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CLOSE THIS BOOKLocal Experience with Micro-Hydro Technology (SKAT, 1985, 171 p.)
F. ECONOMIC CONSIDERATIONS
VIEW THE DOCUMENT(introduction...)
VIEW THE DOCUMENT1. BASIC APPROACH a) Cost-Benefit-Approach for Socio-Economic Selection
VIEW THE DOCUMENT2. MICRO-HYDROPOWER AND LARGER HYDROPOWER PLANTS
VIEW THE DOCUMENT3. MICRO-HYDRO PLANTS AND OTHER ALTERNATIVES

Local Experience with Micro-Hydro Technology (SKAT, 1985, 171 p.)

F. ECONOMIC CONSIDERATIONS

The expert-group on hydropower for the Nairobi-Conference stated that from all renewable energy-sources, existing hydropower ranks top as far as accessible know-how as well as its economy are concerned. This statement will be elaborated on here by using a multi-level cost-benefit-approach which will be applied on micro-hydro installations compared to larger hydro-structures and on micro-hydro installations compared to alternative energies.

1. BASIC APPROACH a) Cost-Benefit-Approach for Socio-Economic Selection

a) Cost-Benefit-Approach for Socio-Economic Selection

When the World Bank says that future energy demand should be met at the least cost the question arises what cost are to be considered. Likewise one has to decide what kinds of benefits should be taken into the calculation. It is appropriate to say that energetic infrastructures - as all infrastructures have expecially many external economies and diseconomies. One way to get hold of most of the important effects, internal and external, could be the following system.

External cost and benefit are defined as the influence which an economic project's creation and performance exercises unvoluntarily on the "situation" (mostly profitability) of other units. Thus the operation of a micro-hydro plant could exercise stimulating effects-via backward linkages -on local workshops for the construction of generating equipment, or on civil engineers etc. (external economies), but would perhaps foster some new sociological stratification if one grainmill-owner or one sawmill-owner uses most of the produced electrical or mechanical energy to the detriment of others (external diseconomies).

It is for operational reasons advisable to differentiate among various levels of the cost-benefit-analysis. Here, three levels are suggested:



FIGURE

FIRST COST-BENEFIT LEVEL

· tangible internal cost:

-Civil works (dam, canal, powerhouse etc.)

-Generating equipment (turbine, governor, generator etc.)

-Penstock

-Operation and maintenance (also fuel cost if non-renewable energy-source, or labour-cost for collecting dung for biogas-purposes)

-Local distribution network (L.T.)

-Other (R+D, project-design, land acquisition etc.)

· tangible internal benefit:

-Mechanical and/or electrical energy-supply

for consumption (domestic) uses
for productive (entrepreneurial) uses

-as "price per kWh" (as measure of comparison to other energy-options)
-Surplus revenues within local community
-Producers IER (internal economic rate of return)

Comments:

· Internal cost means cost of producing unit plus some local public investment in local grid.

. Internal benefit means benefit to all individuals, households and economic units (incl. the hydropower-producing unit). which are integrated into the new energy-system

· The price per kWh is to be calculated over the life of the project

· The surplus-revenues of customers (be it economic units or individuals) are obtained because of more economic activity as such and/or because of productivity-effects providing more foodstuffs per acre, more textiles per day, more cement per hour etc.

· The calculation of the IER needs a forecast of costs and revenues (those of the hydropower-producing unit) which requires a concept about selling prices and tariffs. The estimated future costs and revenues (e.g. the net balance) must be discounted as will be shown later on. Here comes in a difficult adjustment problem: the shadow-prices, i.e. distorted prices, be it too high or too low prices for cost-components of the hydropower-plant, or of alternative energies (e.g. subsidies for kerosene).

It remains to be said that the two-fold aspect of the tangible internal benefit (consumption-aspect and producers-revenue-aspect) coincide when a household or an economic unit is supplier and sole consumer at the same time (e.g. a family-biogas-plant).

So the first cost-benefit-level, by aggregating all cost over the life-period of the installation, determines a selling price of energy (which provides at least a cost-covering IER); the selling price must be related to given purchasing power (incl. the energy-induced increases of it) as well as to the selling prices of alternative energies and their revenue-increasing potential.

SECOND COST-BENEFIT-LEVEL

· tangible external cost:

-Interlocal (regional, national) distribution-grids (H.T.)
-Step-up and -down transformation
-Distribution-losses of energy
-Subsidies
-Need of foreign currency

· tangible external benefit:

-Increased tax revenues

-More diversified and possibly cheaper (for economies of scale arise when energy-input increases production per hour) product-supply to the local and regional community

-Less subsidies for alternative energy-sources

-Lowering of import-bill (e.g. oil) and increasing of import-substitution

Comments:

Though this level is still "tangible" the quantifying problem becomes more difficult. At least rough indications should be possible. The result of this level cannot stand for itself; it has to be superimposed on the result of the first level. To elucidate this: it would make sense to accept a negative IER and subsidise the hydropower plant with a fraction of the increased tax revenues generated by more economic activities. There would still remain a net benefit to the community.

THIRD COST-BENEFIT-LEVEL intangible cost (examples):

-new need arises to regulate the use of rivers by law and enforce its adherence

-Price-increases for consumer goods in case of monopolistic markets

-Privileges of electrified households, workshops, farms etc. in contrast to others

-Increase of local capital-interest and credit-shortage as a consequence of concentrated capital-allocation on a hydroplant

-Short-term displacement of human energy/work in economic production by mechanical and/or electrical power

-etc. intangible benefit (examples):

-more comfort

-educational effects (lighting), health effects (heating)

-environmental protection, flood control

-recreation (in case of dam ' end lake)

-degree of "self-reliance", local production

-slowing down of urbanization because rural quality of life increases

-learning process

-"fall-out" and "trickle-down effect" of more productive methods as a consequence of hydropower and the demonstration-effects

-Prevention of deforestation

-etc.

Comments:

The larger the powerplant the more difficult it usually becomes to seize and to assess all intangible effects, internal and external.

Again, considerations of this cost-benefit-level should be at least added if not integrated into the net-effects of the first and second level.

Summarising one may say: there is an actual problem of quantifying the inputs into the cost-benefit-analysis. Many factors -above all on the third level can only be assessed in a qualitative way; and even this is arbitrary. The first-level-result may be a negative IER, e.g. perhaps because of wrong input-prices (expensive turbine, possibly because of a highly overvalued rate of exchange, expensive cement), because of wrong selling-prices per kWh, or wrongly structured tariffs, because of a low use of a high-cost project (load-factor problem), etc. But these influential factors are quantifiable; more difficulties arise when one has to justify a bad IER with intangible benefits like the longrange value of "rural development" or "local self-reliance". Fortunately this problem will not arise too often since empirical evidence shows that large, centralised hydropower-plants have difficulties to compete successfully with smaller plants where loads are small and scattered, when calculated on the basis of tangible (internal and external) costs and benefits. Thus, the intangible benefits are rather an additional than a compensating incentive.

A further problem connected with cost-benefit is the question of discounting in order to calculate the IER. As mentioned earlier, the IER needs a forecast of costs and revenues which then are related to each other and should produce some positive return on total initial investment over the life-period of the project. At least the running cost, including capital-interest cost, should be reimbursed. The problem of depreciation is treated later (refer to end of section 2 lit. a). The question is how one can compare costs or revenues of today with those of thirty years ahead? Obviously it can only be done if all future costs and revenues are discounted to the present value of costs and revenues. The concept underlying this is simple: money -be it cost (C) or revenue (R) - of a future date (tn) is worth less than the synonym amount today (to) since this money -if accessible today -would be invested at a given interest-rate (i). Up to tn. the initial amount would have increased according to the formula Ctn = Cto (1 + i)n. This elucidates that much of the IER depends on the interest-rate chosen, since in hydropower plants, all costs occur today whereas the revenues are distributed over thirty to fifty or even more years. This simplifies the discounting calculation since only the future revenues which one anticipates, have to be discounted to their present value. A high interest-rate lowers the today-worth of future revenues, a low interest-rate makes future revenues appear high at to.

Fig. 72 exemplifies the discounting method; it is assumed that all future revenues occur together at tn.


Fig. 72: Discounting Alternatives

Case I shows that in view of the present value of the future revenue, the today's capital investment is comparably low, since more capital than Cto would have to be put into alternative investments today (loans, bank-account etc.) to reach the future revenue Rtn.

The following example (refer to fig. 73), will further illustrate the problem. A hydropower plant of 50 kW installed capacity at a cost of $ 1'500/kW ($ 75'000.- total investment) is planned for a life-period of 10 years. The prevailing interest rate of the country -also to be used for discounting -is 14 % p.a., for investments through a bank or other financial institutions. Applying the formula mentioned earlier the capital at t10, including compound interest, will amount to $ 278'025.--. If the investor's estimated revenue of the investment into the hydropower plant is higher than $ 278'025.--(estimation I) he will quickly embark on this energy-investment. Should the estimated future revenue be lower than $ 278'025.--(estimation II), then the investor will prefer to entrust his capital to a bank or another institution granting the return of 14 %.


Fig. 73: Investment Decisions

The term "investor" needs a further explanation. The discounting procedure is relevant in two cases:

· the private investor choosing among alternative investment-opportunities

· the public investor having an utility-obligation, thus choosing among investment-alternatives within the energy-supply possibilities.

A certain complication of the discounting-method stems from the fact that the future revenue will rather be a yearly return than an aggregated sum at the end of the plant's lifespan. Mathematically it means that each year's revenue must be discounted separately or, should costs also arise yearly, the net balance between yearly cost and revenue.

In other words: the higher the discount-rate must be chosen (again: meaning that at this interest rate one could invest today's money) the less advantageous are capital-intensive installations (unless staggering kWh-prices are applied); a high discount-rate favours labour-intensive installations because it keeps down capital-investment at to. The low initial capital-investment respectively the low capital (interest) cost, will thus allow for more labour-intensive plant operation.

In practice, analysts have tended to underestimate seriously the level of discount rates prevailing in poor areas. One result has been to focus attention exclusively on relatively capital-intensive and complex energy systems (see: French: Renewable Energy Systems, p 41; for example of calculation see NRECA, Small Hydroelectric Powerplants, p 104 f).

In summary it is necessary to:

· Determine all pertinent factors to be included into the three cost-benefit-levels

· quantify and qualify these factors . discount the tangible costs and revenues.

The results may then be used to:

· compare hydropower plants of different types and sizes
· compare hydropower plants with alternative energies.

As to the latter point however, one will first have to consider the "second law efficiency" of thermodynamics before embarking on economic analysis since there is a distinct interrelationship between task, energy-source and energy-device, which - when one end-use (task) is considered -eliminates many energy-alternatives at the outset for thermodynamic reasons rather than for economic reasons.

b) Constraints on the Selection of Energy-Sources

End-uses like lighting, cooking, heating or grainmilling, sugar-processing, brick-making, water-pumping, dyeing, cooling etc. may require very different energy-sources, ranging from wood, liquefied biomass, grid electricity, mechanical hydropower, biogas, kerosene etc. To begin with, a selection will consider thermodynamic constraints by tabulating the tasks into temperature-grades, lighting, stationary and mobile power. In an outstanding analysis of a village's energy needs, Reddy shows this as reproduced in fig. 74. Thus the economic cost-benefit-analyses will have to concentrate on the alternative options left over after this energetical pre-selection.


Fig. 74: Selection of Sources and Devices for Pura

Source: Reddy

c) Concluding Remarks on Decision-Criteria

The energetical selection (lit. b) and the economic cost-benefit-approach (lit. a) will both limit the energy-options to a few; to narrow further down the remaining alternatives, some more general criteria might be helpful. These are:

· the matching of the time-dependence of the energy-utilising task with the time-variation -if any -of the supply of energy from the chosen source. If matching is bad, energy-storage becomes necessary which implies new cost. The problem may arise with the variable discharge of rivers, the time of sunshine, variable wind-velocities etc.

· the primacy of basic needs

· the local self-reliance and system-independence providing social participation and control

· the environmental soundness; the primacy of renewable energy-sources and the minimising of negative ecological impacts

These additional criteria may be a useful guidance when a non-decisive result among alternatives arises.

The following sections will illustrate some of the criteria of lit a), b) and c), by way of examples of hydropower plants and alternative energy-sources. A full three-level cost-benefit analysis of each and every option is impossible at this place, however.

2. MICRO-HYDROPOWER AND LARGER HYDROPOWER PLANTS

All figures given from examples, and experience with hydropower plants are to be taken as order of magnitude since every case will differ very much for reasons of different labour costs, equipment-cost, site-cost, import-cost etc. Furthermore, figures reflect different cost/revenue-years; it would be academic to de- and revaluate foreign currencies to a comparable international statistical basis in U.S. Dollar ($) since neither inflation-rates nor rates of exchange can accurately be secured.

a) Experience with Tangible Internal Costs

The World Bank states that the economic limit for mini-hydro projects (under 1 MW) is in the $ 2'000 -3'000 per kW range. One should consider this statement as too rough and a cost per kW of $ 3'000 as too high to electrify hamlets, micro-industries and villages, in view of experience gained in a number of projects. A report from OLADE 1'000 to 2'000 per kW as the desirable goal, and still other sources state that efforts should be made to remain close to $ 1'000 per kW for obvious reasons. Based on this, it is now of interest to look at some actual figures, to see how far this can be achieved.

A series of different types of turbines from European manufacturers is shown in fig. 75, in the output range from 30 kW to 300 kW, and a head range from 2,3 m to 350 m. The costs given are updated to the level of 1980 and include complete generating equipment (e.g. turbine, step-up transmission where necessary. flywheel, governor, alternator, valves and other acessories, but excluding penstock). It becomes clear from the table that equipment for low head and low output becomes very costly.


Fig. 75: Different Hydro Generating-Equipment Costs

Source: Integration GmbH, Laufwasserenergie

The same source states that euqipment cost ranges from 40 to 50 % of total cost in conventional hydro installations of the sizes referred to. This means that -since low-head installations have a relatively larger flow rate - civil construction costs amount to 50 % of total cost for heads above 20 m, and to 60 % for lower heads. This is of course broadly generalised but it serves the purpose of arriving at a relevant magnitude of total cost.

Based on fig. 75, the calculated total costs are between $ 1'825 and $ 8'750 per kW for heads from 2,3 to 13,5 m and $ 1'000 to $ 3'000 for heads between 27 and 350 meters. Thus a very clear cost-function of head and size is reflected in total plant costs. Notwithstanding this trend, it is also true that equipment for the highest head with an output far above the average of the examples given, is not the cheapest. Much depends on the type of equipment and the suppliers pricing. It is nothing unusual to get quotations for the same site, which differ by several hundred percent from different suppliers. This adds another variable, making representative cost analysis still more difficult.

As far as costs of civil construction-components are concerned, no standard cost unit can be given here. Dams, canals and intakes will obviously cost a very different share of the total for different sites. Much depends on the topography and the geology, and also on the construction method applied and the materials used.

Of interest in the context of this paper is now a comparison with costs of local technology. The examples in fig. 76 are all actual project costs at about the price level of 1980. In all cases shown, the turbine is of local design and construction. Other equipment components are also made locally, such as step-up transmission, flywheels, coupling, base frames, gate-valves and penstock.

Governors are not used at all in the smaller plants, while on the bigger sets, different solutions were found as indicated. Alternators are in all cases imported; either from within the region or from overseas.

Comparing data from fig. 75 and 76 brings to light a number of facts. These should not be interpreted to be the absolute and only truth for reasons of enormous project diversity. However, the trend clearly stands as shown:

· The influence of variations of head and size on price are not pronounced because of a high degree of flexibility as to the chosen equipment configuration, which is appropriate to the situation.

· The average share of equipment cost of the total is 26,5 %, e.g. clearly less than the conventional 40 to 50 %.

· Total costs for the range from 10 to 100 kW using local technology, compared to cost per kW in fig. 75 show reversed economies of scale.

· Taking the average figure for equipment cost of $ 265.-/kW and comparing this with the average of $ 890.-/kW of eight turbines (imported in fig. 75, shows that on an average, locally made sets (fig. 76) cost approx. 30 % of imported equipment only. (To arrive at a more representative average cost for imported equipment, the first three figures - representing atypical cost because of low head/low output -have not been included).

· Taking amounts for total cost for both series of examples shows, that only with local technology can the stated goal of $ 1'000 per kW be approached under "normal" conditions.


Fig. 76: Cost of Generating Equipment Using Local Cross-Flow Turbine

Sources: BYS, Nepal; NEA, Thailand; ITB, Indonesia

Conclusions:

· It is possible to counter the rule of traditional economies of scale by using local technology in the range up to 100 kW.

· It is also possible to reduce traditional overall costs considerably.

· The result is, that the range up to 100 kW -where local technology is possible -becomes more economical as compared to the range from over 100 kW to 1 MW.

This latter point can not directly be derived from the examples shown but is the result of an evaluation of hydropower activities in Nepal, in the range up to 500 kW. The study referred to maintains that there are two economically feasible ranges of size in evidence. The first from 2 to 30 kW ( and the second from 1 to 3 MW because in the latter, economies of scale are pronounced. For the range from over 100 kW to 1 MW, it is the following factors that make it uneconomical:

-too big for local technology, therefore high capital cost
-requires skilled and professional staff, therefore high running costs
-too small for a remarkable effect of economies of scale.

The same authors also introduce a new dimension of cost-reduction for marginal village electricity-supply: Many small hydropower installations exist in Nepal for mechanical power supply to agro-processing units, such as mills and oil presses. These projects are operating profitably, and could therefore be equipped with small alternators to provide domestic lighting and very limited other electricity uses, at only marginal cost of $ 250 to 420 per kW (which may be extended to 100 kW if head is over 20 meters as shown in fig. 75) this also includes electricity distribution). As indicated previously, one can take it for granted that the upper limit of these very economical hydropower plants can be extended from 30 kW to about 100 kW, without jeopardising the intangible benefits of still using appropriate technologies, which are locally manageable.

Similar cost-experience has been gained with micro-hydro installations in China. The cost-concept is based on the conviction that canals, dams, roads etc. can be attributed to irrigation and flood-control anyway, so that electric power can be calculated at extra-cost for the generating equipment and civil works implied. In this way, costs attributable to electricity generation and distribution of as low as $ 350 per kW, are reported.

As to the distribution of energy, local low-tension lines (380 V) were included in the first-level cost outlay. L.T.-lines are possible up to a couple of kilometers, depending on the material used for wiring. Good examples exist in Nepal or in Tanzania. Most of the Tanzanian micro-hydro plants have a short overhead distribution line to the consuming points, with an average length of 800 meters (min. 200 meters, max. 2 km). The electrical energy produced by these micro-hydro plants, is used mostly for households, water pumping, productive and agricultural machinery, hospital-stations, etc. With such short distances, a low-tension line is sufficient. Since the local low-tension distribution network must be provided anyway, the cost of local distribution would remain the same whether the electricity-supply comes from the local powerstation, or from grid extension fed by a distant power plant. But the point is that the villages have practically no chance to get a grid-extension, since step-down transformation on the high-tension side is a costly thing. One must rather envisage a grid-extension in a maybe not so distant future, after the local power plant has contributed to the village development, so that this can afford later-on to integrate its consumers into a larger grid-system.

Another cost-component of distribution is the metering of energy-consumption. It depends much on the tariff applied and will be discussed later.

To conclude on tangible internal cost, the operation-and maintenance-cost shall briefly be sketched: Hydropower plants are characterised by high initial capital-investment and low operation and maintenance cost, whereas diesel-powered generators are cheaper in terms of investment, with high running fuel-cost. For hydropower plants, operation cost must be seen as a function of the size of the plant and the salaries of local staff. Maintenance cost depend more on the characteristics of the site (rebuilding of intakes, removing slides on canals etc.) than on the size of the plant. Experts on this problem maintain that operation and maintenance cost for small hydropower plants (between 100 -400 kW) are almost independent from installed capacity and amount to roughly $ 25'000 - 40'000 per annum. Consequently, operation and maintenance cost per unit produced, decrease rapidly with size. They conclude that operation and maintenance costs can only be paid by the revenues of the plant, if its capacity is higher than 200 kW, the load factor is at least 20 % (with an availability of 75 %) and at high electricity prices. This again fosters evidence that the small-sized plant between 100 -1'000 kW should be avoided.

Smaller plants than 100 kW show a drastic reduction of operation and maintenance cost by a factor averaging 4 -5. However, the tendency to overstaff also micro-hydro stations is a problem. It also seems that the running-cost of a micro-hydro plant cannot easily be covered by simply selling electricity at a too high rate; the solution will rather be an adequate shaping of the tariff, in order to promote use of electricity to obtain a good load-factor.

A further element of the operation and maintenance cost is the depreciation of the plant. Again experts have calculated a weighted rate of depreciation, according to the different lifespans of the plant's parts like civil-work, generating-equipment etc. They suggest an annual depreciation rate of 4 % of the initial investment. Usually this determines such a high price per kWh in the range of up to US {1 for depreciation alone that a serious problem is posed. Form an economic point of view one has to take a firm stand regarding depreciation. As long as the perpetuum mobile is not invented there is no such thing that does not depreciate. If depreciation of the plant cannot be paid, then the country's development budget or foreign agencies must replace the whole installation, after the wearing out of the plant. If depreciation can be paid, two ways are conceivable: A loan can be repaid step by step thus diminishing capital-cost of the plant, and proportionally increasing the new debt-potential for the new plant, or, internal reserves are accumulated, so that the total replacement of the plant can be paid with proper financial means.

In most cases a subsidy to the plant will be inevitable, be it for private or public hydropower investment. No one would ever question the fact either that schools, streets and other public services have to be depreciated at the public ' expense. However, to what extent costs are covered, is entirely determined by the revenues, a question that will be dealt with in the following chapter.

b) Experience with Tangible Internal Benefits

Information thereof will focus on the prices -and tariff - situation whereas "surplus revenues" and the "IER" are not elaborated at length.

"Baliguian" in a very remote place in the Philippines, is an example of locally designed and locally built equipment (Welded Francis turbine). With a head of 27 meters, and an installed capacity of 100 kW, the hydropower plant caused total cost of $ 749 per kW (excluding distribution cost), of which hardly 40 % for the generating equipment ($ 287). Producing 437'500 kWh per year - implying a load factor of close to 50 % -the selling price is an amazingly low US-cents 2.1 per kWh (calculated from data in: Dumol, Mini-Hydro Application, p 31 Looking at investment cost, it appears that capital interest and depreciation are not accounted for). Other small and micro-hydro installations in the Philippines sell at higher prices:

Installation

US-cents per kWh

-Magat A & B with 2'800 kW capacity

4.7

-Agua Grande with 2'750 kW capacity

5.2

-Hasaan with 30 kW capacity

5.3

The third example may demonstrate once more that a micro capacity is by no means in itself a guarantee for a low total investment and selling price. There are so many variables which finally determine the economy of a plant, that relying too much on the cost element of the generating equipment, can be a misleading yardstick.

The East-African power plants mentioned earlier, sold at rates per kWh between US ¢ 13 and 18 in 1966, a not so attractive offer considering the fact that European electricity producers calculate today with a price of US 3.5 per kWh to cover cost and depreciate the plant within 10 years (see Integration GmbH, Laufwasserenergie, p 55). At US 4 2.0 per kWh the depreciation is stretched over 20 years.

Back to China -a country with a lot of experience on small hydropower plants -more comforting evidence is available. It is said that micro-hydro plants sell cheaper electricity than larger plants; in case of higher investment-cost per installed kW in small plants, this is by far offset by the high transmission costs of larger plants. For the Xinhui county, a price of US 5 per kWh is indicated for small hydel stations and US ¢ 8.4 per kWh for grid-electricity (1979). It is certainly true that kWh-prices in developing countries often turn out to be higher than in industrialised countries; but the cost of alternative energy sources often are even higher, or -if lower as in the case of wood - have intangible costs which are unmeasurable. At this point, one should simply remember the question of energy-source selection from a thermodynamic standpoint. From this angle, cooking with electricity for example, would energetically be a luxurious undertaking.

Uneconomical and thus unwanted uses of generated power can be controlled by shaping the tariff accordingly. Any electricity supply company has to deliver electrical energy at the moment of production. Due to the fact that electrical energy is not storeable, an electricity supplier has to charge for two services: for keeping a certain amount of generation equipment ready (which is a typical public utility duty), and for the actual supply of energy per period of account. There results a two-part tariff, one part for the power-capacity, the other part for energy consumption. For hydropower plants with relatively high capital investment and low running cost (no fuel-cost), this means high capacity and low energy charges, whereas thermal generation induces moderate capacity and high energy charges. The two-part tariff however requires the metering of the individual energy-consumption, as well as the consumers peak demand. If upto 90 % of total consumption is by small consumers, this is simply too expensive.

An alternative method is based on the assumption that the power requirements of a domestic consumer correspond to the number of rooms or bulbs etc. he possesses. The tariff applied is then a maximum-demand equivalent charge per room or per electrical device. Metering is not anymore necessary. The method is called the flat rate per unit installed. This tariff does in fact -though in a very simple way - also take into account the two part cost structure of an electric energy supplier: when the electric device is switched on, the flatrate charged to the consumer pays for energy consumption; when it is turned off, the flat-rate pays for capacity installed. The rate is in both cases the same. The negative aspect of the flat rate is of course that it induces consumers to have the electrical devices on as much as possible, instead of saving energy. However in the case of hydropower, this aspect should be looked at from another angle: the price per kWh can only decrease, when the generating equipment is utilised to the largest possible extent. The electric energy supplier is therefore interested in having a high load factor. The flat-rate tariff is in fact a consumption-inducing tariff.

Another, also consumption-inducing tariff and thus load-improving method is to price the supply in blocks at a decreasing rate, e.g.

-the first 1'000 units at 10 US ¢ per kWh
-the next 2'000 at 8 U ¢ per kwH
-all additional units at 6 US ¢ per kWh.

The method increases the load factor and lowers the average price per unit of energy. This can also be combined with an off-peak tariff, thus flattening out uneven capacity use. However, both measures favour the larger consumers.

Finally, a fourth method should be mentioned: the tariff of the social untility-principle. To every use a different use-value is attached, expressing the users' appreciation of the different services rendered by electricity . For example, lighting receives a high use-value, whereas the energy-input into workshop machinery will be rated lower for reasons of its productivity. To further exemplify: The "Mel river" power plant in China charges the following rates:

type of consumer

US ¢ per kWh

-Industry

1.2

-Domestic

2.1

-Irrigation and pumping

0.6


The "Gu Don Mountain" power plant in China puts the social utility weight differently. It looks at industry as the most solvent partner, since precisely industry -by means of electricity - is enabled to attain surplus revenues, and is therefore charged most, the domestic-sector second-most, but hardly anything for irrigation and pumping (though surplus revenue will be generated in agriculture in the first place).

Consequently, the tariff helps determining many things like the load factor and thus the average price per kWh, the peaks and off-peaks in consumption and the socially wanted distribution of the generating costs, by differentiating the tariff according to end-uses. But all in all, the tariff will have to provide an acceptable IER to the producing organisation.

c) Experience with Tangible External Costs and Benefits

As to external costs, some data will be given here specifically focusing on H.T.-grids as the most crucial factor, whereas state subsidies and foreign-exchange costs are not further quantified.

If one looks at the Brasilian hydroenergy potential of 209'000 MW -14 % of it which is utilised only - the energy problem of this country seems to be solved. This "global" optimism is an illusion however, because the distances from the sites of hydropotential to the main consumer points are enourmously long. And so are the implied costs of H.T.-lines.

Considering a transmission-line of 10 kV, the Chinese indicate cost per km of $ 5'500.-to 6'500.-. Very similar costs are budgeted for a H.T.-line of 7 km length, including transformation to 6 kV in Nepal, with $ 6'250.- per km (1977).65) The World Bank stated in 1975 that extending a subtransmission link 25 km to an isolated demand point, may cost around $ 100'000, thus amounting to $ 4'000 per km.66) Inflation will bring it close to the above-mentioned $ 6'000.- per km. In Tanzania* a typical price for a 33 kV line is approx. $ 8'430.-per km.67) A rough average -at costs of today -is therefore approx. 7'000 $/km. This is valid only in the small-hydro range.

Some analyses have been done of a comparison between public supplies from the main grid and micro-hydro stations.68) For micro-hydro -serving local consumers and public lighting - an installed capacity of 80 kW was considered, and public supplies from the grid was assumed to be of medium-voltage of 33 kV as subtransmission link to the local L.T.-line. The capital costs of supplies from the grid are much higher than those of micro-hydro generation, but are of course depending on the distance from the nearest grid. The crucial point however, is this: the higher the utilisation of the energy-project, the better off is the supply from the public grid, since its fixed transmission costs result in a decreasing unit-cost, if the load-factor increases. This is illustrated in fig. 78, where unit-cost is given for different situations. At a low level of utilisation, public supplies from the grid are too expensive because it is extravagant to extend so expensive networks at $ 7'000.-per km, to meet small demands in areas remote from the grid. Microhydro thus is better off, provided that its local consumers are not too remote either from the power plant, since -as shown earlier - L.T. lines are technically restricted to a relatively small radius of some kilometers at the most. As soon as it comes to transformation and H.T.-lines, micro-hydro tends also to run into high costs.

When the socio-economic uplift of the village has increased energy-consumption, the marginal internal cost of expanding micro-hydro generation, will have to be compared with the external cost of integrating the village into the main grid. Again the Chinese have even applied a combination, by using small hydro up to its capacity-maximum (maximising the load factor) and supplementing peak-demand by public supplies from regional grids.


Fig. 78:Average Costs of Different Schemes, US $ per kWh

Source: World Bank, Rural Electrification, p 21, micro-hydro figures are calculated on the basis of project data from Nepal

Some brief remarks should be added to the tangible external benefits. Whether tax revenues will rise depends on surplus revenues generated by the higher energy input into production, be it agricultural or industrial. Product diversification and possible price decreases cannot be generalised here. Similarly, the question of subsidies must be looked at from case to case; it is conceivable that subsidies for imported kerosene will turn into subsidies for depreciation of a micro-hydro plant. But it might as well be that subsidies increase, but can be activated in terms of accounting, through local build-up of innovation-centres, more local employment, less expenditures on the trade-balance of the country, etc. It is especially the import bill, which could substantially be affected by implementing micro-hydro plants.

Most of the civil work will be entrusted to local engineering firms thus accounting for 30 -50 % of the total cost. One has of course to safeguard against the tendency of importing steel, cement etc. used in too elaborate construction. As to the mechanical and electrical components, what is possible by local means has been elaborated in chapter D at length.

d) Experience with Intangible Costs and Benefits

As indicated earlier this third-level assessment is the most difficult one. The problem will be demonstrated by means of few examples without aiming at a comprehensive description.

Measuring the very long-term discharge of a river over 10 -40 years can be a cost which nobody really considered. The tropical and subtropical zones have instable climatic features which can play costly tricks on a hydropower plant. The intangible cost of not having correctly assessed the hydro-potential of a chosen site, will suddendly turn into very tangible costs once the water discharge is substantially lower in a dry year. In China the general reliability of micro-hydro plants is rated lower than the one of large power stations. Severe droughts periodically plaguing large areas of China can incapacitate small stations quite rapidly.69) Therefore an intangible cost can consist in the interruptions of energy supply from small power stations, causing some disorder and planning problems to the economic life of a village. But experts working with micro-plants insist that -if capacity is based on minimum-flow rather than a power plant capacity aiming at optimum-utilisation of flow - such incidents are seldom and when they occur, the harm done is not so dramatic.

Certainly one does also have to consider some socio-cultural impacts of a new energy-source like electricity. Examples are: smoke from open fires in houses projects inmates from flies and insects; electrical appliances do not. A fire also heats a house, an electrical cooker does so much less; the fire offers light in the mornings and evenings and provides a natural center for social life, whereas electrical appliances do not substitute for these functions.

On the intangible benefit-side in the first place one has to evaluate the immense "mobilisation-effect" of rural electrification, all the development thrust which can be generated in a small community that makes suddenly power available for irrigation and drainage, for primary processing tasks such as grain treshing and milling, fodder crushing, oil extraction, timber sawing etc., truly the first steps towards sensible modernisation in remote, poor communities. What counts are not only the tangible external benefits (surplus revenues) of the above-mentioned activities, but above all -intangibly -the motivations, the attitude and the drive towards "being able to do something" against poverty.

3. MICRO-HYDRO PLANTS AND OTHER ALTERNATIVES

a) General Remarks

The following sections compare alternative energies basically using again the criteria of the multilevel-cost-benefit approach. However, the application of this system will be more eclectical than in section F2. The evaluation will concentrate on costs of installed capacity and user-prices per kWh, surrounded by other tangibles and intangibles.

A fist rough impression of relative costs (cost-relation) among energy alternatives is given in fig. 79.


Fig. 79: Comparative Costs of Electricity Generation from various Fuels in 1980 $

Source: World Bank, Energy in the ..., p 43

* including costs of transmission and distribution

** intermittent energy sources requiring storage to make energy available on demand at all times; investment cost given include storage costs.

*** hydropower plants are assumed to operate at a load factor of 5'000 hours per year, coal-units on a base load of 7'000 hours per year.

The diesel-powered generator and the oil-fired steam engine both depend on increasing fuel-costs, thus falling out of competition in the long run. The coal-fired steam engine also will have to face price-increases; beside this, the attractive cost per kWh of only 5.2 US' stems from a load factor 40 % higher for coal (80 %) than for the hydropower station (57 %). Wood, wind and solar conversion seem to eliminate themselves for price reasons.

The following sections will deal very briefly with alternative energy-sources individually, in relation to hydro-power, in order to check the so far outlined relative cost situation.

b) Oil fuels

From a "model-calculation" for two 40 kW-plants, one hydro-electric and the other diesel-electric, the cost-functions as shown in fig. 80 have been derived.


Fig. 80: Total Operating Cost and Unit Cost against Power Generated Capacity/Utilisation for 40 kW Diesel and Hydro-Electric Installations

Source: Wright, Micro-Hydro Installations

The key characteristics of investment costs are: hydropower has twice as much costs as the diesel, especially because of much higher civil-work costs and transmission-costs since a diesel-set can be put right in the centre of a consuming point. As to the operation-costs: the diesel has much higher depreciation-costs because of a three-times shorter lifespan, higher maintenance costs, and above all high variable fuel costs. The main results of the comparison are: total operation costs are equal for the systems at about 10 % capacity utilisation, but at 40 % capacity utilisation, diesel is twice as expensive.

Another example from the Philippines is also instructive. The National Electrification Administration plans 239 hydropower stations with a total capacity of 305 MW until 1987,71) an average capacity thus of 1'276 kW. The total cost is supposed to be 4 billion pesos or $ 533 million. On average, 1 kW installed capacity amounts to $ 1'748. The total generating capacity to be installed is the equivalent of a medium sized thermal generating plant, which would consume about 2,3 million barrels of oil at a capacity use of 5000 hours per year. At costs fo $ 35.-per barrel of oil equivalent, yearly fuel costs would amount to 80.5 million $, or 5.3 ¢ US per kWh, in addition to 2,4 ¢ per kWh for capital interest and depreciation. Excluding maintenance and other costs in both cases, 7.7 ¢/kW for the thermal plant compares to 5.2 ¢/kWh for the hydropower plants.

The advantage of such a thermal power plant would be that the initial capital required is lower by 289 million $, when compared to the hydropower alternative. Future costs of fuel, amounting to 80.5 million $ per year, have to be discounted as explained in section F1 (p 114 f.), to get a true picture. Thus, assuming 10 % interest, fuel costs over 5 years will amount to 305 million $, expressed in today's-value of money. From the sixth year onwards, all money spent for fuel in the case of the thermal plant, is equal to a net-saving in the case of the hydropower plants envisaged. Not considering here possible increases of the fuel price, the shorter life of a thermal plant, and other factors, the total amount saved over the life period of 30 years of the hydropower plants, amounts to 470 million $ -expressed again in today's value of money -when compared to thermal plant operation over the same period.

It remains to be said that micro-hydro installations have many external and intangible benefits not inherent to diesel. It starts with the import costs of diesel-sets ranging from $ 600 to 850 per kW. Hydropower plants in contrast will provide a lot of local employment and improvement of human capital. By any criteria like environment, maintenance, lifespan etc. the hydropower plant is favourable, unless there is no water.

c) Wood and Dung

Cost comparisons between hydropower and wood/dung are difficult and do not make much sense. Difficulties arise because only a minority of people in developing countries really buy wood; for an Indian village, 4 % is an example.72) All others cut the wood at no private cost, at quantities of up to 0,6 tonnes/year per capita. Those who buy wood, get it at prices which are -despite the fuel-wood crisis -much lower than kWh-charges from hydroplants. For Nepal it is indicated that one can acquire 1 kWhth for less than 1 US ¢. No electric supply company can compete with this price. The comparison, on the other hand, does not make much sense because wood simply is no longer an alternative. The worldwide deforestation rate calls for an immediate campaign of conservation of wood and for a massive planting of fuelwood supplies. But as long as wood is free of cost to the user, and as long as controls over the cutting of wood are ineffective, there are few incentives to plant energy-forests.

A similar problem is posed with dung. Up to 1 billion people use it to fuel their cooking fires. The amount of dung now being burned annually, is believed to be equivalent to some 2 million tons of nitrogen and phosphorous. 73) The problem is that neither hydro-electric energy can compete economically with wood and dung - even if its price per kWh were a fraction of a US cent -nor does this mean that wood and dung are an economically better solution than hydroelectric power.

In the overall context, only processes in which the fertiliser-value of dung is preserved are feasible propositions and, in the case of power generation from wood, it appears that - in most regions of the world -only planned energy-forests could justify this. The latter, however, have long gestation periods, and there seems not to be any experience available that would permit a comparison with hydropower.

d) Biogas

Biogas will be evaluated in two steps: firstly, the economy of biogas as end-use energy-source is analysed, and secondly, the biogas conversion into electric-energy is compared to hydro-electric energy.

For the first consideration, a typical family size biogas plant in India is taken. Operating costs of such a plant are shown in fig. 81.

Fig. 81: Total Operating Costs of Family-Size Biogas Plant

Source: French, Renewable Energy ... with own adjustments 6 supplements

Item

Cost-Base

Annual operating cost

plant

375.- total investment

31,25 *

feeding/removing of plant

114.- annual labour cost

57. - **

Maintenance of plant


12,50

capital cost (15 %)


28,15

Total


128,90

* estimated lifeperiod: 12 years

** The plant needs daily 175 pounds of dung and water each; 350 pounds of slurry must be removed daily. It is assumed that after deducting the time formerly spent to collect other fuels, still new labour of 4 hours per day is needed to gather water, to feed and maintain the system, and to unload and distribute the slurry. Annual labour costs amount to $ 114.-- for the Indian case. Considering the fact that much of the labour will be provided by family members, half of the labour cost is taken into account.

The tangible internal benefits of the plant result from a daily production of 3 m³ of gas, enough to meet the daily basic energy needs of an Indian family of five to six people. 20 % will be used for home lighting, 80 % for cooking and heating. The gas production corresponds to 16'800 kcal per day or 19.5 kWh per day on a calorific basis. Assuming a capacity rate of the plant of 70 %

Formerly used energy sources (kerosene, coal) of a comparable calorific amount is said to cost $ 90.-, thus rendering the biogas uneconomical, not accounting here for the intangible benefits (anticipating future oil price increases, protection of forests etc.). One might argue that the biogas economy is quickly uplifted when family work is valued differently and the capacity rate is increased. The break-even point can thus be reached when labour costs in fig. 81 are further reduced by 30 % to $ 40.-per year and the plants' utilisation rate is increased from 70 % to approx. 85 %.

But there are more intangible costs to consider. Firstly: the plant needs daily dung from 3 -4 cows; less than 50 % of Indian cattle-owners have this many head of cattle. Secondly: the very substantial amount of labour required by the plant should be seen as opportunity costs of alternative activities, having a higher return than the operation of the biogas plant. This is one of the very important advantages of the low labour-intensive operation of hydropower plants. Thirdly: About 80 liters of water daily per plant, to be mixed with dung (no second use of the water is possible), is a severe constraint in dry regions.

The second step is to compare biogas converted into electric energy with micro-hydro electricity. Projected costs of electricity-generation from biogas are shown in fig. 82, taking the same family-size plant as a basis. A larger plant would benefit from pronounced economies of scale but has not been considered here because of very limited experience with large plants. Nevertheless, with unit costs of electricity, that are 4 to 8 times higher for a small biogas unit, compared to micro-hydro -it is possible to state that there is no economic feasibility of electric energy from biogas, when hydro-electric energy is an alternative. Even if the biogas plant produced at 100 % (7'120 kWh of biogas), the conversion rate were practically doubled (30 %, giving 2'136 kWh of electric power) and the annual cost of the conversion equipment were half ($ 97.50) the cost would still be close to US ¢ 11 per kWh of electric power.

The conclusion is that biogas must be used for those tasks which thermodynamically match the biogas properties. Biogas as a rule is more economical than electrical power for cooking, but it will already be difficult to compete with micro-hydro installations when it comes to mechanical power, because of the very high labour costs of the biogas plant operation. Finally, biogas is completely out of the acceptable cost-range when electric power supply is desired. The few biogas advantages still dwindle further when one applies a development concept oriented toward the majority of a village population, since only few people possess the necessary cattle. Community plants on the other hand will increase costs very much because of management, gas distribution networks, transportation of enormous quantities of water, skilled technicians to run a large plant etc.76) The overall outlook for biogas therefore, is rather bleak in rural electrification.

Fig. 82: Cost-Comparison of Electric Power from Biogas versus Micro-Hydropower

Total annual biogas production at a capacity rate of 70 %


5'000 kWhth

(256 days x 3 m³ x 6.5 kwh)






Conversion into electric power


800 kWhe

(16 % efficiency)






Annual costs of electric power from biogas:



-cost of biogas production

$ 128.90


-cost of conversion equipment*

$ 195.--

$ 324.--




Cost per kWh of electric power from biogas


US ¢ 40.--




Cost per kWh of electric power from micro-hydro


US ¢ 5-10

* annual operating cost:

Investment

Annual operation cost


Engine $ 200.--

$ 33 (lifespan 6 years)


Generator (1 kW)



$ 400.--

$ 67 (lifespan 6 years)


Maintenance

$ 50


Capital costs (15 % 7

$ 45


total

$ 195

e) Liquefied Biomass

The production of methanol is not considered here as potential substitute for micro-hydropower because the production basis is naphta, residual oil and natural-gas. The end-user price ranges from $ 25.-to 45.-per barrel of oil equivalent, depending on the price of the natural gas feedstock and the size of the production plant. Of more interest is the production of alcohol in the form of ethanol (ethyl-alcohol) from biomass.

Economically, experts agree that ethanol is nowadays a too costly substitute; though very large plants are designed (350 barrels oil equivalent a day), costs are in the range of $ 10 -20 million and require about 5'000 - 6'000 hectare of sugarcane annually. Today, the unit cost of ethanol is substantially higher than that of kerosene, with the decisive cost-factor being the price of sugarcane or other feedstock. It might at the most be a partial solution for Brasil (having large land reserves) or Kenya and Mali which have large surplus molasses from existing sugar production. For the majority of countries, however another problem than the unit-cost is relevant: ethanol from sugarcane plantations needs good agricultural land suitable for food grain production, in contrast to the fuel-wood forests which can grow on non-agricultural land.

f) Solar and Wind Power

Along with hydropower, the direct use of sun and wind power are two more truly renewable energy sources. The potentials are impressing, at least theoretically. The solar radiation can provide an energy flow up to 1.6 million kcal per m² annually. Thus, the 1970 total electricity generation of China -60 million MWh -is equal to the solar flux received annually by less than 40 km² of northern China.

Yet many technical obstacles of solar energy conversion into electricity make it very expensive. Irregular flow of radiation (seasonal and random fluctuations) and its diffusion before reaching the surface make a wide commercial application very unlikely within this century.

Electricity from photovoltaic cells, which convert solar energy directly into electricity, costs on the order of $ 2 per kWh. The widely published forecasts that the price will come down rather quickly, conceal the fact that complementary equipment - above all battery-systems -still remain a very important cost-factor. Solar power for low-lift, small farm-irrigation, for village water supply pumping and village electrification are simply out of the economic range compared to micro-hydropower; the advantage of hydro becomes greater, moreover' in proportion to the load factor of the hydro-plant. Nonetheless, in areas where there is no hydropotential, small photovoltaic pumping systems without storage batteries are likely to become a sound possibility. Other uses like water heating, desalination, and crop drying with simple solar equipment, are economically more viable.

Wind energy also has a marked seasonality in many cases. The economically very central problem of storage (batteries), arises again. However the economic feasibility of wind energy seems to be closer to hydropower than the solar option. With a cost of over $ 5'000 per kW installed capacity it is still indisputably more expensive than a micro-hydro installation.

It might be concluded from all these considerations, that micro-hydropower generation will not solve the energy problem of developing countries, but that it can play a very significant role in conjunction with de-centralised patterns of development, providing mechanical and electrical power at lower prices than other alternatives, inducing local employment and technical activities without prejudicing future energy-systems of a larger type, to which local distribution networks can be linked.

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