available during the initial years. Second, even if selected, hydro plants Energy Policy 1994 Volume 22 Number 6

I000

D Base case 0 Case 1 x Case 2

/ J

_ / E l )

800

"D o

600

×/

x/

¢o o r~

400

2001

0

1991

I

1995

1999

I

I

2003

2007

2010

Figure 2. Peakload under different scenarios.

533

Electricity loss reduction in Nepal: R.M. Shrestha and G.B. Bhattarai Table 2. Capacity mix under different scenarios (%). 1995

2000

2010

Scenario

Hydro

Thermal

Hydro

Thermal

Hydro

Thermal

Base case Case 1 Case 2

63.5 67.1 71.2

36.5 32.9 28.8

73.3 77.1 68.7

26.7 22.9 36.3

81.0 86.0 79.2

19.1 14.0 20.8

Table 3. Scheduling of plant additions, a Base case 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Diesel (20) Diesel (20) Diesel (40) Diesel (20) and Jhimruk b Kali Gandaki A Diesel (40) Diesel (40) Arun III-A Arun III-B Upper Arun Diesel (40)

Case 1

Case 2

Diesel (20) Diesel (20) Diesel (20) Diesel (20) and Jhimruk Kali Gandaki A

Diesel (20) Diesel (20)

Diesel (20) Diesel (40) Arun III-A

Diesel (20) and Jhimruk Diesel (20) Kali Gandaki A Diesel (40) Diesel (30) Diesel (20) Arun III-A

Arun III-B Upper Arun

Arun III-B Diesel (20) Diesel (60) Upper Arun

Figures inside the parenthesis represent capacity in megawatts. h A n already committed 12 MW run of river hydro plant. a

hydro plants selected would be the same as that in the base case. However, the timings of plant additions would be different. As compared to the base case, the first hydro plant in case 2 would be deferred by two years, the second and third by two years each, and the fourth by three years.

that in either the base case or case 1, owing to deferral of hydro plants.

Environmental impacts The environmental impacts of electricity loss reduction in the case of NEA can be broadly classified into two categories: impacts related to hydro plants, and those associated with thermal generation.

Generation mix Table 4 shows the generation mix (ie shares of different types of plant in total electricity generated) in selected years. The share of thermal plants in total electricity generation was found to follow a pattern similar to that of thermal capacity share, ie it was mostly higher during the initial years of the planning horizon than in the later years. In year 2000 thermal generation under case 2, which involves a relatively larger loss reduction target, would be higher than

Impacts related to hydro plants As already discussed, all hydro plants selected during the planning horizon are of R O R type. Potential environmental impacts arising from such hydro plants could include soil erosion and loss of forest area from construction of approach roads, transmission lines, and the power plants. But according to

Table 4. Generation mix in selected years (%). 1995

534

2000

2010

Scenario

Hydro

Thermal

Hydro

Thermal

Hydro

Thermal

Base case Case 1 Case 2

95.55 97.63 98.76

4.55 2.37 1.23

99.93 99.97 95.26

0.07 0.03 4.74

99.70 99.92 99.98

0,30 0,08 0.02

Energy Policy 1994 Volume 22 Number 6

Electricity loss reduction in Nepal: R.M. Shrestha and G.B. Bhattarai

Table 5. Emission from thermal plants (tonnes)." 1995

2000

2010

Scenario

COz

NO,,

SO2

COz

NOx

SOz

CO2

N O , , SOz

Base case Case 1 Case 2

34535 17334 8622

30 15 7

275 138 69

896 337 56472

1 <1 49

7 3 449

8447 2016 415

7 2 <1

67 16 3

a Diesel used in power plants in Nepal is assumed to have sulphur and carbon contents of 1% and 78% respectively. Fuel input of diesel plant is 0.21 kg/kWh. The corresponding emission coefficients (in grams of a pollutant emitted per kilowatt hour of electricity produced) used to calculate the levels of emission are as follows: 4.79 for SO2, 0.52 for NO~ (assuming 80% reduction due to control device), and 601.66 for C02. Source: Nepal Electricity Authority, Update of Least Cost Generation, Vols 1 and 2, Kathmandu, 1990; Asian Development Bank, Environmental Considerations in Energy Development, Manila, 1991; Ram M. Shrestha, 'Environmental implications of electricity supply in selected Asian countries', Proceedings of International Conference on Energy and the Environment, 27-30 November 1990, Bangkok.

N E A , no significant environmental impacts have been envisaged with the construction of the new hydro plants. 9 As can be seen from Table 4, for a small-scale loss reduction target as in case 1, both the selection of hydro plants and their schedule would be the same as that in the base case. This implies that there would be no difference between case 1 and the base case in terms of environmental impacts associated with new hydro plants. The situation is, however, found to be different in case 2, with a relatively large loss reduction target. Although the set of hydro plants to be added under this case is the same as in the base case, their additions would take place one to three years later than in the base case (see Table 4). The deferral of hydro plant constructions here would clearly help delay local deforestation associated directly with hydro plant construction. It would also delay deforestation from the commercial logging (legal as well as illegal) that could ensue with the building of approach roads to hydro plant sites. This could also be viewed positively from the global environmental perspective as it implies maintaining the CO2 absorption capacity of the national forests for a longer period than in the base case.

notion that i m p r o v e m e n t s in T & D efficiency (ie reductions in T & D technical losses) would necessarily help reduce emission of air pollutants. For example, in a recent paper, Schramm t° states (p 746): An important side benefit o f . . . performance improvements would be the reduction in environmental pollution resulting from the prevention of unnecessary losses and outright waste both on power supply and consumption side. The upshot of the discussion here is that while a reduction in technical losses in the T & D system would directly result in a reduction of pollutant emissions in the case of electric utilities based on a single generation technology and using a fuel of uniform quality, the same cannot be argued generally for utilities that employ multiple generation technologies and fuels. The issue of whether the option of reducing technical T & D losses would improve an electric utility's performance in the emission of air pollutants is linked with the level of target loss reduction itself as well as the changes in peak load and system load shape it implies. It is also related to the size and type of candidate plants as well as quality of fuels used.

Impacts associated with thermal generation

Table 5 presents estimated emissions of CO2, NOx and SO2 f r o m thermal generation in selected years. With the small-scale loss reduction target in case 1, there would be a reduction in emissions of air pollutants from thermal generation, while the impacts from hydro plants remain unchanged. As can be seen from the table, a large-scale loss reduction in case 2 would, however, lead to increased emissions of air pollutants occasionally (eg in the year 2000). Such a finding contrasts with the apparently popular

Energy Policy 1994 Volume 22 Number 6

Economics

of loss reduction

Table 6 shows the costs of generation, and potential gross savings in total cost arising from target loss reduction in the selected cases. Generation cost here includes capacity and variable costs of power generation. The gross savings from loss reduction in cases 1 and 2 are due to capacity and generation costs avoided in these cases as c o m p a r e d to the base case, and express the upper bounds for the costs of loss reduction to be economically viable. 535

Electricity loss reduction in Nepal: R.M. Shrestha and G.B. Bhattarai Table 6. Total generation cost and gross savings from loss reduction during 1991-2010 at 1989 prices (US$ thousand).

Scenario

Total generation cost ~

Total gross saving due to loss reduction

Gross saving per kW of peak load avoided

Base case Case 1 Case 2

660 542 599 078 545 333

20 684 39 017

2.11 2.87

a This includes the capital cost of NOx control device at US$70/kW and a recurrent cost of US$12/kW/year in the case of diesel plants. A discount rate of 10% per annum is used.

Table 6 also presents values of gross saving per kilowatt of peak load avoided through loss reduction. These are derived by the following the methodology described in Appendix 2. Interestingly, the gross savings per kilowatt are significantly higher than the standard unit T&D capacity cost even if the latter was assumed to be a proxy for loss reduction cost per kilowatt of peak load avoided. 11 At a unit transmission line capacity cost of US$700/kW 12, the net savings per kilowatt of peak load reduction under cases 1 and 2 were found to be US$1410 and US$2166 respectively. These savings in costs would imply a considerable reduction in average cost of electricity generation, ie from USc4.2/kWh in the base case to USc4.0/kWh in case 1 and USc3.8/kWh in case 2 and hence a reduction in electricity prices and an improvement in consumer welfare.

Conclusions and final remarks One of the key findings of this study is that reductions of T&D technical losses need not always result in the improvement of environmental performance of the utility. In the case of NEA, a large-scale loss reduction programme (eg case 2) was in fact found to result in larger emissions of air pollutants from thermal generation during some years in the planning horizon than would be the case without the loss reduction programme (base case). The issue of whether an electricity loss reduction programme can consistently improve environmental performance would depend upon scale of loss reduction programme, size and type of candidate power plants, and changes in system load shape. It is to be noted here that we have not considered the social costs of emitting air pollutants from power generation in the study. However, it is expected that the above finding would still hold in qualitative terms even if such costs were included. The study has examined the effects of technical loss reduction from the long-term generation expansion planning perspective of an utility and showed 536

that there would be substantial savings in costs to a developing country utility like NEA not only in the short run but also in the long run. Clearly, the option of technical loss reduction merits serious consideration by utility planners. However, for a successful implementation of such an option, it is important to determine the types and levels of technical losses in the T&D system carefully first and design the appropriate technical mitigating measures accordingly. This is because, in many developing countries, it is non-technical losses which are the larger proportion of total T&D losses. The problem of reducing non-technical losses, is, however, often found to be much more complex to solve than the problem of technical losses as the former is frequently linked with fraudulent billing/collection system and social attitudes towards pilferage, for example. 13 We intend to discuss the planning implications and other issues related to non-technical loss reduction in a subsequent paper. An earlier version of the paper was presented in the 16th Annual International Conference of the International Association for Energy Economics (IAEE) on 27-29 July 1993 in Bali, Indonesia. Financial support for the study was provided by the Canadian International Development Agency (CIDA) under the CIDA/ AIT-CUC Partnership Project. lWater and Energy Commission Secretariat, 'Background paper for energy issues and options in the Eighth Five-Year Plan', National Workshop/Seminar, 6-7 September 1989, Kathmandu. ZNepal Electricity Authority, Profile of Progress: 1986-90, Kathmandu, 1990. 3International Energy Agency, Energy Balances of OECD Countries: 1987-88, Paris, 1990. 4See eg M.W. Gustafson and J.S. Baylor, 'Approximating the system loss equation', IEEE Transactions on Power Systems, Vol 4, No 3, 1989, pp 850-855; Asian Development Bank, Power

System Efficiency Through Loss Reduction and Load Management, Manila, 1985; Economic and Social Commission for Asia and Pacific (ESCAP), Techniques and Methods for the Reduction of Transmission and Distribution Losses: Asian Efforts, RAS/86/ 136, 1990, United Nations, New York; R.M. Shrestha and M.P. Acharya, 'Electricity losses in power systems of selected Asian countries: a comparative study', Proceedings of International Conference on Power Development in Afro-Asian Countries, New Delhi, India, 10-14 December, 1990. 5International Atomic Energy Agency, Expansion Planning for

Energy Policy 1994 Volume 22 Number 6

Electricity loss reduction in Nepal: R.M. Shrestha and G.B. Bhattarai

735-747. UNormally, the costs of technical loss reduction programmes per megawatt of loss load reduced are significantly less than per megawatt of new transmission capacity. 12This figure, although arbitrary, is comparable to the World Bank average estimate of US$550 per kilowatt (at 1987 prices) as cited in US Agency for International Development, Power Shor-

Electrical Generating Systems, Vienna, 1984. 6International Atomic Energy Agency, Wien Automatic System Planning Package (WASP): A Computer Code for Power Generation System Expansion Planning, Users' Manual, 87-03342 (1980),

IAEA, Vienna, Austria. 7Nepal Electricity Authority, Ten Year Transmission and Distribution Plan: Load Forecast Study, Final Draft Report, Kathmandu, 1989. SOp cit, Ref 4. 9Nepal Electricity Authority, Report on Implementation of Arun I11 Hydro-Electric Project, Kathmandu, 1991. l°G. Schramm, 'Issues and problems in the power sectors of developing countries', Energy Policy, Vol 21, No 7, 1993, pp

tages in Developing Countries: Magnitude, Impacts, Solutions, and the Role of the Private Sector, Washington, DC, 1988.

13See eg Gunter Schramm, 'Technical and non-technical power losses in developing countries', a paper presented at ELEC 88, International Symposium on Production, Transmission and Distribution of Electric Energy, Paris, 14-18 November, 1988.

Appendix I Given a load duration curve (LDC) of a power system for a period under the base case, the following approach has been followed to derive the corresponding LDC under a loss reduction scenario. Suppose that the target value of loss reduction in a year is A E and that the total duration of the LDC is T. The LDC is broken down into n number of blocks across the total duration. If the duration of block i is denoted by ti (i = 1 .... n), then the summation of durations of n blocks should be equal to T; that is,

n Z ti = T i=~ Since electricity loss at any time is proportional to square of the load (ie power d e m a n d ) at that time, the amount of loss reduction in block i (denoted by AEi) is derived using the following expression: AEg

p2i ti tl

* AE

E P~t, ~=1

i =

1 ..... n

(1)

where Pk and 6 represent the average load and duration respectively corresponding to block k. The reduction in average load in block i (denoted by A P i ) from loss reduction can be obtained as follows:

6Pi -

AEi

. t = 1..... n

ti

(2)

The average load in block i after loss reduction (denoted by Pi*) is then given by Pi* = Pi - APi.

Appendix 2 The gross saving per megawatt of peak load reduction has been calculated as follows. Let L'~ = peak load in year t under the base case Lit = peak load in year t under loss reduction case i C = gross saving per megawatt of peak load avoided through loss reduction programmes The reduction in peak load in year t under case i as compared to that under the base case is given by: R~ = L 0, -

t .i

(3)

The gross saving in year t (denoted by ASJ due to peak load avoided through loss reduction programmes is related to the level of net reduction in peak load in the year and can be expressed as"

Energy Policy 1994 Volume 22 Number 6

AS, = C A Q ,

(4)

where AQ, denotes incremental reduction in peak load during year t and is given by:

m e g a w a t t of p e a k load a v o i d e d through loss reduction programmes, C, can be calculated from the following relationship: N 1=1

Total present value of savings in generation expansion cost during the planning horizon from loss reduction in case i (APV/) is given by: A P E = PVo - PVs

/~kS,

A P V i = Y~ (1 + r)'

max [o, (R~ - R~ ,)l

(5)

where PVo and PVi represent the optimal total cost of generation system expansion under the base case and case i respectively. If all savings in generation expansion cost were solely attributed to reduction of peak load (or capacity avoided), the value of gross saving per

(6)

where the right-hand side expression represents the total present value of savings from the reduction of peak load, r is the discount rate, and N is the number of years in the planning horizon. Thus, from Equations (4) and (6): c =

APE

(7)

= (1 + r)'

537