the potential for alternative private supply (aps) of power in … · 2020-07-07 · nyangani...

JUNE 2014

The Potential for Alternative Private Supply (APS) of Power in Developing Countries

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THE POTENTIAL FOR ALTERNATIVE PRIVATE

SUPPLY (APS) OF POWER IN DEVELOPING COUNTRIES

Final Report

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Acknowledgments

This report was developed by the Investment Climate Department of the World Bank Group. It was written by Economic Consulting Associates, UK, under the direction of Vyjayanti Desai and Alejandro Moreno with the support of Maria Fyodorova, all with the Investment Climate Department. The team is grateful for comments and insights provided by Mohua Mukherjee, Pepukaye Bardouille, Alexios Pantelias, Efstratios Tavoulerias, Katharina Gassner, Stephane Barbeau, Carolina Dominguez Torres. The report was edited by Lise Lingo of Publications Professionals, LLC.

Many thanks go to the following people who contributed to this report:

United Kingdom

Peter Lundy

Paul Lewington, Director, Economic Consulting Associates

Andrew Tipping, Senior Economist, Economic Consulting Associates

Eleni Adamopoulou, Economist, Economic Consulting Associates

Ray Tomkins, Director, Economic Consulting Associates

Peter Robinson, Director, Economic Consulting Associates

William Derbyshire, Director, Economic Consulting Associates

Richard Bramley, Senior Economist, Economic Consulting Associates

Sri Lanka

Tilak Siyambalapitiya, Partner, Resource Management Associates (Pvt) Ltd

Harsha Wickramasinghe, Deputy Director General (Operations), Sri Lanka Sustainable Energy Authority

S.H. Padmadewa Samaranayake, Sri Lanka Sustainable Energy Authority

Kamal Dorabawila, Principal Investment Officer, IFC

Zimbabwe

Mike Gratwicke, Rift Valley Energy

Ian McKersie, Managing Director, Nyangani Renewable Energy (Pvt) Ltd.

Lasten Mika, Practical Action

Sweden

Pär Almqvist, Chief Marketing Officer, OMC Power

India

Major Neil Castelino, Deputy Director and Head, Confederation of Indian Industry—Pune Zone

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Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

Key Findings from APS Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii

Key Findings from Analysis of Mobile Telephony Drivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix

1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1.1 Definition of APS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1.2 Categorization of APS Schemes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1.3 Selection of Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

1.4 Layout of the Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

2 Approach to Cost-Benefit Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

3 Captive Power and P2P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

3.1 Economic and Financial Drivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

3.2 Approach to Cost-Benefit Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

3.3 Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

3.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

4 Mini-grids and Small Power Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

4.1 Economic Drivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19


4.3 Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

4.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

5 Coordinated Supply of Individual Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

5.1 Economic and Financial Drivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35


5.3 Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

5.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

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vi The Potential for Alternative Private Supply (APS) of Power in Developing Countries

6 Mobile Telephony Lessons for APS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

6.1 Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

6.2 Increased Functionality and Productive Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

6.3 Technical Characteristics and Cost Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

6.4 Business Models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

6.5 Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

6.6 Parallels with APS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

6.7 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

7 Key Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

A1 Empirical Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Harvard University and Center for Information Policy Research . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

GSMA—Comparison of Fixed and Mobile Cost Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

UN—World Institute for Development Economics Research . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

International Telecommunication Union (ITU) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

World Bank—Development Research Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

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Executive Summary

IntroductionEconomic growth in low-income countries is often hindered by unreliable, low-quality electricity supply and central power grids that fail to reach large shares of the population. The power sector is often dominated by the state, with a single company providing all power services from generation to transmission and distribution to retail sales.

Although opportunities for private investment in generation facilities are increasing, most low-income countries—and many middle-income ones—still strictly limit participation by the private sector in the retail supply and sale of power. Yet the private sector can play a significant role in providing alternative sources of generation (referred to as “alternative private supply of power,” or APS) when traditional utilities prove unable to meet demand. APS projects are typically small in scale and decentralized, distinguishing them from private utilities in fully competitive markets. Nonetheless, for a limited set of customers they disrupt the role of utilities in the retail sale of electricity.1

Some countries view small private power operators in a negative light.2 Because they are typically small and do not leverage the economies of scale of an established utility, APS projects are often assumed by policymakers to be an economically inefficient approach to electrification. There may be an assumption that power from APS projects is too expensive, unreliable, or low-quality. In addition, there may be a fear that certain types of projects will reduce utility revenue by selectively targeting the most profitable customers.

However, APS models may offer a quicker and easier way to scale up power services in countries that have significant power deficits. They may provide a way to encourage fuel diversity and may increase the penetration of cost-competitive renewable energy technologies. APS projects are limited in scope, directly address supply shortages, and require only a small number of targeted policies or regulations.

1 Industrial captive power plants that sell surplus power to the grid share many of the characteristics of traditional small power producers, but they are considered APS for the purposes of this study as they replace the generating fi rm’s purchases of power from the grid.

2 Opportunities and Challenges for Small Scale Private Service Providers in Electricity and Water Supply Evidence from Bangladesh, Cambodia, Kenya, and the Philippines, World Bank/PPIAF, 2009, p. 2.

The World Bank Group’s Investment Climate Department commissioned this report from Economic Consulting Associates to assess the value and financial viability of the most common forms of APS in developing countries, through a series of case studies in South and East Asia and in Africa. In addition, the report analyzes the technical, regulatory, and economic drivers of the mobile phone revolution in developing countries in order to assess whether any APS models have the potential for similar scaling and replication.

MethodologyThe report addresses two main questions:

1. In what circumstances can APS models be part of the optimal long-term power supply for a country, and when can they be an effective second-best solution? Can they be economically viable without (operational) subsidies?

2. To what extent could APS models replicate the success of mobile telephony and provide a widespread solution to the energy challenges facing developing countries? What technical, regulatory, and economic characteristics and approaches allowed mobile telephony to succeed in developing countries, and which can be replicated in the power sector?

The report assesses five APS models:

1. Captive power or larger commercial/industrial self-generation, with surplus power sold off-site (excluding self-generation purely for backup power)

2. Private-to-private (P2P) sales through wheeling arrangements or a dedicated connection with one or more off-takers

3. Mini-grids, in which electricity is generated and sold by a privately owned or operated distribution network to residential and/or commercial end users or cooperatives

4. Small power distribution (SPD) systems, in which individuals, cooperatives, or private companies purchase power at wholesale prices from the grid and distribute it through a privately owned or operated distribution network

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viii The Potential for Alternative Private Supply (APS) of Power in Developing Countries

5. Coordinated supply of individual power generation or storage units (such as rooftop photovoltaic systems or rental of batteries or power boxes) on a small scale for self-consumption

The report presents the assessment of the five APS models in three groups, according to the type of electricity supply activity:

• Captive power and P2P require a conventional grid and compete with conventional sources of electricity generation.

• Mini-grids and SPD systems are small networks that in most cases supply electricity to rural villages. Isolated mini-grids also have their own sources of generation.

• Coordinated supply of individual power generationmodels generate electricity directly for users without the use of a network.

Case Studies and Cost-Benefi t Analysis

The team analyzed 16 case studies across 10 countries through a combination of country visits and desk research. Owing to the high concentration of different types of APS projects being implemented in India and Sri Lanka, these two countries contributed a large share of the case studies. For each case study, the report compares the costs and benefits of existing APS projects with appropriate counterfactuals (that is, what would exist in the absence of the APS project). In cases where a grid is accessible, a grid connection may be the appropriate counterfactual; in other cases, the counterfactual may be kerosene lighting. One model of APS may be a counterfactual for another (for example, mini-grids, SPD systems, and conventional grid connections could be counterfactuals of each other). In the case of grid connection, the report notes whether the counterfactual is the actual (unreliable) grid network as it is or the theoretical, optimal grid.

The cost-benefit analyses look at APS project development from the perspectives of the developer, the consumer, the utility, and the national government. A key aspect of these analyses is the review of situations in which tariffs do not reflect costs. The economic (national) perspective also identifies costs and benefits that are not monetized, including health, environmental, social, and indirect economic development benefits, but does not quantify them.

Analysis of Mobile Telephony Drivers

The assessment reviews empirical studies of the drivers of mobile telephony in developing countries: falling prices; technical characteristics (compared with those of fixed

lines), including the structure of costs; business models and payment plans and how they differ from those used for fixed-line telephony; functionality; and policies to promote competition. For each APS model, the report identifies potential similarities or parallels with characteristics that were critical to mobile telephony’s success and the potential for scaling up in a similar fashion.

Key Findings from APS Case StudiesThree key themes run through all of the case studies:

• Despite their limited size, any APS model can be the most cost-effective or economically valuable approach to supplying power. However, different APS models address different weaknesses in the utility system and are appropriate solutions only under the right sets of circumstances.

• APS models need not be the theoretically optimal solution in order to be a rational, cost-effective way to address issues of limited power access or reliability. Most APS projects are implemented specifically in response to chronic failures of an existing utility structure, in situations where the ideal solution—the extension of the existing grid to remote communities, for example, or the development of sufficient generation capacity to avoid power outages—has been promised for decades but never delivered. In these cases, alternative systems need only be more cost-effective or provide more value than the existing energy supply and consumption patterns in order to be the best short- to medium-term solution in a particular area. In the right circumstances, APS models can be economically viable without ongoing external subsidies.

• Direct P2P sales and some captive power plants (CPPs) are likely to be financially viable on a purely commercial basis, whereas mini-grids and the coordinated supply of individual power units are likely to require at least some initial subsidy or financial support.

Some model-specific findings from the case studies are summarized in the next four subsections.

Captive Power and P2P

The captive power and P2P case studies show that these APS models can be optimal in their own right, in particular when driven by advantageous access to fuel sources and/or cogeneration. Examples include a biomass-fueled CPP for a cement factory and a bagasse-fueled CPP for a sugar factory, both in Sri Lanka.

Even if not theoretically optimal, captive power and P2P can also provide the quasi-best solution where power

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shortages are chronic. In Pune, Maharashtra (India), a scheme for buying surplus power from underutilized CPPs owned by industrial firms allowed the city to avoid power cuts. In Zimbabwe, independent private power plants—although more expensive than the main grid supply—supply specific customers who are willing to pay higher tariffs.

The case studies also show that distortions can encourage captive power or P2P for reasons that conflict with national interest or policy objectives. This is particularly true of electricity pricing, where there are large cross-subsidies from one group of users (often commercial and industrial) to another group (residential). India’s Electricity Act of 2003 promoted open access and P2P, including specialist companies like Tata Power Trading Company. Because cross-subsidies from industrial consumers to residential ones were retained, P2P became an attractive way for industrial consumers to avoid paying them. To eliminate this problem, the government introduced a cross-subsidy surcharge.

Mini-grids

Mini-grids can be the optimal solution under certain circumstances. Those circumstances include the distance from an existing grid; the cost of electricity from the grid; the community’s income level (which often rises over time); whether the community is scattered or concentrated; the availability of hydro, solar, or other sources of energy; the real cost of kerosene and/or diesel (which varies over time), and other such factors.

Cambodia provides a good example of a successful mini-grid program where the mini-grids were developed privately, without significant government intervention. The private developers were able to charge high but cost-reflective tariffs, allowing them to operate sustainably. However, in Africa, mini-grids have generally been successful only when provided with large capital subsidies and often direct or indirect operating subsidies. Low affordability, low consumption levels, and high costs per kilowatt (kW) or kilowatt hour (kWh) are the main constraints and the reasons that many have failed. Others may have failed because communities served by mini-grids successfully lobby for ceilings on the tariffs to match the (subsidized) prices charged by the main grid company or because the community is unwilling to pay higher tariffs than those charged by the main grid company. The best (or quasi-best) solution in these circumstances is more likely to be distributed solar products. It cannot be concluded that mini-grids are always the wrong solution in Africa; they will certainly be best for communities more distant from existing grids, with good energy resources, with reasonable

levels of economic activity, and where households and other users are not scattered over large areas.

SPD Systems

Only one case study of SPD systems is provided, for Cambodia. The key characteristic that distinguishes an SPD system from a conventional distribution grid is that it is privately developed, owned, and managed. Unlike a mini-grid, it relies on the main grid as the primary source of power. Its utility as a solution therefore relates more to the efficiency of a private developer/owner/operator compared with the efficiency of a conventional utility. Whether this solution is optimal cannot easily be judged through a high-level case study, but the case studies do illustrate situations in which SPD systems can be a good way to achieve electrification goals when conventional utility-based electrification is not available. This was the case in Cambodia, where the main utility did not have the resources to finance rural electrification. Even if the utility’s resources had not been constrained, an SPD system may have been the most effective way to achieve rapid electrification.

Coordinated Supply of Individual Power Generation

Like mini-grids, solar photovoltaic (PV) and other distributed solar products can be the optimal solution in the right circumstances. The case study of OMC Power in Uttar Pradesh, India, describes an interesting rental model for small-scale appliances, using batteries collected from and delivered to customers’ doorsteps. This solution is optimal for small users, for whom a grid connection is not economically justifiable and for whom a dedicated solar home system with a commitment to pay a fixed monthly amount is often unaffordable. Case studies for Bangladesh and Mongolia show that distributed solar can be an optimal solution and that targeted subsidies may be effective in helping establish a local market for solar if the subsidies can be reduced over time.

Key Findings from Analysis of Mobile Telephony DriversThe widespread adoption of mobile telephones was driven in large part by pay-as-you-go business models, which allow consumers to control the timing and amount of expenditures. The cost structure of mobile telephony greatly facilitates pay-as-you-go models, as most fixed costs are associated with services that can be shifted easily from one customer to another (such as bandwidth). Because only minimal costs are specific to any individual customer, it is financially viable for operators to offer telephony services to low-income users who have low or infrequent consumption.

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x The Potential for Alternative Private Supply (APS) of Power in Developing Countries

The analysis had four key findings:

• The cost structure of mobile telephony, unlike that of other network services, has relatively low fixed and user-specific costs. In this context, fixed means capital costs incurred up front and recovered from users over time. Both mobile and fixed-line operators have fixed infrastructure costs that must be covered from phone charges, but the proportions of their costs that are fixed and customer specific differ. It is the combination of fixed and customer-specific costs that is important here. Once a fixed line is installed to a house, the capacity provided by that connection is not available for use by another user.3 In mobile telephony, by contrast, effectively only the handset is user specific. This favorable cost structure makes it financially viable for operators to use the prepaid/pay-as-you-go4 model to offer services to low-income users who have low monthly consumption.

• There is general consensus among empirical studies that the prepaid/pay-as-you-go charging option was a key driver of the mobile phone revolution in developing countries. For traditional fixed-line services, prepaid models may be technically feasible, but the cost structure requires monthly payments to make service

3 Costs may also be specifi c to a small group of users—for example, a small village. If some households do not use the capacity, others within that village can, but the capacity cannot be used by households in other villages. There is a progression of such types of infrastructure whose costs are fi xed and specifi c to individual users and increasingly large groups of users.

provision financially viable for the operators.5 The pay-as-you-go model is made commercially feasible from the mobile provider’s viewpoint by the cost structure of mobile telephony. For the mobile service operator, it means low revenue collection costs and low or zero credit risk. For the user, the cost structure gives control over expenditure. Despite higher unit costs, the pay-as-you-go model is much more attractive for low-income households in developing countries. But the model does not by itself overcome the challenging cost structure of fixed-line telephony.

• The call services provided by mobile phones are similar to those provided by fixed-line services, but there are important additional benefits from the simplest mobile telephony functions. These additional benefits appear to have a high productive value in developing countries by enabling telephony on the move; for example, by enabling farmers to share produce prices and coordinate transport of produce or people to markets in order to sell crops or buy seeds or tools.

• Competition is easier to achieve in mobile telephony, and competition helped drive down prices and encouraged innovation in developing countries. Empirical evidence suggests that it was a key driver for the high levels of mobile phone penetration.

5 Fixed-line operators may also adopt the pay-as-you-go model without fi xed monthly charges but not for reasons of commercial self-interest. They typically introduce such models because governments place social obligations on them to serve rural or peri-urban communities that could not otherwise afford access.

4 This report uses the terms “prepaid” and “pay-as-you-go” interchangeably. In practice, in developing countries, they are virtually identical. In developed countries, “prepaid” can refer to a system in which customers make monthly payments in advance through their bank accounts with a reconciliation at the year end. This model is not relevant to most users in developing countries.

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1

1 Introduction

1.1 Defi nition of APSAPS is defined as approaches to power supply in which distributed private operators replace or bypass the traditional utility model for part or all of the distribution or retail supply process. Five APS models are assessed in this report:

• Captive power, or larger commercial/industrial self-generation from which surplus power is sold off-site, including to the grid (that is, excluding pure self-generation for backup power)

• Private-to-private (P2P) sales through wheeling arrangements or a dedicated connection with one or more off-takers

• Mini-grids, in which a privately owned or operated distribution network generates and sells electricity to residential and/or commercial end users or cooperatives

• Small power distribution (SPD) systems, in which individuals, cooperatives, or private companies purchase power wholesale from the grid and distribute through a privately owned or operated distribution network

• The coordinated supply of smaller-scale power generation or storage units (such as rooftop PV or battery/power box rentals) for individual consumption6

“Private” is defined here as schemes in which a return on an equity investment is expected. Cooperatives with investors or subscribers who expect to receive a dividend are considered private but those with members who receive benefits only in kind (electricity supply) are not. However, as discussed in the next subsection, not-for-profit schemes, including cooperatives, may nonetheless be used as examples of the possibilities of APS.

In addition to being private, successful APS schemes should be economically sustainable, without ongoing operating subsidies. Schemes may rely on capital subsidies

6 The distinction between captive power and coordinated supply of individual power generation need not be defi ned precisely. Small-scale solar PV systems may be used by customers who do not use the grid. They may also be used by those connected to the grid, with any surplus “sold” to or “banked” with the utility using net metering. For this study, net metering has been included with coordinated supply.

initially, provided that they are sustainable and replicable in the future. They may also rely on carbon credits from the Clean Development Mechanism (CDM) or some reasonable subsidies from carbon funds that reflect externalities.

APS does not include private schemes in which the centralized grid is the only or majority buyer of power generated, such as large-scale independent power producers (IPPs) or renewable energy schemes selling to a central grid under feed-in tariff (FIT) arrangements. It does include schemes that depend on the existence of large-scale national transmission or distribution grids (P2P). APS can, however, include types of schemes that have existed for years, such as cogeneration, which produce electricity for their owners’ use and sell surplus to the grid.7

APS is not defined by the source of energy for power generation; that is, renewable energy is not a precondition. The focus is primarily on schemes that produce electricity rather than substitute for it (such as demand-side measures) or produce specific energy services (such as pico solar lighting). Solar home systems are considered APS because they produce electricity that can be used for non-specific purposes (such as phone charging, radios, and refrigeration).

1.2 Categorization of APS SchemesThe report clusters the five APS models in three groups according to the type of electricity supply activity:

• Captive power and P2P: These depend on the existence of a conventional grid and compete with conventional sources of electricity generation.

7 There are many modern examples of situations where cogeneration of electricity and heat/cooling/steam make private decentralized electricity generation attractive. Desalination using waste heat from power production can also make decentralized electricity generation attractive in some locations (for example, in resorts in Egypt). Many such schemes are fundamentally viable but need some regulatory intervention to correct market distortions, often by mandating the national utility to purchase surplus electricity from cogeneration plants. The United States introduced the Public Utility Regulatory Policies Act in 1978 for this purpose, and other countries have produced similar schemes since then (for example, Turkey introduced a similar law in 2003). More recently, more substantial electricity market reforms in a number of countries have made these decentralized schemes viable.

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2 The Potential for Alternative Private Supply (APS) of Power in Developing Countries

• Mini-grids and SPD systems: These deliver electricity to mostly rural villages using a network. Mini-grids also have their own source of generation.

• Coordinated supply of individual power generation: These generate electricity directly for users without the use of a network.

Each group has different drivers and presents different issues.

1.3 Selection of Case StudiesThe initial intent was to select a small number of countries to visit and examine in order to identify the benefits and negative consequences of the various APS models in each. Fifteen countries were considered as potential sources of case studies; others were considered but rejected. A preliminary assessment of the selected countries identified very few successful APS projects in any country (with the notable exceptions of India and Sri Lanka). As a result,

the case studies are categorized by APS model instead of country. The team made dedicated visits to India and Sri Lanka because of their high concentration of different types of APS schemes, and for that reason those two countries contribute a large portion of the case studies. Single examples from other countries were investigated through a combination of brief visits and desk research.

1.4 Layout of the ReportThe report is organized as follows: Section 2 explains how the team analyzed specific APS experiences in terms of costs and benefits. Sections 3 to 5 describe case studies in developing countries. Each section covers one of the three APS groups: captive power and P2P, mini-grids and SPD systems, and coordinated supply of individual power generation. Section 6 reviews the drivers of the mobile telephony revolution in developing countries and considers whether the conditions exist for the same type of revolution to occur in the electricity sector. Section 7 summarizes the key findings.


3

2 Approach to Cost-Benefi t Analysis

The cost-benefit analysis for the case studies described in sections 3 to 5 is both quantitative, to the extent possible, and qualitative. It compares the costs and benefits of APS with appropriate counterfactuals (that is, what would exist in the absence of APS). In some cases, when a grid is accessible, a grid connection may be the appropriate counterfactual. In other cases, the counterfactual may be kerosene lighting. One model of APS may be a counterfactual for another model (for example, mini-grids, SPD systems, and conventional grid connections may all be counterfactuals of each other). Where grid connection is the counterfactual, the analysis also identifies whether it is the actual unreliable grid network as it is, or the theoretical optimal grid, which does not exist in practice. Addressed in the analysis of both the APS and the counterfactuals were the following:

• Costs (capital costs and operating costs), including the costs of fuel, generation, transmission, and distribution

• Technical and nontechnical losses actually incurred or which might reasonably be incurred

• Health, environmental, and social impacts

• Quality of supply (reliability, voltage and frequency fluctuations, and the resulting cost of unreliability)

Where the counterfactual is no electricity supply, the analysis assesses the economic value (willingness to

pay and ability to pay) of electricity supply or the costs of alternatives (such as kerosene lighting or pico solar lighting).

The cost-benefit analysis is approached from both financial and economic points of view. The financial viewpoint looks at the APS developments from the perspectives of the private developer, the consumer, and the utility. The economic viewpoint looks at them from the national perspective.

A key aspect of this analysis is consideration of situations in which distortions in the regulatory or institutional framework lead to tariffs that do not reflect costs. For example, tariffs paid by industrial customers for electricity sourced from the central grid may be artificially high to cross-subsidize other customers, making some APS schemes attractive to users when they are not the best solution for the country. Subsidies or artificially low tariffs may make APS schemes unattractive to users when they are the best solution for the country.

The economic (national) viewpoint takes account of the costs and benefits that are not monetized, including health, environmental, social, and indirect economic development benefits. Generally, no attempt is made to quantify these costs and benefits.


5

3 Captive Power and P2P

For this analysis, captive power is defined as an embedded supply of power primarily for use by a commercial business where the power is not simply used for backup and surplus power is sold to a utility or a market. Captive power in the APS context includes outsourcing of on-site generation (for example, when an electricity user contracts with a third-party company to install and operate an on-site power plant that provides electricity to the user).

P2P power transactions are those between private parties or through a trading party, with electricity transmitted through an electricity grid under a third-party access arrangement. In developed countries, third-party access arrangements and competition are well developed, but in developing countries they are at a relatively early stage of implementation. The P2P arrangements in this section illustrate how P2P can be implemented in relatively simple ways without fully liberalizing the electricity market.

3.1 Economic and Financial DriversIn liberalized electricity markets, the motivation for P2P is based on the expectation that competition will drive down the cost of electricity generation and supply and there is no need to investigate the specific drivers. In developing countries, where third-party access arrangements are rare, it is necessary to identify the drivers for individual power generation schemes.

3.1.1 Primary Drivers

There are four primary motivations for developing captive power and P2P. The first two relate to failures by the national utility and bad pricing policies:

• Unreliability of grid-based power (due to insufficient generation or transmission capacity, or other factors)

• Distortions in pricing (that is, cross-subsidies) that cause some consumers to pay high prices—above cost-reflective levels, which may lead to captive power and P2P becoming financially viable for some consumers

The second two motivations relate to cost efficiency, whereby on-site generation costs are lower than the costs of conventional grid-connected power plants:

• Advantageous access to fuel, such as bagasse from sugar processing, wood chips from a sawmill, or site-specific hydropower

• Additional benefits from power generation, such as cogeneration plants in manufacturing or other processes requiring steam, heat, or cooling

These latter two drivers can enable small power plants to produce electricity more cost-effectively (from a national perspective) than a national utility can. Often there are multiple motivations, both good and bad.

The main difference between captive power and P2P is that the buyer of P2P electricity is a consumer or group of consumers, whereas the buyer of captive power is a grid utility. To develop power generation as a P2P scheme, the generator must have some reason not to sell to the grid utility. For example, a generator may choose to sell to customers rather than the grid if revenues from the grid are unreliable or if the maximum price offered by the grid is lower than the price that eligible consumers are willing to pay. It is important to understand why a generator prefers a P2P arrangement over an IPP one.

3.1.2 Reliability

Markets in which P2P arrangements—contracts between producers and consumers—flourish encourage cost efficiency by introducing competition in the generation and supply of electricity. Competitive power markets typically require third-party access, a regulatory framework to ensure transparent and fair access to the network, and a complex balancing and settlement system to account for the certainty that the amount supplied to the network by the producer will not exactly match the amount used by the consumer during each time period.8 Systems with poor supply reliability are generally not the most competent candidates for introducing and operating such complex frameworks effectively.

An additional problem with introducing P2P arrangements (or bilateral contracting) in such systems is that it is difficult to allocate shortfalls between the incumbent utilities’ customers and the consumers buying electricity from IPPs under third-party access arrangements. If the shortfalls arise because the incumbent generates insufficient supply, then it may be simple to identify the problem and require the incumbent to interrupt supply to its customers. But if the problem relates to the capacity of the transmission grid, then the incumbent may

8 The two main options are either a mandatory gross pool or bilateral contracting and a balancing market (or net pool).



legitimately (or not) require that P2P customers share in the load shedding.

In many developing countries, supply reliability is a problem and P2P arrangements are not common. However, India has introduced P2P with mixed success. And Zimbabwe, despite chronic power shortages, has introduced a simple P2P scheme without a complex balancing market which appears to be functioning well. This suggests that simple schemes are feasible in developing countries and that one of the drivers can be chronic power shortages.

3.1.3 Cogeneration

CPPs, which have existed since the early days of the electricity supply industry, are relatively common throughout the world. Although electricity users can develop such plants to meet only their own demand, the opportunity to sell surplus electricity often makes them more financially viable. For many industrial plants, the ratio of heat to power demand often means that cogeneration plants (in particular) are viable only if surplus electricity can be sold. Economies of scale also make it more attractive to develop a larger plant that can supply consumer demand as well as the grid.

3.1.4 Utilities’ Perspective

Although CPPs and P2P may offer clear benefits for both the generator and the consumer, they may have negative impacts on the incumbent utility. A utility that is cross-subsidizing one group of customers by charging high tariffs to another may lose the source of its cross-subsidy when captive power or P2P schemes are allowed. A sufficient number of such schemes may threaten a utility’s financial viability. The best solution is for the utility to charge prices that reflect costs so that when it loses sales, its costs are simultaneously lowered. However, it is often politically difficult to make prices cost reflective by raising tariffs charged to a subsidized group because that group is typically residential customers. As described later in this section, in India a “fix” has been implemented in an attempt to help overcome this problem.

Utilities may have legitimate reasons for rejecting the purchase of surplus electricity from CPPs or for rejecting P2P—for example, because distorted tariffs are a government policy and captive power or P2P undermines that policy—but sometimes the reason is simply that such arrangements reduce their hold on the sector. In some situations, to avoid or reduce load shedding, consumers with CPPs or backup plants may be encouraged to sell surpluses to the national utility. Although backup power is generally much more expensive than grid-connected

power, the cost to the national economy of load shedding can be enormous. For that reason, utilities or regulators sometimes allow such arrangements. Regulators may also allow the costs to be passed on to users through higher prices, or the government may step in and help subsidize these interim arrangements.

3.2 Approach to Cost-Benefi t AnalysisTwo key questions arise in relation to captive power and P2P:

• Is power generation capacity that is developed as captive power or P2P the best solution from a national perspective?

• Do the utilities and policymakers have legitimate reasons for rejecting captive power and P2P?

The cost-benefit analysis therefore considers the national perspective and the utility perspective:

• From the national perspective, it asks whether the CPPs and P2P power plants would be least-cost in a “first best” environment in which the utility provides reliable electricity supply.

• From the utility perspective, it compares revenues and costs accruing to the utility in situations with and without captive power and P2P.

It is also interesting to consider what motivated the developers of captive power generation—for example, distorted tariffs or power shortages. The cost-benefit analysis therefore also considers the perspective of the developer of a CPP.

Finally, in some of the P2P case studies, particularly in India and Zimbabwe, it is relevant to ask why the generators and consumers prefer to contract with each other rather than with the conventional utility. For some of the cases, the analysis thus considers the perspectives of both the generators and the consumers.

3.3 Case StudiesThe following sections present six case studies of captive power and P2P arrangements in four countries.

3.3.1 Captive Power: Tokyo Cement (Sri Lanka)

In the 1990s, Sri Lanka introduced legislation that allowed private firms to sell electricity to the Ceylon Electricity Board (CEB). More recently, it introduced legislation to implement competition, but these reforms were not in


7Captive Power and P2P

force over the period described by the two case studies in this section and the next. During these periods, the CEB was effectively a vertically integrated utility that also purchased electricity from IPPs under build-own-operate or build-own-operate-transfer arrangements.

Tokyo Cement Group (TCG) is a Sri Lankan company with a cement manufacturing plant at Trincomalee. In 2008, it established a 10 MW biomass power station on the site through a subsidiary. This is a relatively conventional captive power scheme in which three of the four key drivers identified in section 3.1 were present (price distortions in Sri Lanka are only a minor driver).

First, TCG required a secure supply of power to run its cement plant, to meet demand of about 8 MW at peak production. Sri Lanka’s power supply in Trincomalee today is generally reliable. However, when TCG developed its plant, war-related problems affected the transmission line feeding the area. The nature of TCG’s cement manufacturing operations makes any interruption in power supply, however brief, very costly.

Second, TCG saw an opportunity to source fuel for a biomass generation plant by using the backhaul from the independent trucking dealers that the company uses to distribute cement throughout Sri Lanka. About 150 trucks visit the plant every day. Truck owners are paid for every tonne of rice husks or wood (gliricidia, a fast-growing species of biomass commonly available in Sri Lanka, or sawdust in the off-season) that they bring to the plant; how they collect the biomass and pay for it is up to the truck owners.

Third, TCG could use the ash from the power generation process in the cement manufacturing process.

TCG is generally able to supply the CEB grid with the surplus from its power station, but it also purchases electricity from the grid. Whether TCG is a net purchaser or seller varies from year to year. When selling electricity to the grid, TCG benefits from an attractive FIT for renewable energy; when TCG signed its power purchase agreement (PPA) with the CEB in 2008, the FIT for power plants operating on agricultural waste was Rs 10.70/kWh, but scalable components of the FIT had raised it to about Rs 14.00/kWh in 2013.

Developer’s Perspective

By the time TCG completed the development of the power plant, Trincomalee’s power supply had become considerably more reliable, so the plant offered little benefit in terms of reliability of supply. Self-supply will remain beneficial to TCG as long as the cost of

generation (indicated by TCG to be Rs 12.00/kWh) is lower than the grid tariff (Rs 20.00/kWh). The project will remain beneficial as long as the FIT (Rs 14.00/kWh) that TCG receives from the CEB is higher than the cost of production (Rs 0.12/kWh). The PPA is in place for a period of 20 years, and the FIT includes an escalation allowance that should ensure project viability until the PPA matures.

Two additional questions might be asked:

• Would TCG have developed the plant if no FIT were available and if the CEB offered to buy surplus electricity only at its own avoided cost? The sale of surplus electricity from the biomass might have been only marginally viable for TCG if the FIT had been based on the avoided cost of energy generation, as it is now calculated. An earlier version of the FIT program offered renewable energy plants a tariff based only on the CEB’s avoided cost. The CEB still uses the avoided cost to determine tariffs paid to renewable energy plants that signed PPAs before 2007. That cost is estimated at Rs 15.63/kWh for 2013 but is likely to fall to perhaps Rs 11.5/kWh in 2014, when new coal-fired power plants are commissioned. That level is likely to be maintained in real price terms from 2014 onward. However, if the CEB had allowed for the full avoided costs of generation capacity and, possibly, some transmission capacity, as well as the avoided cost of fuel, then the biomass plant would almost certainly have been financially viable for TCG.

• Would TCG have developed the plant if the CEB had refused to buy the surplus electricity? This question is harder to answer, but the answer is probably yes. The plant’s cost of Rs 12.00/kWh is substantially lower than the cost of purchased electricity and will remain so even when tariffs fall after the coal-fired power plants are commissioned.

Utility’s Perspective

The CEB estimates its avoided costs (the costs that it avoids by buying from IPPs) at Rs 15.63/kWh in 2013, falling to perhaps Rs 11.50/kWh in 2014. If allowance is also made for the avoided costs of generation capacity and of some transmission capacity, then these figures would rise. The cost of electricity purchased from biomass generators is Rs 14.00/kWh, suggesting that purchasing electricity from the plant is likely to match the long-run savings in costs to the CEB. Even if the FIT were higher than the CEB’s real avoided costs, under the current scheme the CEB is compensated for the excess costs by allowing its overall revenue requirements to rise—so that, in theory, it should be indifferent to the level of the FIT. However, as a result of TCG developing a power plant,



the CEB estimates that it loses revenues of Rs 20.00/kWh while paying costs of perhaps Rs 17.30/kWh to supply TCG. The excess profit of Rs 2.70/kWh would have been used to help subsidize other customers, particularly small residential customers. Thus, although the CEB might have been neutral about losing revenues from this customer if the tariffs fully reflected costs, it is more likely to resist CPPs when cross-subsidies are built into the tariff structure. (This is not to suggest that the CEB has resisted the development of this biomass plant.)

National Perspective

TCG’s biomass plant produces electricity at a cost of about Rs 12.00/kWh. From 2014 onward, it will produce energy cost savings to the CEB at the margin of Rs 11.50/kWh. It will also produce generation and transmission capacity cost savings that will bring the total savings above Rs 12.00/kWh. Therefore, overall, the plant is attractive from a national perspective.

Summary and Key Lessons

Table 1 summarizes the results of the analysis.

This case study offers two key lessons:

• Captive power can lower costs to developers and the nation if production costs are lower than grid tariffs and there are cogeneration or other benefits.

• A utility should generally be neutral to such schemes, though it may lose where cross-subsidies exist.

3.3.2 Captive Power: Sevanagala Sugar Factory (Sri Lanka)

Sevanagala Sugar Industries has a sugar factory in southern Sri Lanka, in the western part of Monaragala

district. It sources sugarcane from its own sugar estate and from contract growers, processing it through its own mill to produce sugar in its final packaged form, for direct delivery to markets.

The factory collects the bagasse (fiber) waste from the cane crushing process for use in a 2.5 MW power plant that supplies the entire facility. Steam from the plant is also used in sugar production. This use of sugarcane waste and the combination of electricity and heat/steam are examples of the second two motivations for using captive power—advantageous access to fuel for power generation and cogeneration benefits of electricity generation and process heat/steam.

At present, the factory uses only 1.6 MW of its capacity and does not sell any power to the CEB grid, so it is not currently an example of APS, but company management intends to expand sugar production and, with increased efficiency of processing and power generation, plans to replace the generating capacity with a 10 MW plant. This will be significantly more capacity than the factory will require for its own use, even after expanding operations, so the company will sell the surplus to the CEB, under a FIT arrangement. It is this proposed arrangement that is analyzed in this case study.


As noted in the TCG case study, electricity supply in Sri Lanka is generally reliable. Although reliability was no doubt a factor in the company’s decision to develop a CPP, cost savings were clearly the motivation for developing a self-generation power plant. With advantageous access to bagasse fuel from the sugar-crushing process, the factory’s power production costs are minimal. Lacking detailed information, these are assumed to be Rs 12.00/kWh. With the added benefit of producing heat for use in the evaporation and boiling of the sugar syrup, it can be assumed that the present value of supplying power and heat from the facility is cheaper than the cost of purchasing power from the CEB.

The assumption is that the key driver for developing the excess capacity is the ready supply of bagasse waste rather than the benefits of cogeneration of heat and power. Without data on the costs of the factory’s power generation, it is not clear whether the FIT is necessary to cover the incremental up-front and operating costs of developing the additional capacity. At a minimum, it is safe to assume that under the FIT of Rs 14.00/kWh, the project has a positive value for the business. Any increment above the cost to produce is of value to Sevanagala.

Table 1. Summary of Tokyo Cement Case Study

Stakeholder Perspective

Developer Captive power is beneficial as long as generation cost (Rs 12.00/kWh, according to developer) is lower than grid tariff (Rs 20.00/kWh); grid supply tends to be reliable; feed-in tariff makes sale of surplus possible in market where supply tends to equal demand.

Utility Essentially neutral as costs are passed on to customers; Developer was a net contributor to cross-subsidize residential customers, but not likely a strong enough reason for the CEB to resist plant development

Nation Energy cost savings to the CEB at the margin of Rs 11.50/kWh and additional generation and transmission capacity cost savings bring savings above Rs 12.00/kWh; cheaper source of supply than next best alternative



The two questions posed in the case of TCG might also be asked here:

• Would Sevanagala have developed the plant if no FIT were available and instead the CEB offered only to buy surplus electricity at its own avoided cost? As in the TCG case, the avoided cost is estimated at Rs 15.63/kWh for 2013 but is likely to fall to perhaps Rs 11.50/kWh in 2014 when the coal-fired plants are commissioned, and this level is likely to then continue (in real price terms). The sale of surplus electricity from the bagasse plant might have been only marginally viable if the FIT had been based on the avoided cost of energy generation as currently calculated. However, as with TCG, if the CEB calculated the avoided cost tariff with allowances for the full avoided costs of generation capacity and, possibly, some transmission capacity, as well as the avoided cost of fuel, then the plant would almost certainly have been financially viable for Sevanagala.

• Would Sevanagala have developed the plant if the CEB refused to buy the surplus? This question is harder to answer, and unlike the TCG case, the answer is a partial no: the company would have been unlikely to develop the plant to the planned scale. It can be assumed that the plant’s costs are lower than the grid tariff for purchasing electricity, so it makes sense to develop the plant to meet the factory’s demand. The boilers might have been larger than needed to supply the power generators, if the heat required for sugar production is greater than the steam required to power the generators. It is assumed that the plant’s cost of Rs 12.00/kWh is substantially lower than the cost of purchased electricity and will remain so even when tariffs fall in 2014.


The CEB’s perspective in this case is thought to be more or less the same as in the TCG case. The CEB estimates its avoided costs (what it saves by buying from IPPs) at Rs 15.63/kWh in 2013, falling to perhaps Rs 11.50/kWh in 2014. If allowance is also made for the avoided costs of generation capacity and of some transmission capacity, then these figures would rise. The cost of electricity purchased from bagasse generators is currently Rs 14.00/kWh, suggesting that purchasing electricity from the plant is likely to match the long-run savings in costs. Even if the FIT were greater than the CEB’s real avoided costs, under the current scheme the CEB is compensated for the excess costs by allowing its overall revenue requirements to rise, so that in theory it should be indifferent to the level of the FIT.


Purchasing from the plant will produce energy cost savings for the CEB at the margin of Rs 11.50/kWh and will also produce generation and transmission capacity cost savings that will certainly bring the avoided cost above Rs 12.00/kWh. Therefore, overall, the plant is attractive from a national perspective. Owing to the requirements for combustion of bagasse, environmental benefits will accrue only to the extent that the power from the plant displaces dirtier fuels, such as coal.




• Captive power can lower costs to customers and the nation if the production costs are lower than grid tariffs and grid costs, and there are cogeneration or other benefits.

• Utilities can be broadly neutral to captive power if costs (of FITs) can be passed on to customers; they may lose net revenues where cross-subsidies exist.

3.3.3 Captive Power: Pune Power Project (India)

The Electricity Act introduced in India in 2003 sought to create a more market-based approach to power supply across the country. It included open access to the electricity transmission networks for generators and eligible consumers. In November 2011, the Central Electricity Regulatory Commission (CERC) declared that

Table 2. Summary of Sevanagala Sugar Factory Case Study


Developer Advantageous access to fuel (bagasse) makes self-supply better than grid supply (assumed to be Rs 12.00/kWh and Rs 20.00 kWh, respectively), with additional benefit of heat for processing sugar; selling surplus makes sense with FIT at a level that puts tariff offered above the cost of generation

Utility Essentially neutral as costs are passed on to customers; the plant is not a major customer of the utility, so no major net revenue loss on cross-subsidies that it cannot collect from the consumer

Nation Avoided cost of grid electricity displaced by the plant is estimated at Rs 15.63/kWh in 2013 falling to Rs 11.50/kWh in 2014 (higher if avoided costs of generation capacity are included and if some transmission capacity is assumed to be saved); electricity costs Rs 14.00/kWh, matching long-run cost savings, so beneficial overall; environmental benefits from displacing dirtier fuels (coal and heavy fuel oil)



all customers with demand greater than 1 MW would have open access, with tariffs not regulated by state regulators. The wheeling charges applicable to each transaction would be determined by each state regulatory commission.

One of the functions created through the reform was that of power traders, which operate across states under licenses granted by the CERC. In addition, the CERC has allowed market exchanges for short-term power trading—the Indian Energy Exchange and Power Exchange India Limited—which facilitate transactions over periods ranging from intra-day to two weeks ahead. Trades may occur within states, between states, and with other countries. Currently, power traders’ transactions entail just 2.5 to 5.0 percent of all power generated in India.

The city of Pune in Maharashtra state was subject to the electricity market framework established by the federal government in 2001, which included bilateral contracting for eligible consumers, mandatory third-party access, a balancing market, and independent regulators. In practice, however, the market continued to be controlled by the incumbent power supplier, the Maharashtra State Electricity Distribution Co. Limited (MSEDCL).


In 2005, businesses and households in Pune were suffering from load shedding as a result of insufficient generation capacity for providing power to the MSEDCL. As insufficient capacity was not a new phenomenon (there or in much of India), many industries had established backup generation capacity through owned facilities or outsourcing arrangements. At the time, the MSEDCL did not use this capacity as a power source. This is thus a less conventional captive power arrangement. Strictly speaking, it is backup power because the industries would have preferred grid electricity supply. It was motivated by failures of the main utility.

In light of the capacity shortage, the Confederation of Indian Industries proposed to the Maharashtra Electricity Regulatory Commission that 30 CPPs in Pune generate power for purchase by the MSEDCL. As most of the plants were diesel-fueled, the CPPs requested reimbursement for the fuel charges as well as permission to pass an additional cost through to all but the smaller residential customers as a “reliability charge.” The ultimate agreement between the CPPs and the MSEDCL credited the CPPs’ accounts against future charges.

From May 2006 to July 2007, the total demand for power in Pune was 365 GWh. Of this, the grid supplied 282 GWh

(77 percent), and the CPPs supplied the remaining 83 GWh (23 percent). The Confederation of Indian Industry (Pune branch) estimated this as an average of 60 MW of capacity for seven hours per day.


The MSEDCL was able to contract additional capacity from otherwise dormant capacity and recover from customers all the costs it incurred (including power purchase, transmission, and distribution costs). There was no impact on its own generation capacity and no change to its revenues other than the additional sales. The MSEDCL’s revenues were allowed to increase to cover the cost of the additional purchases from the pool, with all but the small residential customers paying a reliability charge. Ultimately, this benefited the MSEDCL, as its profitability was not affected.


The national perspective asks whether contracting power from the CPPs was the optimal arrangement for the country or, probably more appropriately, for the state. From the economic perspective, it was a good solution under the circumstances. The best solution would clearly have been for the MSEDCL to contract with more cost-effective sources of power generation. Nobody regarded this arrangement as anything other than a temporary and costly solution to a power supply crisis resulting from failures of the conventional power supply industry. But given the power shortages and the long lead times for developing power plants, the capacity shortages could not be solved quickly. Thus, it was better to supply power to the grid from CPPs at an additional charge of $0.75/kWh rather than face load shedding that could cost the economy up to $1.90/kWh (Wärtsilä India Ltd 2009). Additional alternatives to load shedding may have been available to the MSEDCL in the form of demand-side measures, including energy conservation and load management. It is not known whether the MSEDCL investigated or implemented such demand-side options.




• The cost of power interruptions can make it necessary for electricity consumers to obtain expensive diesel-based (and other) captive (or backup) power. Selling a surplus from backup plants is financially beneficial for consumers when the tariff offered by the utility covers the costs of generating it.



• When utilities’ supply cannot meet demand, purchasing an expensive source of supply can be justified if the costs are lower than the costs of load shedding.

P2P: Tata Power Tr ading Company (India)

Tata Power’s subsidiary Tata Trading Company (TTC) was the first company in India to receive a power trading license, in June 2004. It is involved in about 350 P2P arrangements across the country and is India’s largest power trading company (by volume of power traded), with 5,583 GWh traded during the 2012 financial year. TTC purchases power from a range of generators (including Tata Power companies, IPPs, and CPPs). From its portfolio, it sells to a range of customers, including state distribution utilities and industrial consumers. For its industrial customers, TTC offers a long-term, reliable, and economic supply which the customers might not otherwise be able to access. In addition, to balance demand and their contracted supply, TTC facilitates short-term power transactions through India’s registered Power Exchange. Tata Power facilitates the actual transaction by securing open access from regional load dispatch centers. Its customers are all large consumers with dedicated lines through which the prioritization of the power supply can be isolated and secured.

Because residential and agricultural tariffs in India are generally heavily subsidized by industrial and commercial customers, and because of fears that P2P arrangements would allow such customers to avoid subsidizing residential customers, the government introduced a “temporary” cross-subsidy surcharge (CSS). The formula agreed for calculating the CSS was (and remains) as follows:

S � T � [C (1 � L / 100) � D]

where S is the surcharge, T is the tariff payable by the relevant category of consumers, C is the weighted

average cost of the top 5 percent of power purchased (at the margin, excluding liquid fuel–based generation and renewable power), D is the wheeling charge, and L is the system losses for the applicable voltage level, expressed as a percentage.

In the fully liberalized competitive electricity markets implemented in Europe, Australia, and the United States, the question “Why adopt P2P?” is irrelevant because consumers and producers have no option—they must adopt P2P. Smaller consumers and many large consumers normally buy electricity from a supplier rather than directly from a generator, but the suppliers and the generators have entered into P2P arrangements with each other. This is also true in India, but many consumers effectively continue to buy electricity from the incumbent state electricity boards, which in turn buy electricity from generators (some of which may be private IPPs). It is therefore relevant to ask, “Why adopt P2P?” in India because the answers may provide lessons for countries that do not intend to introduce full liberalization.

Poor supply reliability is not common where most competitive market arrangements exist. Such arrangements generally exist to ensure that, collectively, generation output matches the collective demand of consumers in each half hour. India is unusual in operating competitive markets in a situation of chronic supply shortages. In this situation, P2P arrangements can help some consumers achieve more reliable supply than the conventional utility route.

Customer’s Perspective

Customers of power trading companies have options equivalent to those of generation companies: buying from the distribution utility, under a bilateral contract with a generator, and from a power trading company. Table 4 outlines the factors affecting the choice.

A customer sourcing power from a distribution company may face a lower tariff than from a power trader or a generator. The tariff may also be higher if there is a cross-subsidy. Regulations allow for both wheeling charges and the CSS, and for negotiation of tariffs for private arrangements, so it is not possible to say which scenario produces lower tariffs.

A customer may prefer to source power from a power trading company for reasons of supply reliability, regardless of the tariff. Distribution utilities have not always been able to offer reliable power supplies, often owing to excess demand and to political mandates to direct supply to particular customers. Supply from a single

Table 3. Summary of Pune Power Project Case Study


Developer Captive power is more expensive than grid supply, but justified by higher cost of blackouts from grid supply; selling surplus from dormant capacity justified when price paid by utility covers the extra costs

Utility Essentially neutral as high costs of power purchased are passed on to customers

Nation Not the cheapest source of power in the long run but effective, given long lead times for new power development, and cheaper than costs of load shedding ($0.75/kWh versus $1.90/kWh)



IPP may also be unreliable. However, power traders, particularly in competitive trading environments, have diversified—and therefore reliable—sources of supply.


Generation companies that supply power traders in India’s open electricity market may choose to supply a distribution company, a power trading company, or large customers directly. Table 5 describes the factors affecting the choice. Many generation companies sign PPAs with power trading companies before developing their facilities, to enable financing of their projects. A generator might not develop a facility if its only option for a PPA counterparty is an unreliable distribution company, or it might price that risk into any PPA and charge high prices (if it can).

Thus, weaknesses in distribution utilities—including their creditworthiness—and distortions in market pricing can encourage IPPs to seek P2P transactions with a power trader or directly with a consumer. Some benefits of transacting with a distribution company are also achieved when transacting with a power trader, which has a

diversified customer base and lower transaction costs than direct sales. This combination of benefits may make transacting with a power trader preferable.

Power Trading Company’s Perspective

Power trading is a regulated activity. The licenses granted by the CERC allow a company to trade power up to a specific volume limit. TTC is one of seven trading companies in the largest bracket, which requires a net worth of Rs 500 million; these companies may trade an unlimited volume of power each year.

The prices that traders offer and charge are set in negotiation and therefore determined by market forces and competition. Trading companies charge margins on the volume of power they trade between generators and consumers, with the margin regulated by the CERC. The fixed margin means that the trading company’s motivation is to trade as large a volume as possible. In interstate power trading, the maximum margin must not exceed Rs 0.07/kWh for a sale price exceeding Rs 3.00/kWh and must not exceed Rs 0.04/kWh for a sale price less than or equal to Rs 3.00/kWh.

Table 4. Factors Affecting Customer Choice of Power Supplier

Via distribution company Via power trading company Direct from generator

Tariff may be higher or lower Tariff may be higher or lower (partially depends on the CSS)

Tariff may be higher or lower (partially depends on the CSS)

May not offer reliable supply Reliable supply Chance of unreliability owing to single supplier, also depending on fuel type (such as low flow in run-of-the-river hydro)

Lower transaction costs compared with direct purchase from generator

Lower transaction costs compared with direct purchase from generators

Can choose to source a certain proportion of renewable energy

Higher transaction costs

Table 5. Factors Affecting Generator’s Choice of Distribution Channel

Via distribution company Via power trading company Direct to customer

Not always most reliable payer; PPA may not be bankable

Reliable payer

Diversified customer base, so low risk compared with direct sales to customers

Reliable payer

Single customer, so more concentrated risk

Tariff offered may be lower than for higher-value direct customers as some customers will be low-income and less able to pay a high tariff

Can charge higher tariff as company is offering reliable supply to its customers

Could charge higher tariff as customers place premium on reliable supply

Lower transaction costs compared with direct sales to customers

Lower transaction costs compared with direct sales

High transaction costs due to lack of specialization in handling customers and power market



In addition to the costs of originating and managing transactions, trading companies pay wheeling charges for all power traded, as regulated by each state. Under section 42 of the Electricity Act of 2003, state regulatory commissions can charge power traders a CSS in addition to the wheeling charge where cross-subsidies between customer categories will be affected by the trading arrangement, provided the CSS is used to meet the requirements of the cross-subsidy and that it is progressively reduced and eliminated as specified by the state regulatory commission.


Under section 42 (4) of the Electricity Act of 2003, all power transactions in which a consumer receives power from a person other than the distribution licensee—such as power traders—may be liable to pay wheeling charges to the utility. In addition, if cross-subsidies in the tariff structure are affected negatively by the transaction, the utility can include an additional CSS on the wheeling charge. Table 6 outlines the comparative costs and benefits to the utility of the options for transacting power between generator and customer.

What is not clear is whether the CSS that the utilities can claim would cover losses incurred as a result of losing those customers or whether a CSS that covers such losses would be greater than the saving such customers could gain. Daljit Singh (2005) attempts to analyze this effect, citing evidence from Maharashtra. He concludes that a CSS necessary to cover the utility’s losses on the cross-subsidy would be greater than the value that a switching consumer might gain, which suggests that consumers will not adopt P2P or, if the CSS is set at a level that allows consumers to adopt P2P, that the utility will suffer financial losses. (That analysis assumes that P2P has no benefits other than avoiding a distorted tariff.)

The evidence of what has happened in Maharashtra lends some support to this conclusion. Having initially set the CSS at zero, in early 2013 the Maharashtra Electricity Regulatory Commission increased the CSS

applicable to customers sourcing power through open access, to between Rs 0.10 and Rs 5.53/kWh, depending on customer type; higher-voltage and higher-end customers faced higher charges. The poorest domestic households with the lowest usage paid no CSS. Reports on customers of Tata Power Company (TPC) who source their power from Reliance Infrastructure suggest that the tariff differential between the two became less than 5 percent for 75,000 high-end customers after the CSS was adopted. The difference could disappear completely over time, although it would ease the tariff burden on 2.1 million low-end consumers whose tariffs increased after they shifted to TPC. Subsequently, TPC appealed the decision and the Appellate Tribunal for Electricity stayed the order, pending the outcome of the multiyear tariff calculations still under way. It remains to be seen whether the CSS will be adopted in Maharashtra. These events highlighted the reality of the dilemma identified by Singh in 2005, that the concept of the CSS is sound but the reality of its implementation is more difficult.

The notion that one barrier to P2P arrangements is the risk of losing customers who are net contributors to cross-subsidies was supported by anecdotal evidence in Maharashtra (where the incidence of such transactions is lower than in many other states). The MSEDCL receives 41 percent of its revenue from just 2,000 of its 20 million customers, according to the state regulatory commission. This imbalance highlights the risks it faces if customers with large loads source their power elsewhere. Although both the Electricity Act and the regulatory commission allow P2P transactions, and there is an allowance for accommodating cross-subsidies through additional surcharges, bilateral contracting or contracting through power traders is rare. Reports suggest that the MSEDCL can claim the existence of technical barriers (for example, high loads require major line and transformer upgrades) to protect it from losing its cross-subsidies. It is very difficult to substantiate whether the surcharges are sufficient to cover the lost revenues and whether the MSEDCL’s concerns are legitimate or an irrational rejection of a policy. The MSEDCL has nothing to gain from P2P and, if

Table 6. Factors Affecting Utility’s Power Transactions

Via distribution company Via power trading company Direct to customer

Higher volume of power traded lowers operating risk through more diversified customers and suppliers, and diversifies customer and supplier load profile

Distribution company receives wheeling charges to cover all costs of transaction, including profit margin

Receive wheeling charges to cover all costs of transaction, including profit margin

Can cross-subsidize across customer categories (where state regulations allow)

Receive CSS to cover cross-subsidy Receive CSS to cover cross-subsidy



the surcharges are inadequate, it potentially has a lot to lose, so its rejection of the policy may be reasonable. But if the surcharges are adequate, there should be no reason for policymakers to reject P2P.


From the national perspective, the key question is whether generation developed to supply TTC is better than generation developed to supply the MSEDCL directly or better than small-scale generation developed to supply a large customer or small group of customers directly. In principle, to the extent that P2P helps encourage efficiency, P2P should be better from a national perspective. It is unlikely that the IPP plants developed to supply TTC differed fundamentally in size (economies of scale) or fuel mix from those that might have been developed to supply the MSEDCL directly. One would expect them to have been constructed over a shorter period and without cost overruns, and one would expect that the contracts would encourage the IPPs to operate more efficiently. However, no empirical evidence is available to show that those plants were actually more efficient.

Small-scale generation developed to supply one or more industrial consumers directly rather than through a trader is likely to suffer from significant diseconomies of scale. The generator will thus need a large reserve margin to ensure security of supply. Unless small-scale generation offers specific benefits, such as those described for captive power (cogeneration, availability of low-cost fuel, and so on), a trader buying from large power plants is almost certainly more cost-effective from the national perspective, at least in the context of a large country such as India.



This case study offers four key lessons:

• P2P arrangements can provide more reliable supply for customers than can weak utilities.

• Trading companies can trade power more efficiently through economies of scale, with lower risk for customers and generators, as compared with direct transactions.

• The loss of cross-subsidizing customers makes open access problematic for utilities, and compensation measures may be inadequate to make up the difference where the loss of revenue (compensation amount) is less than the subsidy to the customer.

• P2P and open access arrangements should lead to more scale-efficient development of generation plants; where weak utilities are unreliable buyers, traders will prefer to sell to more reliable and geographically dispersed customers.

3.3.4 P2P: Power Supply Ring-Fencing (Zimbabwe)

Like many countries, Zimbabwe has faced shortages of power capacity in recent years. Customers have suffered regular load shedding and are forced to supply backup power at high cost. This situation has given rise to opportunities for firms to generate power for customers that are willing to pay high tariffs. Customers are often located far from the power generation sources (particularly when that source is hydropower), so this arrangement requires third-party access to the transmission grid. Zimbabwe has considered the introduction of competition in the power market but—despite some unbundling of generation from transmission, distribution, and supply—the market remains dominated by incumbent utilities.


The customer perspective is a generic one, hypothetically requiring uninterrupted supply for 24-hour operation. In the absence of grid power, customers require backup from diesel generation. The analysis shows that a customer that can purchase electricity from the Zimbabwe Electricity Transmission and Distribution Company (ZETDC) for only

Tabl e 7. Summary of Tata Power Trading Company Case Study


Customer Tariff may be higher or lower; reliable supply; lower transaction costs compared with direct purchase from generators; can choose renewable energy supply; surcharge to cover loss on cross-subsidy may be greater than benefit of P2P

Developer Power trading companies are more reliable payers than weak utilities; diversified customer base has lower risk than direct sales; generators can charge higher tariff as they offer more reliable supply; lower transaction costs compared with direct sales

Power trading company Essentially neutral as high costs of reliable power purchased are passed on to customers

Utility Receives wheeling charges to cover all costs of transaction, including profit margin; receives surcharge to cover cross-subsidy, but may be insufficient to cover loss of net payer in cross-subsidy

Nation P2P should be sourced from larger generation plant benefitting from economies of scale over smaller plants developed for specific customers



75 percent of its power needs and thus requires diesel generation as a backup will benefit from the ring-fenced power arrangement by approximately $0.026/kWh, a saving of approximately 14 percent (table 8).


Nyangani Renewable Energy (Pvt) Ltd (NRE), a Zimbabwean company, operates three run-of-the-river hydropower generation facilities in the Eastern Highlands. Its average cost of supply for its three facilities is about $0.15–0.16/kWh, including return on capital. As it is required to sell to the ZETDC, NRE must accept the tariff that the ZETDC is willing to pay. The ZETDC’s average cost of supply is $0.078/kWh, which is significantly lower than NRE’s cost of supply, making the ZETDC reluctant to buy from NRE.

NRE entered an arrangement with the ZETDC, approved by the Zimbabwe Energy Regulatory Authority, whereby it would sell all its power to the ZETDC at a cost-reflective tariff. At the same time, a customer with significant demand entered a separate but back-to-back contract with the ZETDC to purchase all the power supplied by NRE, receiving the benefits of uninterrupted supply (except when both NRE and the main grid were unable to supply), at a tariff of approximately $0.16/kWh. The customer made payments into a bank account that was separate from the ZETDC’s main account; the ZETDC made payments to NRE from the main account. The arrangement is feasible only for large users that have dedicated grid connections, so that supply to such users can continue while the ZETDC disconnects supply to surrounding customers during rolling load-shedding programs. However, the disconnected customers remain exposed to any failure in the high-voltage transmission network between NRE and themselves.

This initial arrangement has been expanded to include additional electricity generators and customers, such that

a ring-fenced pool of power is supplied without interruption and then consumed by customers contracted to pay the higher cost of that power. Among the generators are more-expensive and previously mothballed thermal plants owned and operated by the Zimbabwe Power Company. This broader arrangement has mutual benefit for both generators and consumers, as the generators receive a (regulated) tariff that covers their costs, while the consumers receive uninterrupted supply (with more diversified sources) and no longer rely on expensive backup generation.

However, what occurs now differs slightly from what was envisaged. The total demand by customers signed up for this agreement exceeds the supply from the generators. In addition, the bank account for the arrangement, which had been kept separate from the general accounts, has now become a more general account. As more-expensive generation is now incorporated into the pool, the average cost of supply has increased above the ring-fenced tariff, such that the cost can be brought down only by blending the supply with the cheaper general supply. Although this arrangement is still beneficial for the generators, who receive the cost-covering tariffs (including a return on capital), and those customers receiving uninterrupted supply, it has created a bias toward those customers at the expense of the regular customers, who now face even greater load shedding.

The framework that has allowed this arrangement has developed in a slightly piecemeal fashion. The Electricity Act 2005 gives the Zimbabwe Electricity Commission specific objectives, which opened the door for the P2P transactions that have occurred. The Act identifies those objectives as follows:

(c) to ensure that an adequate supply of electricity is available to consumers,

(d) to ensure that the prices charged by licensees are fair in the light of the need for prices to be sufficient to allow licensees to finance their activities and obtain reasonable earnings for their efficient operation, and

…

(f) to ensure that regulation is fair and balanced for licensees, consumers, investors and other stakeholders in the electricity industry.

Table 8. Customer Cost Calculation

VariableNo ring-fencing, diesel back-up

Ring-fencing, no back-up required

Total power demand per month (MWh) 360 360

Power supplied by grid (MWh) 270a 360

Cost of grid supply ($/kWh/unit) 0.098 0.16

Cost of grid supply ($) 26,460 57,600

Power supplied by diesel generator (MWh) 90 0

Cost of diesel supply ($/kWh/unit) 0.45 0

Cost of diesel generation ($) 40,500 0

Total power supply cost ($) 66,960 57,600

Average cost ($/kWh) 0.186 0.16

a Assumes 75 percent power supplied.



The rather ad hoc development of the arrangement produced no predetermined methodology for calculating wheeling charges and no clear criteria for customer eligibility. So far, the customers involved in the transactions have been those with larger demand, such as those in mining and large industry.

Maintenance of the initial arrangement, with stricter ring-fencing of power supply than in its expanded form, should have led to better outcomes for all parties. It would have provided profitable business opportunities for generation companies, delivered more reliable supply to customers prepared to pay for it, increased revenue for the utility, and potentially provided more reliable supply for all other customers, as the capacity available to supply the non-ring-fenced customers would have increased. Even in its expanded form, the arrangement is more beneficial for all parties than the alternative of more widespread load shedding.

The cost-benefit analysis is based on ring-fenced power supply from multiple generators and purchases by multiple customers, with demand and supply broadly matched. Under this arrangement, the ring-fenced pool is augmented by the ZETDC’s more general pool only to balance supply and demand during the seasons when river flows are low.

There is no cost-benefit analysis from the developer’s perspective. The financial benefits clearly exceed the costs, otherwise the developers would not have developed the plant or entered into a contract to supply electricity. The focus here is therefore on the customer, utility, and national perspectives.


In a generic P2P arrangement, the utility is not a party to the contract but simply a conveyor of power. In Zimbabwe, IPPs are not allowed to sell directly to customers, so the arrangement between the generators and consumers relies on back-to-back contracts with the ZETDC as the counterparty. Therefore, rather than taking a fee for access to its transmission and distribution network (that is, a wheeling charge), it can take a margin on the buying and selling of power transmitted.

The ZETDC loses nothing from this arrangement because, in its absence, it would have to shed load and would earn no revenues. The ZETDC does, however, gain through the margin on the electricity that it sells. The margin is unknown but can be assumed to be greater than zero. Therefore, the ZETDC should have no reason to object to this scheme.


This arrangement is a response to failures by the ZETDC to provide reliable electricity supply. The plants used to supply the ring-fenced customers are typically small (for example, NRE’s hydro plants) or old (the ZETDC’s mothballed coal plants). They are not optimal long-term generation plants that would have been developed had the ZETDC anticipated demand and developed capacity to meet it. The arrangement appears to have been an economically optimal response to a power crisis (that is, second best in the context of failure by the incumbent). The cost of load shedding in Zimbabwe is unknown, but such costs typically exceed $0.50/kWh. The cost to the national economy of supplying electricity, even from old and relatively inefficient plants, would certainly be lower than the cost of load shedding.




• In a situation of chronic power shortages, supply can be increased from private generation when customers are prepared to pay a higher tariff for a reliable supply.

• Customers may pay more than the grid tariff for private generation if they get more reliable supply at a lower cost than self-supply with diesel backup generation.

• Utilities can gain from wheeling charges on the additional load from such arrangements.

Table 9. Summary of Zimbabwe Power Supply Ring-Fencing Case Study


Customer Unreliable grid supply with diesel back-up generation costs $0.186/kWh on average; ring-fencing arrangement costs $0.16/kWh

Developer Power companies provide generation only when it is profitable, so scheme must be attractive to developers

Utility Absent the arrangement, the ZETDC would shed more load and lose revenues; with the arrangement, it gains a margin (assumed to be positive) on electricity it transmits

Nation Second best option where supply fails to satisfy demand as cost of supplying additional electricity, even from old and relatively inefficient plant, would be lower than load shedding; best solution would be to improve grid reliability



• Although a second-best solution nationally (where the plants are more expensive than they would have been in a properly planned system), a P2P arrangement is much better for the economy than load shedding.

P2P: Retail Competition and Open Access (Philippines)

This mini case study is included to show that cross-subsidized tariffs may not be recognized as a problem for incumbent utilities at the time third-party access is introduced.

Although the introduction of retail competition and open access (RCOA) in the Philippines was anticipated under the 2001 Electric Power Industry Reform Act (RA 9136), it did not occur until 2013 because of concerns about both the readiness of market participants and the impacts on incumbent utilities. In December 2012, customers whose average peak demand exceeds 1 MW became eligible to negotiate contracts with retail electricity suppliers other than their local distribution utility. Such customers include electric cooperatives. These contracts became effective in June 2013. Customers that had not entered into a new supply contract continued to be supplied by their incumbent distribution utility. In December 2013, however, the obligation on distribution utilities to supply those customers ended. Those customers were then required to enter into new contracts with retail suppliers (which include distribution utilities) or to accept supply under standard “supplier of last resort” rules. The demand threshold for eligibility for retail supply is to be lowered gradually over time.

In principle, distribution utilities (including electric cooperatives) should not be affected by the introduction of RCOA. Cooperatives serve relatively few customers who are eligible for retail supply (although this will change as the threshold for eligibility is lowered). A customer who switches to an alternative retail supplier is still obliged to pay the full costs of wheeling services provided by the distribution utility. These costs are already unbundled from other costs in regulated tariffs, and there should be no cross-subsidies between these costs and other costs of supply.

In practice, it is less clear that cooperatives will be unaffected. Cooperatives charge a lifeline rate to their smallest residential customers, which is cross-subsidized by other customers. As RCOA extends, it is likely that the base for these cross-subsidies will shrink. This will leave cooperatives in the position of having to either (1) increase tariffs to their remaining non-lifeline customers

or (2) simultaneously reduce access to lifeline rates and increase those rates. The political opposition that these actions will provoke could leave cooperatives facing substantial financial difficulties. Uncertainty about future customer demand as a result of switching will also pose greater risks for cooperatives in contracting for electricity supplies, which could produce major financial losses for the cooperatives or higher costs for their remaining customers.

Thus far, cooperatives evince little concern about the potential risks RCOA brings for them. This may reflect an assumption that few eligible customers will switch suppliers. However, whether this complacency will be justified in the longer term is questionable. As of June 2013, of 909 eligible customers, only 239 had entered into contracts with retail suppliers (Malaya Business Insight 2013). Of these, the majority (151) opted to be supplied by the investor-owned utility, Meralco, which serves Manila and its surrounding provinces. None had opted for a cooperative. Cooperatives have also shown little interest in competing to supply eligible customers—partly owing to respect for territorial boundaries and partly to their lack of the scale and skills needed to compete in this market.

Key Lessons

This mini case study offers two key lessons:

• The loss of customers that are net payers in cross-subsidy arrangements will make open access difficult for utilities in the Philippines.

• It is too early to ascertain the full impact of the introduction of RCOA.

3.4 ConclusionsThis section has described three cases of captive power or backup plants selling surplus power to central grids and two examples of P2P arrangements. Captive power is relatively common, and the three cases reflect some of the drivers for using it:

• Low-cost fuel source and secondary value for a by-product of power generation

• Failure of the grid to supply reliable electricity

• Low-cost fuel source combined with a demand for process heat from cogeneration

P2P schemes are less common in developing countries, with the exception of India. The case study for Maharashtra provides an example of the relationship



between generators and consumers in the type of competitive market that is now reasonably well established in many developed countries. The case study in Zimbabwe is an example of an innovative scheme that attempts to overcome chronic failures by the national company to provide reliable supply. In the Philippines, transparent pricing of electricity to end users should aid the transition to RCOA, but it appears to be too early to tell how the incumbent utilities will be affected by the loss of customers who are currently net payers into the pool that cross-subsidizes small residential consumers.

These five cases provide a series of lessons:

• In markets without major power shortages:

• Captive power can be profitable for a developer when own generation is cheaper than grid supply or produces additional benefits such as heat or valuable by-products.

• Selling surplus from CPPs can improve the economics of captive power from the developer’s perspective by offering economies of scale and by allowing the option of better matching plant capacity and heat load.

• P2P arrangements involving an intermediate trading aggregator can make energy trading more efficient at the national level than direct IPP-to-customer transactions.

• P2P arrangements can create challenges for utilities that are legally obliged to retain significant cross-subsidies between customer categories.

• In markets with major power shortages where the optimal investment choices are not immediately feasible:

• Self-supplying using captive power may be a more expensive option per kWh than grid supply but cheaper than the cost of blackouts.

• Selling the unused capacity of captive or backup power can increase gross capacity for the system that avoids power supply interruptions, and the cost is lower than the costs resulting from output lost during blackouts.

• P2P arrangements can result in increased capacity. Some larger customers are willing to purchase under a P2P arrangement, even though it may be more expensive than grid supply, because it can help ensure a more reliable supply.

• P2P arrangements can be a problem for utilities that are forced to cross-subsidize between large customers or other social customers. But there are solutions—such as the CSS—that compensate utilities and neutralize this problem yet can still leave P2P attractive for producers and consumers.

• P2P arrangements involving an intermediary with a portfolio of contracts can lead to the development of more scale-efficient generation capacity, with more diversified risk, where multiple purchasers and generators can contract for power supply through a grid network, as compared to a series of much smaller and more inefficient bilateral arrangements between small-scale plants and smallish consumers.

One of the primary challenges raised by these case studies is that resulting from cross-subsidies. While the introduction of cost-reflective tariffs is the preferred first step, it is always politically difficult. Other solutions exist (such as transparent levies on P2P transactions, as in India, or direct subsidies from government to the utility), but they are not without difficulties themselves and are complex. Incumbent utilities will often seek to defend their monopolies, so it is important to recognize the difference between genuine concerns about obligations to protect certain customer groups through the tariff mechanism and simple lobbying to protect monopolies.

References

Malaya Business Insight. 2013. “Open Access Starts in the Power Industry.” June 27.

Singh, Daljit. 2005. “Open Access in Electricity Distribution: Assessing the Financial Impact on Utilities.” Economic and Political Weekly 40 (37): 4062–67.

Wärtsilä India Ltd. 2009. “The Real Cost of Power.” Mumbai, India. http://www.wartsila.com/en_IN/media/reports/rcop.


19

4 Mini-grids and Small Power Distribution

Mini-grids and SPD systems are small-scale low-voltage electricity distribution grids, usually operating in rural areas. Mini-grids here refers to isolated “island” systems with their own generation. SPD systems refers to those grids that have a main grid connection and purchase power from the grid utility at a bulk supply tariff. Some SPD systems may also have their own generation capacity which they may use for backup or from which, if the generation plant is low cost, they may sell surplus electricity to the grid utility.

4.1 Economic Drivers Mini-grids and SPD systems provide power to multiple households and/or businesses in a concentrated area. By connecting to a grid, customers can take more power than they can with alternatives such as SHS and possibly receive a more reliable supply for longer periods.

From the perspectives of consumers and operators, where no power supply exists, the choice between developing a mini-grid or developing an SPD system is determined by two questions about tariffs, which are key to commercial sustainability:

• Can the operator charge tariffs that allow it to cover the costs of developing and running the network and earn an acceptable profit?

• Can the customers of the grid afford to pay those tariffs?

From the national (economic) perspective, the decision to allow or encourage mini-grids should be based on whether a mini-grid is more cost-effective, taking account of the full range of monetary and nonmonetary costs and benefits compared with either no power supply (for example, kerosene lamps, pico lighting, or SHS) or connection to the main grid.

An additional factor is the availability of grants and concessional loans from international donors for mini-grids that are based on renewable energy sources. Such grants and loans are not available for grid connections or for SPD systems such as mini-hydro or solar hybrid systems.

4.2 Approach to Cost-Benefi t Analysis The costs of developing and running the network are the costs of installing low-voltage lines for household connections and medium-voltage lines connecting to the power source, as well as the costs of developing or buying the power source (for mini-grids), and operating and maintaining the network and generation, including any power or fuel costs.

From the national perspective, the choice of power source (no electricity, SHS, mini-grid, or main grid) is determined by four factors:

• Proximity and accessibility of the main power grid

• Proximity and cost of other energy sources for localized generation

• Size of the load and consumers’ willingness to pay for electricity

• Nonmonetary benefits not captured by willingness to pay including those related to health, the environment, and other aspects

Developing a mini-grid is optimal from a national perspective only if the cost is lower than the cost of connecting to and taking power from the main grid. The greater the distance from the main grid, the higher the cost of buying power (owing to higher capital costs and technical losses in transmission), and the higher the relative value to consumers of developing their own generation and operating as a mini-grid. Similarly, from the national perspective it is worth developing a mini-grid only if the benefits outweigh the extra capital costs, when compared with kerosene lighting, pico lighting, or SHS.

4.3 Case StudiesThe following sections present six case studies of mini-grids and SPD systems in five countries.

4.3.1 Mini-grids and SPD Systems: Electricity Authority (Cambodia)

Cambodia’s limited national electricity grid was largely destroyed during the civil war in the 1970s. In the



unsettled periods that followed, little was done to rehabilitate or rebuild it, until peace was declared in the early 1990s and economic rebuilding began. At that time, there was no legislative or regulatory regime for the power sector. Power supply was limited to Phnom Penh and a number of provincial capitals. There was no effective government control in many rural areas and no formal provision of services in any such areas. With no access to grid electricity, private development of (predominantly) diesel-powered mini-grids emerged as a response to meet the demand of rural as well as urban populations. The developers tended to be individuals or small family groups, operating informally.

The role of mini-grids was formally recognized when Cambodia promulgated its Law on Electricity in February 2001. The law introduced licensing requirements for mini-grids and other electricity providers and brought providers under the control of the new Electricity Authority of Cambodia (EAC). The EAC requires licensees to meet minimum technical standards before it will offer longer license terms. Only a small number of mini-grids were licensed initially, though many others may have continued to operate without licenses.

Survey data from 2005–06 suggest that only 22 percent of households with access to mini-grid service purchased power from a mini-grid (World Bank/PPIAF 2009). The number of mini-grids declined from an estimated 600–1,000 (licensed and unlicensed) in 2000 to about 120 licensed systems in 2011, as shown in table 10. That year, the largest mini-grid had sales of 6,368 MWh

to 6,508 customers, while the smallest had sales of just 3 MWh to only 92 customers. On average, these mini-grids had about 840 customers.

The decline of mini-grids was due to a range of factors, including

• Increased costs of fuel and limited ability of customers to pay, making some mini-grids unprofitable

• Conversion of mini-grids to SPD systems as the EAC encouraged consolidation and the national utility—Electricité du Cambodge (EDC)—expanded the national grid

From 2009 to 2011, the number of SPD systems rose from 60 to 165. Because the number of licensed mini-grids fell by 42 during that same period, it appears likely that many of the former mini-grids were converted to SPDs (in addition to the new development of at least 23 SPDs).

Regulation of Mini-grids and SPD Systems

Under Article 7 of the 2001 Electricity Law, the EAC has the power and duty to approve tariff rates and charges and the terms and conditions of licensees’ electric power services, except where it considers that those rates or charges and terms and conditions have been established in a competitive, market-based process. Before 2001, mini-grid operators set their own tariffs at levels that enabled them to cover their costs. The regulatory framework put in place by the EAC set tariffs on the basis of the actual costs of each mini-grid. For smaller grids that rely on diesel generation, this basis inevitably leads to very high tariffs—up to $1.00/kWh.

As a means of reducing supply costs and tariffs, the EAC encourages mini-grids to connect to grid supply. It established bulk supply tariffs that provide incentives for mini-grids to build subtransmission lines to connect to the grid, with the tariffs based on distance, as shown in table 11. When mini-grids connect to the grid, the EAC does not immediately reduce their regulated tariffs to reflect their lower costs of supply. Connection thus enables mini-grids to earn surplus cash for a short period (although this surplus is supposed to be invested in expanding and improving the network).

Table 1 0. Trends in Mini-grid Power Supply (2009–11)

Variable 2009 2010 2011

Number of licensees 162 139 120

Number of customers 145,654 123,882 100,832

Average customers/licensee 899 891 840

Installed capacity (MW) 92.3 59.7 39.4

Installed capacity/licensee (kW) 570 430 328

Installed capacity/customer (kW) 0.63 0.48 0.39

Energy generated (MWh) 182,340 116,499 41,021

Energy generated/licensee (MWh) 1,126 838 342

Energy generated/customer (MWh) 1.3 0.9 0.4

Energy sold (MWh) 164,083 105,522 33,267

Energy sold/licensee (MWh) 1,013 759 277

Energy sold/customer (MWh) 1.1 0.9 0.3

Energy expenditure/month ($, at $0.45/kWh)

42.24 31.94 12.37

Energy sold/energy generated 90% 91% 81%

Source: EAC Annual Accounts, ECA calculations in italics.

Table 11. Bulk Supply Tariff for SPD Systems

Distance from EDC grid Bulk supply tariff ($/kWh)

�20 km 0.1305

�15–20 km 0.1355

�8–15 km 0.1405

�8 km 0.1455


21Mini-grids and Small Power Distribution

Co st-Benefi t Analysis

It is important to recognize that unlike with grid extensions, the costs and benefits of mini-grids are very specific to community circumstances (household density, income and load, distance from the grid, and terrain). In some circumstances a mini-grid is the optimum solution, and in others grid extension is.

It is also important to recognize that circumstances change. Mini-grids served by diesel generators may be the optimum solution when oil prices, diesel prices, and income levels are low. As diesel costs increase, solar PV prices change, and income levels rise, some hybrid supply options may be more beneficial than diesel-only mini-grids. Nevertheless, supply costs for isolated systems will inevitably be high, and mini-grids will be optimal in only some situations.

Customers’ Perspective

In 2006, residential customers of mini-grids paid an average tariff of $0.71/kWh (CR 2,923.00/kWh) (World Bank/PPIAF 2009). That was more than three times the tariff at which electricity was sold by EDC ($0.22/kWh) at the time. This suggests that although customers were paying more than they would have had they been supplied by EDC, they were doing so willingly to receive electricity. Table 12 compares the costs to consumers of electricity supply from three sources. It also provides calculations of the monthly costs, based on an average monthly consumption of 27.5 kWh (used for illustrative purposes).9 It suggests that of the electricity supply options, households would clearly prefer supply from the grid if available, followed by supply from an SPD system. The most expensive and therefore least preferred option would be supply from a mini-grid.

It is difficult to assess average monthly expenditures on power as the available data tend to be aggregated across all mini-grids and are not consistent from one mini-grid to another. Consumption from mini-grids will be lower

9 This is a little less than the average consumption calculated from the data for 2011 in table 10, though lower than in previous years. It includes sales to nonresidential as well as residential customers. The average residential sales should therefore be lower than the overall average. It is equivalent to the amount needed to run about three compact fl uorescent lightbulbs, a small television, a radio, and a phone charger each month.

because the tariffs are higher, and consumption from the EAC supply will be higher because the tariffs are lower. For a household, the cost of lighting—using kerosene, candles, and batteries—plus phone charging might be between $4.00 and $8.00/month.10 These households are among the approximately 80 percent who have access to power from mini-grids but choose not to purchase it. Given that the mini-grids charge high tariffs and require households to make regular monthly payments, it is not surprising that the rate of connection is low. Many households choose to use other sources even when they have access to a mini-grid.

In practice, customers taking supply from a mini-grid typically use less than those taking power from the EDC grid. However, the benefits of a grid connection are significantly lessened if the consumer uses electricity only for lighting. For example, three 11 W compact fluorescent lightbulbs might use only 7 kWh/month; at a tariff of $0.71/kWh, a customer taking supply from a mini-grid might pay $5.00/month, making the cost of electric lighting comparable with the cost of kerosene lighting. The additional cost of mini-grid supply might be justified to avoid kerosene fumes, to obtain better-quality light, and to charge mobile phones. In addition, some consumers are clearly willing to pay higher monthly charges in order to use electricity for television, radio, and other purposes.

Developers’ Perspective—Mini-grids

The mini-grids were developed voluntarily by the private sector, without subsidies, and it can be assumed that they were financially attractive when they were developed. As with any commercial enterprise, some have been successful and others not; some may no longer be commercially viable. The declines in both the number of mini-grids and the number of customers supplied by mini-grids were driven by several factors, among them a decline in profitability as fuel costs increased.

With fuel costs of $0.75/liter11 (as of 2005–06), generation production assumed to be 2.5 kWh/liter, and a connection cost of $60.00 for the low-voltage network (Economic Consulting Associates’ estimates), a developer would more or less break even at a discount rate of 10 percent if the tariff were $0.46/kWh. The average price of

10 Based on surveys noted in Tenenbaum et al. (2013). Though the surveys did not include Cambodia, spending on lighting and other services is unlikely to differ signifi cantly. An energy survey conducted in Cambodia in 2006–07 (UNDP Cambodia 2008) showed that in one province with low levels of electrifi cation, 75 percent of rural households used kerosene for lighting and 84 percent used batteries.

11 From an energy survey conducted in Cambodia in 2006–07 (UNDP Cambodia 2008).

Table 12. Cost of Electricity, Consumer Perspective

Variable Mini-gridSPD system

Direct grid supply

Average tariff ($/kWh) 0.71 0.28 0.16

Cost per month ($) 19.50 7.70 4.50



$0.71/kWh for power from mini-grids suggests that the average costs are higher than calculated here or that the mini-grids earn a substantial margin (which seems less likely).

Developers’ Perspective—SPD Systems

The analysis of SPD systems suggests that they may be financially viable only for larger networks within a short distance of the EDC grid, under the following assumptions:

• The bulk supply tariff is $0.146/kWh (equivalent to $0.16/kWh delivered to the end user after allowing for distribution losses of 10 percent).

• The SPD system covers the cost of connecting to the main grid.

• The regulated tariff that SPD system can charge end users drops to $0.28/kWh.

The analysis estimates that an SPD system less than 5 kilometers (km) from the EDC grid with 500 customers consuming an average of 27.5 kWh/month would have costs of $0.25/kWh and revenues of $0.28/kWh. However, the same SPD system with only 100 customers would have costs of nearly $0.50/kWh.


EDC plays no role in mini-grids. In SPD systems, if EDC is not responsible for the costs of connecting them to the main network then it should be happy to connect them, provided that the bulk tariff (between $0.131 and $0.146/kWh) exceeds the cost of bulk supply. This analysis assumes that the bulk supply cost is about $0.10/kWh, which suggests that the bulk supply business is profitable for EDC. EDC has no ambition to be responsible for supplying rural communities and does not regard the SPD systems as a threat.


From the perspective of the national economy, the cost-benefit analysis suggests the following:

• For a small low-income community, if the distance to connect to the main grid exceeds about 4.5 km, then connection to the main grid and the creation of an SPD system is not the most cost-effective solution. If households would like electricity, a mini-grid (or perhaps some other solution) is more effective.

• For larger communities and/or higher-income communities, connecting to the main grid becomes much more attractive from the national perspective.

For example, the assessment here suggests that for a community of 500 households with an average demand of 27.5 kWh/month, a grid connection is optimal for distances up to about 23 km.

• Electricity supply from mini-grids for lighting and small-scale use (for example, mobile phone charging) is more expensive than traditional forms of lighting and phone charging. Nevertheless, consumers have demonstrated their ability and willingness to pay $0.71/kWh and more in order to obtain the additional convenience and other benefits that result from connection to a mini-grid. The economic benefits therefore exceed the costs.

Table 13 provides one example of the cost-benefit analysis of grid connection versus isolated mini-grids.



This case study offers three key lessons:

• Mini-grids can be viable when tariffs reflect costs and customers are willing to pay those (high) tariffs.

• Mini-grids are the optimal solution under some circumstances, just as connection to the main grid is optimal in other circumstances. Because circumstances change, mini-grids will not always be the optimal solution.

• Mini-grids can successfully become SPD systems when extension of the main grid engulfs mini-grids.

Table 13. Cost-Benefi t of Connecting to the EAC Grid

VariableValue ($/kWh)

Mini-grid

Generator capital cost 0.08

Fuel cost 0.33

Distribution cost (low cost, $6 per connection per year) 0.02

System operation and maintenance costs 0.01

Overall costs 0.44

SPD system, with EAC connection

Wholesale purchase costs from EAC 0.10

Medium-voltage line (4.6 km at $15,000/km, 33 MWh/year)

0.26

Operation and maintenance on medium-voltage line 0.05

Distribution cost (low-cost, $6/year/connection) 0.02

Operation and maintenance on SPD network 0.01

Overall costs 0.44

Additional cost (1)/cost saving (2) 0.00

Note: Assumes 10 percent discount rate, 30-year life of assets, 100 customers, and total consumption of 334 MWh/year.



4.3.2 Mini-grids: Various Developers (Sri Lanka)

In Sri Lanka, before the expansion of the national power grid, mini-hydro mini-grids were developed extensively to support the fast-growing plantation economy.12 With the expansion of the grid in the 1960s, their use diminished significantly, to be renewed when the oil crisis of the 1970s made alternative energy sources more affordable. During the 1980s, the introduction of off-grid technologies such as efficient stoves and solar PV by the Intermediate Technology Development Group (ITDG) and the CEB resulted in improved general acceptance and wide replication. In subsequent years, state activity in renewable energy concentrated on grid-connected applications, and nongovernmental organizations (NGOs) such as ITDG stepped in to fill the void. From the early 1990s onward, village hydro has maintained steady growth in both installed capacity and connected homes, as demonstrated in figure 1.

Mini-grid development in Sri Lanka has been characterized by variety in the donors and agencies involved in the program and specific projects, which was a result of

12 Much of the content for this section was adapted from Wickramasinghe (2005).

Table 14. Summary of Cambodia Mini-grids Case Study


Customer Mini-grids are expensive ($0.71/kWh or $19.50/month) compared with SPD systems ($0.28/kWh or $7.70/month) or direct main grid supply ($0.16/kWh or $4.50/month) but may be preferred to kerosene for additional functions (such as television)

Developer Mini-grids were profitable before alternative options became available; increases in fuel costs and proximity to main grid made many less profitable; where near enough to main grid, can remain viable by sourcing power from grid as SPD system

Can break even at discount rate of 10 percent if tariff were $0.46/kWh; average price of $0.71/kWh suggests higher average costs than calculated here or substantial margin earnings (less likely)

Utility EAC not involved in mini-grids or directly in rural electrification; would favor SPD systems if it can supply them in bulk for tariff of $0.131–0.146/kWh, using electricity that costs $0.10/kWh on average

Nation At connection distance from main grid of more than 4.5 km, main grid connection and SPD creation are not most cost-effective solution; grid connection optimal for a community of 500 households with average demand of 27.5 kWh/month at distances up to about 23 km; to obtain electricity, villagers may choose to pay high tariffs to mini-grid

0

1,000

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2,000

3,000

4,000

5,000

6,000

7,000

8,000

1992

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1995

1996

1997

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2001

2002

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2004

Con

nect

ed h

omes

0

250

500

750

1,000

1,250

1,500

1,750

2,000In

stal

led

capa

city

(kW

)

Connected homes, cumulative Installed capacity (kW), cumulative

FIGURE 1 GROWTH OF OFF-GRID-HYDRO SECTOR



the absence of any formal state activity, particularly in financing. Most projects implemented during this period lacked any form of quality assurance, especially in site-specific components such as civil works and the power distribution network. However, these projects served the purpose of providing the necessary background and capacity for the large-scale mobilization of off-grid projects facilitated by the Energy Services Delivery (ESD) project. The ESD project paved the way for the ongoing Renewable Energy for Rural Economic Development project, which was formulated to cater to the growing demand for finance for renewable energy projects. Through off-grid hydro, 1.44 GWh of electrical energy had been delivered to rural homes by 2003; table 15 presents the breakdown.

The Dothaluoya village hydro project, which was implemented in the final stages of the ESD project, illustrates a typical result. Dothaluoya is a relatively large village of 167 homes, situated in Ratnapura division in the Sabaragamuwa province, on the southwest slopes of the central mountains. The main source of income is tea cultivation, carried out on small plots of 0.1–0.5 hectare. The distribution of household income in the village appears in figure 2.

The project was formulated with a design capacity of 32 kW to provide electricity to all 167 homes, averaging 200 W per home. Following political interference that forced some families to withdraw support, 89 homes were selected for connection. In addition, the plant had to be redesigned to accommodate lower head than initially expected, meaning that only 26.5 kW of power

was actually developed; however, owing to the reduction in households, in the new arrangement, each home was entitled to 300 W.

Utilization of the developed plant was very low; households that had been optimistically expected to create a demand of more than 200 W actually demanded 80 W on average, amounting to a village peak demand of only 7.1 kW. Had this been known before implementation, the investment could have been reduced by more than 50 percent, resulting in a much lower cost. Under such conditions, the proportion of the average load to the plant capacity could have been much improved from the present annual average of 12 percent.


The beneficiaries of the project were also the developers. With the national grid 5 km away, villagers had been

Table 15. O ff-grid Projects Developed Under Various Phases

Project phase Years ProjectsConnected homes

Installed capacity (kW)

Before ESD Project 97 1,003 175

ESD Project 35 1,732 350

RERED Project (completed)

51 2,293 521

RERED Project (in progress)

49 2,229 541

Note: ESD � Energy Services Delivery, RERED � Renewable Energy for Rural Economic Development.

0

5

10

15

20

25

<1,5

00

1,50

0–1,

999

2,00

0–2,

499

2,50

0–2,

999

3,00

0–3,

499

3,50

0–3,

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0–4,

499

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499

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00–1

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>11,

000

Monthly household income range (SL Rs/month)

Num

ber

of h

omes

FIGURE 2 DISTRIBUTION OF MONTHLY INCOME IN DOTHALUOYA



using kerosene as the main source of lighting and lead acid batteries for additional lighting and television. Lead acid batteries usually were carried in on foot, mostly by women, over a distance of about 5 km. Table 16 provides estimates of the average expenditure on energy before and after the project was developed. At an exchange rate of $1:SL Rs 127, monthly expenditures were approximately $5.74 before and $6.42 after the project. Households now spend considerably less on kerosene and batteries. Fixed payments to the mini-grid scheme cover operations and maintenance as well as a portion of the commercial loan repayment.

The beneficiaries pay a slightly higher amount for energy but enjoy clean grid-quality energy, with better reliability, no time lost in charging batteries, and health benefits from much reduced kerosene use. However, this electricity is consumed at a much higher price than that of power supplied to customers connected to the CEB grid. Low-usage customers of the main grid benefit also from a subsidy on delivered energy through the lifeline tariff, which customers of an off-grid scheme cannot access. Table 17 presents a cost comparison based on the average monthly consumption of a home in Dothaluoya, showing that off-grid consumers pay nearly six times more for a unit of energy than grid-connected consumers do. The cost of electricity is $0.08/kWh for CEB customers and $0.56/kWh for off-grid customers, which explains why rural households are generally very keen to connect to the national grid. The analysis is based on an average village consumption of 954 kWh/month, which equates to a monthly consumption per home of 10.7 kWh/month.13

13 Based on a load factor of 5 percent, measured just after commissioning. The loads may have grown to a plant factor of about 25–30 percent within a few years, but no measurements have been taken to support this fi gure.

One of the risks that is difficult to quantify is the inability to insure village hydro assets, owing to their ownership structures and the marginal viability of their customers. If a lightning strike ruins a hydro plant, the mini-grid must collect cash from its members in the community to finance the repair. By contrast, the CEB manages grid electricity supply without any additional costs to consumers.


In this community-based scheme, the developer and the consumers are the same people. The project was managed by a community-based organization called the Dothaluoya Village Hydropower Consumers Welfare Society. After the plant was commissioned, the society appointed a subcommittee to inspect all homes to ensure the internal wiring undertaken by villagers met the specifications. It appointed another permanent committee, known as the audit committee, to ensure that no home is connected before settling all dues. The audit committee also acts as a flying squad to inspect homes suspected of using high-energy-consuming devices; it has the authority to disconnect homes for nonpayment of dues and for misconduct.

Table 18 details basic project components and actual costs incurred in implementation. Professional services provided by the consultants were directly reimbursed by the ESD

Table 16. Es timated Household Expenditure Pre- and Post-project

Energy source

Monthly expenditure on energy (SL Rs/household)

Before project After project

Kerosene 187.89 9.39

Dry cell 117.07 58.54

Lead acid battery charging 52.65

Loss of labor 308.34

Lead acid battery replacement 65.76

Loan repayment 650.00

Operations and maintenance 100.00

Total 731.71 817.93

Table 17. Com parison of Grid and Off-grid Electricity Costs

Variable CEB customer Off-grid customer

Fixed payment 60.00 750.00

Energy payment for 10.7 kWh/month

32.00 0

Total 92.00 750.00

Cost of energy (SL Rs/kWh) 8.60 70.00

Table 18. Cost Estimate for Project Components

ComponentCost (SL Rs)

Share of total (%)

Civil works 1,012,567a 30.1

Electromechanical equipment 1,170,000b 34.8

Power distribution system 743,000c 22.1

Project design 50,000 1.5

Testing and commissioning 47,556 1.4

Contingencies 290,000 8.6

Working capital 50,000 1.5

Total cost 3,363,123 100.0a This number was from records kept by the village, but the actual amount is estimated to be higher. b This was an estimate; actual costs were about SL Rs 160,000 higher. c Excludes the cost of poles, which were obtained by felling nearby trees.



project administrator and are not included but could be on the order of SL Rs 1–1.25 million. The project cost SL Rs 3.36 million (approximately $26,000).

Villagers supplied much of the labor voluntarily. This cost component includes the value of sand mined from a stream and rubble quarried from granite deposits nearby. These inputs from villagers often determine the viability of an off-grid project, as sweat equity is a prominent component of the project financing plan; these costs are included in the civil works component in table 18. Records were kept to account for the contributions of members of the community who chose to assist in the development. If a particular home failed to make required contributions on time, the executive committee imposed a penalty.

The project financing plan relies on a diverse array of funding sources, as shown in table 19. The bank loan was obtained from the Balangoda branch of the Hatton National Bank. Funds from the World Bank’s Global Environment Facility (GEF) were channeled through a refinance scheme.

Nearly half of the project cost was met from grants. In addition, the cost recovery plan of the scheme does not include a return on the sweat equity invested by the community, which suggests that it was not “invested” on commercial terms. The capital subsidy provided by the grant components appears to be quite low compared with the grants afforded to a few selected grid extension projects in the same province, as shown in figure 3.

By contrast, at the time the scheme was developed, the lending rate offered to village societies for the nongrant component was extremely high, about 26 percent. The larger banks eventually moved out of the village hydro sector, but the rural development banks that filled the vacuum charged even higher rates.

The operations and maintenance (O&M) costs of the scheme are understandably very low. The office holders usually serve for a period of one year on a voluntary basis. The plant operator, trained by the developer, receives a monthly wage from the society of SL Rs 3,000. With low O&M costs, the scheme was able to make contributions to the commercial loan repayments. If repayments were required on the loan and all grants on the same basis as the commercial loan, the monthly power costs would total more than SL Rs 2,000, which is considerably more than their previous monthly expenditure and would form a very

Table 19. Proje ct Financing Plan

Source of fundingCost (SL Rs)

Share of total (%)

Cash equity from villagers 356,000 10.5

Sweat equity from villagers 675,000 19.9

Provincial council grant 600,000 17.8

Bank loan utilized (SL Rs 1.59 million approved limit)

750,000 22.1

GEF grant 1,007,000 29.7

Total 3,388,000 100.0

0

50,000

100,000

150,000

200,000

0 50 100 150 200 250

Families per project

Gra

nt (

SL

Rs/

hom

e)

Dothaluoya Grid extensions

FIGURE 3 GRANT RECEIVED PER CONNECTED HOME



large part of their monthly income. This would equate to an energy cost of more than SL Rs 85.00/kWh, or nearly $0.70/kWh. This calculation does not take into account any return to equity providers.

In summary, the community is able to cover the costs of running the mini-grid given the project structure but only because of the grant and uncompensated sweat equity financing. It is important to note that some community-owned schemes began to fail because accounts were not maintained or costs were not recovered from the community. Many projects have been taken over by entrepreneurial members of the community, resulting in efficiency improvements as well as maintenance of service reliability.


This mini-grid project has not involved the CEB (the national utility). Since the development of mini-grids throughout Sri Lanka, the CEB has begun extending its grid and connecting many of the villages. Given the low consumption by village households and the subsidized tariff that grid-connected customers pay, grid extension very rarely makes financial sense for the CEB. For every customer that the CEB connects at the lifeline tariff, it must source additional revenue from the net payers in the cross-subsidy. It could request a tariff adjustment to meet its revenue requirement, so that its position is covered.

When the CEB has connected villages to the main grid, it has installed connections directly to the houses, preferring to install its own low-voltage lines rather than connect to the established mini-grids because it does not have sufficient confidence in the quality of the installations. One of the challenges mini-grid developers have faced is understanding the CEB’s intentions for grid extension. Although the CEB has had plans to expand the grid, these plans were not always made clear to developers of off-grid schemes.


Table 20 presents an analysis of the economics of connecting customers to the main grid compared with the cost of mini-grids. For the mini-grid, the cost is assumed as the total project cost (SL Rs 3.4 million) plus an estimate for project development costs,14 converted to a monthly payment over a 10-year period (the estimated life of the project) at an economic discount rate of 10 percent, plus

14 The cost of engaging consultants to assist in the development, which was not included in table 14, is estimated at SL Rs 1.25 million.

all monthly operating costs, all divided by the average consumption of 954 kWh/month. For the main grid supply, the cost is the annualized capital cost converted to a monthly cost (assuming a 10 percent discount rate and a 30-year useful life) for the cost of connecting the village, plus the average cost of bulk supply (calculated by the regulator), currently estimated at SL Rs 13.74/kWh.

This analysis suggests that, at the national level, it would not make sense to connect the village to the grid if households continue to use only 11 kWh/month. (Note also that the cost assumed for the medium-voltage grid connection is very low by international standards.) Although the unit cost of energy (SL Rs 13.74/kWh) is much lower when connected to the grid, the costs of connection at this distance and this low volume of consumption make the total cost high. Connecting to the national grid brings no intangible benefits (for example, to health or the environment) over connecting to a mini-grid; however, value will be added in enabling consumers to use additional appliances, to use electricity for productive purposes, and to use more electricity (that is, additional “consumer surplus”). In some instances, this value is likely to justify grid connection, but the extent to which demand is constrained by the capacity of the mini-grid in this village or in Sri Lanka in general is not clear.

Table 20. Cost-B enefi t of Connecting to the CEB Grid

Variable Value

Mini-grid

Total development costs (SL Rs ’000) 4,650

Monthly operating expenses (SL Rs) 5,000

Total monthly cost of mini-grid (SL Rs) 46,106

Cost per month per household (SL Rs) 518

Cost per kWh (SL Rs) 48

CEB connection

Medium-voltage line (5 km at $15,000/km) 75,000

Transformer ($) 5,000

Connection cost per household ($) 60

Number of households 89

Total connection cost ($) 93,350

Total connection cost (SL Rs ’000) 11,855

Cost per month per household (SL Rs) 1,178

Cost per kWh (SL Rs) 110

Total power cost for grid connection per kWh (SL Rs) 124

Additional cost per kWh for grid connection (SL Rs) 76

Note: Assumes 10 percent discount rate, 30-year life of assets, 89 customers, and total consumption of 954 kWh/month.






• Unsurprisingly, external subsidies can make mini-grid projects viable for communities.

• Tariffs resulting from subsidized mini-grid developments offer significant benefits over the costs of kerosene use, but their comparison to main grid costs depends on the main grid tariff and particularly on whether grid electricity supplied to rural communities is subsidized (as it often is).

• Connecting low-consumption and remote villages to the main grid may be costly to the utility unless it is allowed to adjust tariffs to accommodate the new customers. It rarely makes sense for the nation as a whole unless electricity consumption is expected to increase significantly.

4.3.3 Mini-grid: Masurura (Tanzania)

The Masurura mini-grid project is a solar PV–based mini-grid developed in northern Tanzania by Carbon X, a Tanzanian-registered private company. In 2010, Carbon X

won the Lighting Rural Tanzania competition hosted by the country’s Rural Energy Agency and the World Bank. Carbon X invested the $100,000 prize plus another $50,000 in the Masurura project. It was developed as a pilot, with no intention to recover the capital costs.

Masurura sources its power from a centralized solar farm, with connections running to households in the village. Carbon X uses a smart grid to share power between homes (primary load) and centralized water-pumping stations (secondary load) during off-peak hours and when there is excess unused power in the mini-grid.

Through various financing options, customers in the village purchased an installation package that included a ready-board, a load-limiting meter, and two to four energy-efficient LED (light-emitting diode) lights. The ready-board provides a circuit breaker and electrical outlets. Rather than measuring the total units of electricity used, the load-limiting meter sets a maximum capacity that customers can use. Use of such a meter means that customers pay in advance for their electricity, thereby reducing Carbon X’s risk in collecting tariffs.

Customers choose between 50 W, 100 W, and 200 W supply, for 18 hours per day, at costs of TSh 12,000, TSh 24,500, and TSh 50,000/month ($7.30, $14.90, and $30.30/month). A 50 W connection is just enough to power a 14-inch television plus one lightbulb; to use more lights or a radio, the television must be off.


Carbon X’s survey of Masurura customers revealed that even the poorest households spend about TSh 20,000/month on energy (approximately $12.00/month), as detailed in table 22. Many households also run a radio

Table 21. Summary of Sri Lanka Mini-grids Case Study


Customer Slightly higher cost ($6.42 with mini-grid, $5.74 with kerosene and batteries), but benefits of clean energy, increased reliability, no time lost for charging batteries, and health improvement from lower kerosene use; cheaper cost ($0.088/kWh from the CEB—highly subsidized—and $0.56/kWh from the mini-grid) favors grid connection; also grid connection means virtually no restrictions on appliance types

Developer Community covers operating costs through grant and uncompensated sweat equity financing; many community-owned schemes have been taken over by entrepreneurial members, resulting in efficiency improvements

Utility Given low consumption in these villages and subsidized tariff for grid-connected customers, grid extension very rarely makes financial sense, except when the CEB can adjust tariff structure to accommodate loss-making customers

Nation No reason to connect village to the grid if households continue to use only 11 kWh/month; despite lower unit cost (SL Rs 13.74/kWh), costs of grid connection at this distance and low consumption volume make total cost high; no intangible benefits (health, environment) of grid connection but added value in ability to use more appliances, use electricity for productive purposes, and use more electricity

Table 22. Custome r Monthly Expenditure Before and After Carbon X Project

Variable Value

Kerosene lamp

Hours of use per day 4

Liters used per month 5–7

Cost of kerosene (TSh/liter) 2,500

Cost of kerosene per month (TSh) 12,500–17,500

Mobile phone charging

Charges per month 15

Cost per charge (TSh) 300

Cost of charging per month (TSh) 4,500

Total cost per month before Carbon X project 17,000–22,000

Cost per month for 50 W SHS from Carbon X 12,000



using dry-cell batteries, which are very expensive. Some of the better-off families have other appliances. With the mini-grid, the poorest households can save nearly 40 percent in monthly energy expenditures, while enjoying cleaner, better lighting and more convenient phone charging (having previously needed to leave their homes to charge their phones).

Initially, Carbon X required a connection fee of TSh 40,000 and provided the first two months of electricity free. Now a new customer must pay for wire from the nearest pole, plus internal wiring (including a circuit breaker, which the company requires), at a total cost of about TSh 30–40,000 ($18–24). With monthly bill savings of at least $4.70/month, the connection costs are covered in four to five months.

In the absence of reliable data on energy consumption per household, it is not easy to compare the costs of supply from this mini-grid with the costs of grid supply from Tanesco, the national utility. Table 23 presents an indicative analysis of the comparative costs of the Carbon X project and a hypothetical Tanesco connection. This analysis shows that if the village had access to the national grid or any grid with similar tariffs, customers would likely prefer grid supply over mini-grid supply. The main grid also has no load limit. Although in theory the national grid offers 24-hour supply, in practice load shedding is routine, so it is possible that the grid supply could be less reliable than the mini-grid supply.


Information supplied by Carbon X details the total project costs at $80,000, broken down as shown in table 24. Carbon X discourages large customers. It has 37 customers: 30 on the 50 W plan, 4 on the 100 W plan, and 3 on the 200 W plan. Monthly income is estimated

to be TSh 608,000, or $380. This is much lower than the commercial breakeven monthly equivalent of $1,290/month (which is based on the capital expenditure amount, a conservative 15 percent discount rate, and a 10-year payback period). Since the development of the project, the cost of solar power systems has declined significantly, from the reported $2.60/W to about $0.68/W. If the project were developed today, the total capital expenditure would be $58,880. As a monthly payment on the same terms just noted, this would equal $950, exactly two and a half times the current monthly income. In fact, removing the costs of the panel units altogether and looking only at the other costs (batteries, inverter, meters, poles, wires) still leaves a monthly payment of $830, far in excess of the monthly income. As the system is modular, scaling it up with higher numbers of customers or heavier loads will not significantly increase profitability.

Although the Masurura project is not intended to generate a return on capital, Carbon X does intend to roll out similar projects that do make profits across Tanzania. From the analysis here, it is not clear that this will be possible unless the company finds significant further efficiencies in service delivery, charges much higher tariffs, or continues to use grant funding.


Tanesco’s current tariff structure requires both cross-subsidies and external subsidies to support a low “lifeline” tariff for the lowest-consuming households. Given the low overall consumption levels and high cost of connection, if Tanesco were to connect this village to the main grid, the current tariff structure would lead to losses for each customer connected and each unit of electricity supplied. As a result, Tanesco has little reason to oppose the private supply of power in this case.


If the mini-grid at Masurura had been financed using Tanzanian resources, even if allowance is made for the health and environmental benefits of electrification, the

Table 23. Monthly Expenditure, Carbon X Project and Tanesco Connections

Variable Value

Carbon X

Assumed load limit cap (W) 50

Average load (W) 35

Hours of usage per day 12

Total power used (kWh) 12.6

Charge per month 952

Equivalent charge per unit ($) 0.60

Tanesco connection

D1 domestic tariff (TSh/kWh) 60

Equivalent per unit charge ($) 0.04

Table 24. Capital E xpenditure Breakdown for Masurura Mini-grid

Variable Value

Total units purchased (kW) 11

Cost per W ($) 2.60

Cost of solar panel unit ($) 28,600

Other costs: Hoppecke batteries, inverter, meters, poles, wires ($)

51,400

Total ($) 80,000



scale of the real costs and the low income levels of the community would probably not have made a mini-grid the least-cost solution. However, given that the Lighting Africa grant would not otherwise have been used for activities in Tanzania and that the project provides intangible health and environmental benefits, the project does appear to have a net economic benefit over kerosene lighting. It is not certain that it would have a net economic benefit over pico solar lighting or similar distributed lighting products.




• Solar mini-grids can offer significant benefits over kerosene consumption, but the business model may not be sustainable.

• In low-consumption rural communities, it may be difficult to justify the costs of mini-grids without higher tariffs, which such communities cannot afford.

• Large external subsidies can make mini-grid projects economically attractive, but internal subsidies would not be economically justifiable.

4.3.4 SPD System/Mini-grid: Rift Valley Energy (Tanzania)

The Rift Valley Energy (RVE) project in Tanzania was developed by a subsidiary of Rift Valley Holdings (RVH), a Zimbabwe-based company providing agriculture, forestry, and related services, including energy. Development began

in 2004. It took six years of negotiation with Tanesco to formalize a small power purchase agreement (SPPA), before development on the ground could begin in 2004.

It is debatable whether this project is an SPD system or a mini-grid. The intention was to supply power for RVH’s Mufindi Tea and Coffee Company (MTC), in the Mufindi district of the Iringa region of the southern highlands. The motivations for RVH are those identified in section 4.1. MTC had access to the national grid, but the power supply it received was very unreliable, owing to Tanesco’s repeated load shedding. MTC’s operations required uninterrupted supply. MTC also had advantageous access to a renewable fuel source for power generation within reasonable proximity to its plant: the Mwenga River, with sufficient volume and head for a 4 MW run-of-the-river mini-hydro plant. RVE also can sell 80 percent of its power to Tanesco at a tariff agreed through the SPPA.

As the power lines from the mini-hydro plant ran through and close to 14 nearby villages, RVE decided that it would be a good investment to extend power to the villages, connecting 26,000 households. RVE has established a charging system whereby customers pay for their electricity in advance using their mobile phones. This model reduces not only collection costs but also the risk of nonpayment.

Although the regulator has allowed RVE to charge a cost-reflective tariff, customers in the villages demanded the equivalent grid-connected Tanesco tariff (D1 domestic tariff), which is only TSh 60/kWh ($0.0375/kWh). As this is a subsidized tariff, even a very efficient development would struggle to recover its costs. In RVE’s case, it cannot cover the operating costs incurred in serving these customers through the revenue it generates from sales. RVE is unsure whether the customers could afford a cost-reflective tariff. However, it hopes that customers will consume more power, which will make it easier to move them to a higher tariff category, even if the customers prefer the Tanesco tariff structure. A key proposition is that village customers will not only continue their domestic use but will develop businesses using power, capitalizing on the fairly reliable mini-hydro power source.

Fortunately, the viability of the Mwenga mini-hydro does not rely on the profitability of sales to the villages. The project sells 80 percent of its power to Tanesco under the SPPA. RVE is able to operate as an SPD system only by effectively covering the losses sustained on the village side of its operations through the profitability of its sales to the main grid. In addition, RVE does not need to recover its full capital costs, as more than 50 percent of its capital costs in development were covered by grants. Although

Table 25. Summary of Masurura Mini-grid Case Study


Customer Poorest households save nearly 40 percent in monthly energy expenditures, and enjoy cleaner, better lighting and more convenient (in-house) phone charging; connection costs covered by monthly savings in four to five months

Developer Monthly income estimated to be less than 30 percent of breakeven requirement based on capex costs provided; reduced costs of solar panels make monthly income 40 percent of breakeven requirement; not counting panel costs, monthly income is 46 percent of breakeven requirement

Utility Does not serve mini-grid customers; with current tariff structure, would make a loss on every customer served

Nation Significant international financing gave mini-grids a net economic benefit over kerosene use; not the case if it had been funded with national resources



RVE would like to replicate this project, it would not do so without similar grant funding.

Key Lessons

This mini case study offers three key lessons:

• Although regulations may allow a mini-grid developer to charge a cost-reflective tariff, customers may not be willing to pay those tariffs, particularly if they can make comparisons with the (low) tariffs of the main utility.

• Having the main utility as a major off-taker assists profitability.

• A mini-hydro mini-grid project may be feasible only with significant amounts of soft funding.

4.3.5 Mini-grids: Micro-hydro Schemes (Mozambique)

Two micro-hydro mini-grid schemes have been expanded in Mozambique’s Manica province with support from the European Union, the ACP Energy Facility, Practical Action, and local agencies. Both schemes were established by farmer entrepreneur-operators to power either a small maize mill or a basic electricity generator housed in the same powerhouse. Power distribution was limited to just a few households that could pay the rates set by the entrepreneurs.

The machinery used for generation was very simple, and works were mainly dug by hand by the entrepreneurs. The costs of these schemes were reported as being low but largely excluded costs for the capital expenditure. Funding from the development agencies was used to replace the generators, upgrade some of the water supply infrastructure, and connect houses to the power supply. Tariffs paid by the households were for fixed amounts; power consumption was not measured. As the entrepreneurs sold the power directly, they had the right to supply it when they chose; the arrangements with customers did not address reliability.

Little information is available on the financial arrangements of the two schemes, except that the entrepreneurs were able to repay some of the loans advanced by the development partners. However, these repayments were only a small component of the total amounts the entrepreneurs received. The fact that they made loan repayments suggests that they at least covered their operating costs. The entrepreneurs did not charge for their time and labor so very few operating costs needed to be recovered, in comparison with other schemes.

As a return on their investment, the entrepreneurs received electricity at no additional cost. In one village, one entrepreneur used the water outflow from the powerhouse to irrigate crops, including sugarcane and high-value horticultural products, and was developing a fish farm. It is not clear whether the return generated from these activities provides an adequate commercial return. These two mini-grids are not examples of successful APS.

Key Lessons

This mini case study offers two key lessons:

• Revenues from communities can cover tangible operating costs for the entrepreneur/developer but may not cover the costs of their time or provide a return of or return on the investment.

• To be viable, community schemes may be very reliant on soft funding.

4.3.6 Mini-grids: Western Power (Papua New Guinea)

Western Power owns and operates 30 diesel mini-grids and a micro-hydro mini-grid, each with a capacity of 30–40 kVA and 50–200 customers, spread along the main road in Western province in Papua New Guinea. Since 2011, the company has operated the mini-grid in Kiunga, the local district center, which the provincial government formerly ran. In recent years Western Power has started installing SHS on a subsidized basis. The company has over 3,000 customers, almost all of them residential, and estimates that it serves about 22,000 people. To retain its focus on small-scale supply to remote areas, it sets a self-imposed generation limit of 10 MW.

Western Power is owned by Sustainable Development Program Ltd (SDPL), a company registered in Singapore but owned by the government. Recently, the government announced that SDPL would soon move back to Papua New Guinea and incorporate there. SDPL owns the state’s interest in the Ok Tedi copper and gold mine in Western province. Western Power is one of a number of programs through which SDPL provides a share of the mine’s revenues to the province.

Western Power depends entirely on SDPL for funding. Although it charges a tariff of K 0.80/kWh ($0.35/kWh), that is insufficient to cover even its operating costs, which are estimated to be as high as K 6.00/kWh ($2.50/kWh). The use of diesel and the very difficult terrain make transport costs extremely high. There are no all-weather roads, few dirt roads, and only some river



transport; most equipment and supplies are flown in by air freight. SDPL covers all capital costs, which are extremely high. There is no ready source of gravel in Western province, for example, so construction of facilities (poles, mini-hydro, etc.) requires bringing gravel in by air freight.

Although Western Power is licensed by the regulator, the Independent Consumer & Competition Commission exercises little regulatory oversight. The commission has discussed tariffs but does not formally control them because Western Power charges tariffs similar to those of the main utility (PNG Power), which are well below cost.

The Western Power mini-grid is not an example of a sustainable APS.

Key Lessons

This mini case study offers two lessons:

• Mini-grids in remote areas can be costly to develop and operate.

• Even relatively high tariffs, which likely stretch the budgets of consumers, may be insufficient to cover the high costs of supplying power in remote areas.

4.4 ConclusionsThis section has highlighted a number of issues related to the affordability of power to consumers, the commercial sustainability of mini-grids for operators/developers in the absence of capital subsidies, the circumstances in which mini-grids are the optimal solution for rural electrification, and whether SPD systems are a good way to approach grid connection.

The affordability of tariffs charged by mini-grids is directly linked to their commercial sustainability:

• If customers can afford a cost-reflective tariff, then such schemes can be commercially sustainable. However, with the exception of those in Cambodia, all the mini-grids featured in the case studies have received capital subsidies from international sources.

• In Cambodia, reasonably high load density and income levels, a liberal licensing and tariff policy, and moderately low costs of fuel allowed the mini-grids to be commercially sustainable.

In each country, in different parts of each country, at different times, and at different stages of economic development, the optimum solutions to rural electrification will vary. Other than in Cambodia, most of the projects examined were developed during the

past 10 years or so. Cambodia’s mini-grids began to be developed in the 1990s. At that time, rural incomes were lower, diesel fuel costs were lower, and the EDC grid did not reach far into the rural areas.

But although the example of Cambodia shows that mini-grids can be both affordable and commercially sustainable, it is not clear whether as many mini-grids would have been developed in Cambodia today. The costs of diesel have increased dramatically over the past decade. Although this increase would make kerosene lighting more expensive, it would make the cost of electricity from diesel mini-grids even more expensive. Renewable energy technologies (such as solar) might lower those costs, but even with solar-diesel hybrid systems the cost of electricity from a mini-grid today would still be very expensive relative to the cost of diesel-based electricity in the late 1990s.

Cambodia now has fewer mini-grids, and the development of new mini-grids has slowed. Growing income levels, resulting in rising demand for electricity-using services that only a main grid connection can provide effectively, and decreased costs for connecting brought about by the extension of the EDC network have changed the economic balance in favor of connection to the main grid.

From a national perspective, connecting mini-grids to the main grid (including the creation of SPD systems) will be the best solution for many villages in Cambodia today. In some cases, however, the decisions to connect mini-grids to the main grid and to undertake electrification by means of grid connection will be motivated by tariffs because the tariff for grid-connected SPD systems is lower than the tariff for mini-grids.

Across all countries, rising levels of income can tip the economic balance in favor of mini-grids compared with non-grid solutions (such as kerosene) or in favor of grid connection rather than mini-grids—or mini-grids rather than non-grid solutions. For example:

• In poorer communities, the main use of electricity from a mini-grid is for lighting and mobile phone charging. These communities now have a range of options, including pico solar lighting. Unlike kerosene lighting, such products have no health consequences that can justify connection to the main grid or the development of mini-grids.

• In better-off but isolated rural communities that might have been suitable for mini-grids, where income levels are rising and the main grid is now closer, grid connection will now be more suitable.



• As circumstances change, appropriate solutions at one time and place will not always be appropriate at another time or place.

From a national perspective, another important factor affecting the economics of mini-grids is the availability of donor grants and concessionary loans for low-carbon technologies. These now plentiful technologies can make it attractive to promote mini-grids that are based on renewable energy sources when, but for the grants or concessionary loans, the better solution for the country might be grid connection or pico lighting. This might have been the situation in the case study from Tanzania, where a non-grid (pico lighting) scheme might have been the better option if not for the grant.

At today’s costs, it is not known how many communities can justify the development of mini-grids on purely economic grounds. However, Cambodia’s experience suggests that mini-grids are an important and useful way to meet demand for electricity services for some communities. It is important that frameworks exist that allow mini-grids to be developed when the economics favor them.

The simple cost-benefit analysis in this report (shown particularly in the Cambodia case) is too crude a tool to analyze this properly. SPD systems have the benefit of being operated by private entrepreneurs, with their accompanying dynamism and desire to satisfy consumers and attract new ones. By contrast, SPD systems do not benefit from the economies of scale and standardization that arise when a utility operates the distribution network all the way to the consumers’ meters. The fact that, in Cambodia, the EAC is encouraging the consolidation of SPD systems and mini-grid operators suggests that it considers that economies of scale exist. Yet if the utility is unable or unwilling to extend the grid to the rural community, as in Cambodia, and if a private entrepreneur spots a commercial opportunity, then it is clearly better from a national perspective for the entrepreneur to undertake electrification as an SPD system rather than to deny the community access to electricity. In addition, SPD systems are better able to ensure payment, so a utility may actually prefer to give the responsibility for revenue collection to an SPD system.

SPD systems are therefore economically attractive provided the regulatory framework encourages them, allows them

to charge a reasonable tariff, and properly compensates them when consolidation (with other SPD systems or the utility) is ultimately the better solution. SPD systems often face practical challenges in situations where the tariff charged by the utility to its rural customers is cross-subsidized and lower than the tariffs that the SPD systems must charge to remain financially viable.

In all the countries analyzed in the case studies, perhaps the most important characteristic of the policy and regulatory framework that has led to the development of mini-grids and SPD systems is the ability for operators to charge a cost-reflective tariff that has allowed them to operate profitably (though often with capital subsidies). Other than for RVE’s Mwenga hydro mini-grid, regulations have allowed cost-reflective tariffs, and there has been no social or political pressure to match grid-based tariffs. If regulations allow, it is for customers to determine whether they choose to pay the full tariff and therefore whether the mini-grid or SPD system can operate sustainably.

References

Tenenbaum, Bernard, Chris Greacen, Tilak Siyambalapitya, with James Knuckles. 2013. “From The Bottom Up: How Small Power Producers Can Deliver Electrification and Renewable Energy In Africa—An Implementation Guide for Regulators and Policymakers.” Working draft, World Bank, Washington, DC.

UNDP Cambodia. 2008. “Residential Energy Demand in Rural Cambodia, an Empirical Study for Kampong Speu and Svay Rieng.” Phnom Penh.

Wickramasinghe, Harsha. 2005. “A Case Study on Off-grid Renewable Energy Development in Sri Lanka.” Sri Lanka Sustainable Energy Authority, Colombo.

World Bank and PPIAF (Public-Private Infrastructure Advisory Facility). 2009. “Opportunities and Challenges for Small-Scale Private Service Providers in Electricity and Water Supply Evidence from Bangladesh, Cambodia, Kenya, and the Philippines.” Washington, DC. https://www.ppiaf.org/sites/ppiaf.org/files/publication/WB%20Opportunities%20Challenges%20SPSP%20Water%20Electricity%20-%202009.pdf.

World Bank. 2012a. “Implementation and Completion Results Report for the Rural Electrification and Transmission Project.” Washington, DC. http://www-wds.worldbank.org/external/default/WDSContentServer/WDSP/IB/2012/09/18/000350881_20120918095151/Rendered/PDF/ICR23200P064840C0disclosed090170120.pdf.


35

5 Coordina ted Supply of Individual Power Generation

Individual power generation and supply systems are for a particular user, such as a household. With one exception, the schemes considered in this section are not connected to a network, though where net metering exists, they are connected to the grid. The most common individual power generation solutions are SHS and rechargeable-battery systems. Pico solar lighting is not defined as an APS type, although it serves an equivalent function on a smaller scale and without the option of powering additional appliances (apart, perhaps, from mobile phone charging).

Currently, other than solar and rechargeable-battery systems, no individual power generation technologies are available. Individual power generation in the context of APS might therefore also be described as distributed solar (other than pico lighting).

The four case studies in this section focus on large-scale supply of identical solar or storage systems, as opposed to bespoke individual systems. The first two cases look at the large-scale rollout of SHS in Bangladesh and Mongolia through coordinated national programs, reaching about 2 million and 100,000 households, respectively. The third case involves grid-connected SHS in Sri Lanka and the electricity banking/net-metering arrangements that support it. The last case looks at OMC Power, an Indian company that provides a battery-charging service for local communities around mobile phone towers.

5.1 Economic and Financial DriversIndividual systems for power generation and supply can provide power to consumers without a grid connection. Connections, whether to main grids or mini-grids, are justified if the volume of power consumed and the lower costs of supply from the grid outweigh the high fixed capital cost of connection. Individual power generation is particularly suited to households in remote areas whose demand for electrical energy is very low—typically for lighting, mobile phone charging, and entertainment—and for which connection to the main grid is not feasible, at least in the short or medium term. Another driver for these distributed solutions is simple failure by the main utility to extend the grid network to rural areas despite the economic and financial benefits of doing so.

The most common distributed power generation systems are SHS and pico lighting, which have low operating costs and no fuel costs. Their cost structure is weighted toward the up-front capital expenditure. Power storage systems (batteries) have a similar fundamental cost structure, with two differences: the costs of electricity to charge the batteries may be recovered from users through daily charges, and users may experience lower initial costs and higher operating costs than those who invest directly in SHS or pico lighting.

The economic and financial viability of individual systems depend on three key factors:

• Affordability. A consumer’s decision to invest in a system depends essentially entirely on its affordability, both in absolute terms and when compared with alternatives. Affordability can be enhanced through financing structures, in which payments may be up-front or staged and ownership may rest with either the consumer or the supplier.

• Maintenance. Although these systems tend to have low operating costs, they do require maintenance. When liability for maintenance lies with the consumer, the need occasionally arises for a “lumpy” payment. Consumers’ inability to cover that additional cost can leave an SHS owner without enough cash to repair a faulty system. Maintenance costs are also driven significantly by the accessibility of the system. Given that consumers tend to be in remote areas, owners can face significant costs in providing maintenance—costs that are ultimately borne by the (low-income) consumer.

• Payment system. In addition to the logistics of physical collection, assessment of viability must consider the cost of recourse in the event of default. Given the costs of reaching customers, those costs—particularly reclamation of an SHS—may outweigh the value of the installed system. The development of prepaid SHS has helped. Although installation of prepay meters may entail higher capital costs, collection costs are lower (particularly when using mobile prepay systems) and the risk of default is partly reduced.



5.2 Approach to Cost-Benefi t AnalysisThe key question about distributed electricity is whether it is best from a national perspective. In many cases, the supply of electricity to low-consumption users by conventional grid companies is not financially viable unless subsidies exist or cross-subsidies are allowed. For this reason utilities are generally happy to see such users obtain SHS or other distributed electricity supply products; the utility perspective is therefore not very interesting for three of the case studies. However, where net metering is allowed for grid-connected users and the utility has incurred fixed costs, the utility perspective is interesting. The Sri Lanka case study therefore considers the utility perspective.

In many respects, the consumer’s perspective is obvious. Consumers use SHS or other similar products if those products offer more cost-effective and higher-quality lighting and other services than alternatives such as kerosene or candles. In many cases, however, subsidies are offered to users, and it is interesting to consider whether these subsidies were necessary. For net metering, the consumer perspective is interesting in order to understand the motivation for adopting net metering.

The cost of solar PV systems has fallen dramatically over recent years. Solar modules represent about half of the overall costs of installed systems. According to a 2012 study by the International Renewable Energy Agency (IRENA), the global price of crystalline silicon PV modules in 2008 was estimated at $4.00/W; by 2012 the spot and factory-gate prices from manufacturers had fallen to $1.20–$1.40/W. This downward trend appears to have been driven by large increases in the scale of manufacturing and by technological innovation. Oversupply may also have been a factor.

Most commentators expect that prices will continue to fall. IRENA’s study of solar PV trends suggests that further economies of scale and technological innovation could push module costs to $0.73/W in 2015 (IRENA 2012, table 5.2). The study also discusses the potential for reductions in the costs of the rest of a system (inverters, installation equipment, labor costs, etc.). Table 26 presents some projections of overall system costs extracted from the IRENA study.

Solar products are currently competitive with grid-supplied electricity in only a few situations. If their cost continues to fall, solar power may become competitive with grid-supplied electricity in more and more situations. The next subsection considers the implications of falling costs of solar PV from the national and the utility’s perspectives.

5.3 Case Studies

5.3.1 Bangladesh—SHS

Bangladesh’s per capita electricity consumption is one of the lowest in the world, at 144 kWh/person annually. Access to the grid, which is operated by the Power Grid Company of Bangladesh (PGCB), is available to only 41 percent of the country’s 163 million people.15 Some 17 million of the country’s 29 million households are not connected to the grid. Access varies around the country, as shown in figure 4; in rural areas in 2004, only 28 percent of households had access (Bangladesh Institute of Development Studies [BIDS] survey 2004, cited in World Bank 2010). However, economies of scale may work in its favor: at over 1,000 people/km2, Bangladesh has one of the world’s highest population densities (among countries larger than 5,000 km2).

Kerosene is used for lighting in at least 90 percent of rural households, even in areas with high rates of electrification because even where electricity is available, the connection density is low. Figure 4 shows that 66 percent of villages have a grid connection, yet only 29 percent of households are connected, likely because of the high costs of connection. This contrast holds even in Dhaka, where 80 percent of villages have access to some

15 That is, an electricity connection is available if they choose to undertake the in-house installation, pay the connection fee, and pay the fi xed monthly charges.

Table 26. Projections of Installed PV System Costs, 2010–2030 ($/kW)

Source (system type) 2010 2015 2020 2030

Utility scale

EPIA (crystalline silicon) 3,600 1,800 1,060–1,380

IEA (crystalline silicon) 4,000 1,800 1,200

Residential/commercial scale

IEA 5,000–6,000 2,250–2,700 1,500–1,800

Solarbuzz (crystalline silicon) 4,560 2,280–2,770

Solarbuzz (thin film) 4,160 1,860–2,240

Note: EPIA � European Photovoltaic Industry Association, IEA � International Energy Agency.


37Coordinated Supply of Individual Power Generation

type of grid electricity service, but less than 50 percent of households are connected. Where grid connections exist, power is generally provided by cooperatives including PBSs (Palli Bidyut Samities), which serve rural areas through the national grid system. Many households connect to the grid through a neighbor’s connection. As may be expected, grid connection incidence and electricity consumption increase with household income. For those households earning less than Tk 25,000/year ($320/year), the connection rate and annual consumption are just 15 percent and 32 kWh, as shown in figure 5.

Nationwide, the average household consumes 29 liters of kerosene a year and 144 kWh of grid electricity, primarily for lighting (both kerosene and electricity), cooling, and amusement (electricity only) (BIDS survey 2004, cited in World Bank 2010). Although households also use storage cells and batteries for lighting (often for flashlights) and for amusement, consumption is very low. Kerosene lamps provide 70 percent of all lighting; most of the remainder is supplied from electricity. Even though electricity produces much higher-quality lighting, unreliable supply drives households to use kerosene lamps as a backup. There

0

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100

Chittagong

District

Dhaka

Villages Households

Khulna Rajshahi All

Ele

ctri

fica

tio

n r

ate

(%)

FIGURE 4 ELECTRIFICATION RATES BY DISTRICT

Source: BIDS Survey (2004), cited in World Bank (2010).

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)

An

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ou

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elec

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com

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Household annual consumption (kWh)

FIGURE 5 CONNECTION RATE AND CONSUMPTION BY INCOME QUINTILE


Note: The measure for consumption includes households that do not have access to electricity.



are substantial regional differences in consumption for lighting: rural households in Chittagong use more than twice as much energy as those in Rajshahi, for example. In Khulna, nearly 92 percent of lighting derives from kerosene (figure 6). The price of kerosene varies little across income quintiles or regions. However, for electricity, the lower proportion of fixed tariffs means that prices fall steadily as household incomes rise. Connection type and regional variations also influence electricity pricing.

Bangladesh’s Solar Home Program distributes SHS. It is part of a larger rural electrification program supported by the World Bank’s Rural Electrification and Renewable Energy Development project, which became effective on December 31, 2002, with support from the GEF, KfW, the German Agency for Technical Cooperation (GTZ), the Asian Development Bank, and the Islamic Development Bank. The project is managed and administered by the Bangladesh Infrastructure Development Company (IDCOL). To date, most of the distribution has been done through 46 partner organizations, primarily NGOs specializing in microfinance, microenterprise development, and SHS. One, Grameen Shakti, has made more than half of the sales. Partner organizations have gained the trust of rural households, making them efficient SHS delivery agents with proven collection histories demonstrating enough credibility to develop a credit line.

The program has installed approximately 2 million systems, succeeding beyond initial expectations. Its current target is 2.5 million SHS installed by 2014. Some 80–85 percent of the units are in the range of 20–85 watt peak (Wp), with 50 Wp systems accounting for an estimated 35 percent

of all sales. The simplest 20 Wp units cost $170, providing sufficient capacity to operate two 5 W lamps and a mobile phone charger for four to five hours.

To reduce the cost to the consumer, the IDCOL program subsidizes the up-front cost of the SHS through a grant and provides soft loans to the partner organizations so that consumers can access credit at low interest rates. The soft loan refinancing arrangements cover 80 percent of the price of the SHS, up to a maximum of $230 per system, at interest rates of 6–8 percent. Direct subsidies are about $26 per

household. The subsidies were initially much higher, about $70 per household, with an additional $20 provided to the partner organization for capacity building and recovery of installation costs. The intention is to eliminate the up-front subsidies; the soft loans are expected to continue. Households that purchase units benefit from the direct subsidy. After making a 15 percent down payment, they pay interest rates of about 12 percent (for an annual effective rate of about 21 percent) to the partner organizations for the loan balance.

User’s Perspective

In 2004, households without electricity spent an average of Tk 689/year ($8.86/year) on kerosene, while those with electricity spent an average of Tk 409/year ($5.26/year), a saving of about Tk 280 ($3.60) (BIDS Survey 2004, cited in World Bank 2010). Kerosene then cost Tk 20–21/liter ($0.27/liter), significantly below the retail price today of about $0.75/liter (Kojima 2012). Other sources (Momtaz and Karim 2012) suggest a monthly kerosene expenditure of about $4.39, which is closer to the value that might be expected today.

Figure 7 illustrates the range of SHS sizes purchased and the typical income profile of households purchasing them. More than 60 percent of sales have been made to households with incomes between $125 and $140/month. If these households represent the typical household consuming kerosene for lighting before the IDCOL program began, their expenditure on kerosene lighting (at $4.39) is very low—less than 3.1–3.5 percent of total income.

0

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Chittagong Dhaka

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Kerosene Grid lighting Candle Solar PV Storage cell

Rajshahi All

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ilog

ram

s o

f o

il eq

uiv

alen

t p

er h

ou

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old

FIGURE 6 ENERGY SOURCES FOR LIGHTING BY DISTRICT




Table 27 presents a typical financing arrangement for an SHS purchased through the IDCOL program (adapted from IDCOL 2011). The full cost of a 50 Wp SHS is $380, for which the household receives a grant equivalent to $38.40. The household makes a down payment of 15 percent of the remainder, and the vendor finances the rest for three years at a 12 percent flat interest rate (that is, 12 percent of the initial balance each year; the effective annual interest rate is over 21 percent). The household makes monthly payments of $10.97. Added to this is the equivalent monthly payment of the down payment, if made on the same terms, making the total monthly payment $12.86. This payment also covers the cost of maintenance.

Most households reduce their spending on kerosene by only about 40 percent when they have grid electricity,

presumably because of their need for backup lighting supplies when the grid is not supplying power. Therefore, it can be assumed that kerosene is not needed for lighting after an SHS has been installed, and the increase in monthly expenditure is $8.47, nearly 200 percent. Although total expenditure is still only 9–10 percent of total monthly income, this increase is nonetheless significant. However, it brings the benefit of being able to use additional appliances.

Data from grid-connected households indicate that only a little over half of their expenditure on electricity is spent on lighting, with the rest spent mainly on cooling (fans) and entertainment, as shown in figure 8. It may be assumed that these proportions hold for households supplied by SHS, indicating significant additional uses beyond lighting.

Welfare gains from switching from kerosene to electricity for lighting, represented by the consumer surplus, are about Tk 2,000/month, which represents 40 percent of average monthly household income. For the poorest quintile of households (those with incomes below Tk 25,000/year), the benefit is about 60 percent of monthly income (BIDS Survey 2004, cited in World Bank 2010). In addition, the benefits of much-higher-quality light can be observed in students’ higher educational performance. Studies have shown that electric lighting enables students to study better (World Bank 2002) and that it boosts literacy and school enrollment rates (Barkat et al. 2002).

Given the success of the program, it is clear that households are willing to spend considerably more per month for higher-quality lighting for the additional benefits it brings. What is not clear is whether households

Table 27. Typical Financing of an SHS Purchased through IDCOL

Variable Cost ($)

50 Wp SHS cost 380.00

Buy-down grant (€30) 38.40

Remaining cost to finance 341.60

Household down payment (15%) 51.24

Credit to customer 290.36

Loan duration (3 years, 12% flat rate interest, monthly repayments)

Monthly household installment 10.97

Total household loan payment 394.89

Monthly payment if down payment borrowed on same terms

12.86

Source: Adapted from IDCOL (2011).

0

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$55–$125/monthhousehold income

$125–$140/monthhousehold income

20 Wp

40 Wp

50 Wp

85 Wp

OthersP

rop

ort

ion

of

shar

es (

%)

FIGURE 7 PROFILE OF HOUSEHOLDS THAT PURCHASE SHS, BY SYSTEM CAPACITY (Wp)

Source: IFC (2012).



would be willing to spend as much if the program were entirely unsubsidized. Table 28 presents a cost outline for the same SHS without the buy-down grant and with commercial lending rates—estimated to be 18 percent flat (equivalent to about 31 percent annually), on the basis of the rates charged by most microcredit institutions in Bangladesh (Faruquee and Khalily 2011). Under these terms, the monthly expenditure increases by 26 percent.

The final comparison is between the costs to households of connecting to the main electricity grid. The price of

grid-connected electricity varies by district. In Dhaka district, it is Tk 3.33/kWh ($0.043/kWh) for residential customers using up to 75 kWh/month. For the poorest quintile of households (with incomes of less than Tk 25,000/year), consuming 213 kWh/year (18 kWh/month), this equates to Tk 60/month ($0.77/month), which is below the average expenditure on kerosene.

Dealer’s Perspective

The SHS dealers, known in the IDCOL program as partner organizations, are established NGOs and similar entities with a presence in rural services, predominantly microfinance. As noted, more than half of all sales in the program have been made by Grameen Shakti. IDCOL has provided technical support to each partner organization in developing expertise in SHS marketing, installation, and maintenance. Each continues to receive both direct subsidies for every additional unit installed as well as favorable refinancing terms from IDCOL for 80 percent of the vendor-financing component of every unit. Table 29 presents an analysis of the profitability of the same SHS sale presented in table 26 but from the perspective of the partner organization. On commercial terms, the credit advanced to customers is higher because they do not receive the up-front capital subsidy. The terms of own financing are typical of commercial projects of this nature, with an annual equivalent interest rate of 16 percent and a seven-year term with monthly installments. The

Entertainment

Lighting

Cooling

Heating and cooking

49.50 (34)

4.25 (3)9.34 (7)

80.74 (56)

FIGURE 8 HOUSEHOLD USES OF ELECTRICITY

KWh/year (%)

Source: BIDS Survey (2004), cited in, World Bank (2010).

Table 28. Suggested Financing of an SHS Purchase, Commercial Terms

Variable Value

SHS cost ($) 380.00

Buy-down grant (€) 0

Remaining cost to finance ($) 380.00

Household down payment (15%) 57.00

Credit to customer 323.00

Loan cost (3 years, 25% interest, monthly repayments)

Monthly installment 13.82

Total loan payment 497.42

Monthly payment if down payment borrowed on same terms ($)

16.14

Increase in monthly payment if commercial terms (%) 26




project’s weighted average cost of capital that was used to calculate the present values of cash flows in each case is taken from the weighting of the two interest rates in the IDCOL program or the commercial rate in the commercial program.

Although this analysis shows that the partner organizations make significant profits from financing each SHS, it does not capture their operating expenses. When the program started, IDCOL provided each partner organization a grant of $20 for each unit, an amount that has since been reduced to $2.56. This grant may have covered some operating expenses. It is unclear what the total direct expenses (installation, maintenance, parts) and indirect allocated expenses (overhead) would be, so the profitability of a single unit sale cannot be quantified, other than to acknowledge that it is profitable for the organizations to operate under the IDCOL program. This example highlights the loss that partner organizations would experience—close to a quarter of the benefit—if the IDCOL program did not exist.

Nati onal Perspective

From the national perspective, the question is whether it is optimal for households to receive power from SHS, as compared with a main grid connection (no information is available on mini-grids in Bangladesh). The case study of a related program in India (see section 5.3.4) considers a mini-grid counterfactual, and its results should be reasonably similar to what would obtain in Bangladesh.

The cost of SHS is $380 for a 50 Wp unit, including all installation and maintenance costs for three years;

thereafter, the cost is only $8/year). A useful life of 10 years is assumed. There is no cost for power consumed.

For grid connection costs, this analysis looks at two scenarios: a village that has a connection, in which only half the villagers are connected, and a village that has no connection and sits 5 km from the main grid. For households that connect to the main grid, the analysis posits consumption of 25 kWh/month. Accurate information on Bangladesh’s long-run marginal cost of electricity was not available for this analysis. However, about 75 percent of its electricity generation is powered by natural gas and 18 percent by furnace oil and diesel. Taking into account generation costs in other countries, it can be assumed that the economic cost, excluding the medium-voltage connection to the grid, is in the range of $0.10–0.15/kWh, as shown in table 30.

Using these assumptions, the analysis suggests that the IDCOL program is marginally attractive for villagers living in a village in which some villagers already have grid supply. It also suggests that the SHS option is substantially more attractive than grid electrification in villages that are not yet electrified at all. However, the results depend crucially on the assumptions. A larger village, smaller distances to connect the medium-voltage networks, or lower economic costs of grid-supplied electricity would all change these findings. For example, if the economic cost of grid-supplied electricity is only $0.10/kWh, then for villages that already have a grid connection, the optimal solution from a national perspective is for the villagers to connect to the main grid rather than use SHS. This is because the economic cost is $4.27/month rather than $5.41/month.

Table 29. Dealer’s Perspective on SHS Unit Purchase

Variable IDCOL program ($) Commercial program ($)

Credit to customer 290.36 323.00

Financed by

IDCOL (80%) 232.29 0

Partner organization (20%) 58.07 323.00

Present value of financing repayments by customer (discounted at project WACC) 345.96 393.01

Present value of IDCOL refinancing (7% annual equivalent interest, monthly repayments, nine-year term, two-year grace period; discounted at project WACC)

184.01 0

Present value of own financing (assume 16% annual equivalent interest, monthly repayments, seven-year term; discounted at project WACC)

72.14 323.00

Grant from IDCOL (€2.00) 2.56

Present value of all financing revenues and loan repayments (discounted at project WACC) 92.36 70.01

Difference in present value with commercial program 24%


Note: WACC � weight-adjusted cost of capital.





This case study offers one key lesson:

• SHS can be the optimal solution for providing electricity in rural areas, given certain conditions of population density, distance from main grids, and connection costs. Welfare benefits to households can justify the extra expenditure on energy per month.

5.3.2 SHS: 100,000 Solar Ger (Mongolia)

In 2000, the government of Mongolia initiated its 100,000 Solar Ger program, later receiving financial support in the form of grants from Japan and China. The goal of the project was to provide 100,000 rural herder communities with electricity through mobile SHS units. The government distributed units under a market approach, providing support to potential dealers, to companies to undertake the servicing and maintenance, and to microfinance institutions to support the investments in the units. In 2006, the program received support through the World Bank-initiated Renewable Energy and Rural Electricity Access Project (REAP). The program appears to have

been very successful: targets for electricity access are being exceeded, and markets for distribution, servicing, and electrical appliances are developing and sustaining themselves.

Support for the REAP sat within the government program, with the target of providing 50,000 of the overall target of 100,000 SHS. The initial REAP budget was $11.6 million, funded by the GEF ($0.9 million), the government of the Netherlands ($4 million), and the government of Mongolia ($6.7 million).

The National Renewable Energy Center was responsible for implementation and a project implementation unit for management of day-to-day activities. The program, also known as the Herders Electricity Access component of the REAP, focuses on developing a decentralized private sector electricity market among herders, through the establishment of a rural sales and service network for portable SHS and for electrical goods that can run off the systems (in addition to lighting). The REAP focused only on the SHS and lighting products, allowing the market for appliances other than lighting to develop organically through the dealer network. Dealers often sell other electronic appliances as part of package deals with the SHS.

Table 30. Cost-Benefi t Analysis of SHS and Grid Connection

Variable

Household SHS through IDCOL program

Grid-connected village, remaining households

Village connection to main grid

IDCOL SHS

Cost of unit ($) 380

Present value of warranty ($) 29

Total present value of unit ($) 409

Useful life of system (years) 10

Main grid connection

Medium-voltage connection cost ($/km) 0 15,000

Distance from main grid (km) 0 5

Total medium-voltage connection cost ($) 0 75,000

Medium- to low-voltage transformer ($) 0 5,000

Low-voltage connection cost per household ($) 200 60

Number of households to connect 150 300

Total low-voltage connection cost ($) 9,000 18,000

Total grid connection cost ($) 9,000 98,000

Total cost per household ($) 60 327

Useful life of connection (years) 30 30

Equivalent monthly payment ($) 1.77 4.13

Electricity usage (kWh/month) 25 25

Electricity cost ($/kWh) 0.15 0.15

Total electricity charge per month ($) 3.75 3.75

Equivalent monthly payment ($) 5.41 5.52 7.88



Dealers must be certified before they can enable customer access to a smart subsidy scheme (from the government) that covers a portion of the capital costs. Herders make their own capital contributions. The subsidies were structured to be pro-poor and flat, at $160 for units of 50 Wp or more, and $80 for smaller-capacity units (roughly equivalent to half the costs, depending on size). All SHS equipment sold is inspected for quality and certified to meet stringent standards, enabling herders to purchase with confidence. Each system includes a warranty and can be returned for a replacement at one of 50 sales and service centers established throughout the country under the REAP.

The market development component includes technical support to financial service providers for the provision of consumer credit and loans, the introduction of product quality standards, outreach to farmers, and technical support to dealers for marketing and service, including information on components, spare parts, and appliances. In addition, the REAP established a battery management program.

By May 2012 the program had reached nearly 96,000 rural herders. Initially the SHS were sourced in bulk through international procurement coordinated by the REAP, to benefit from purchasing economies of scale; now they are procured directly by certified dealers. Herders can select the provider of their system through a catalogue that is updated regularly.

The REAP was established to accelerate the pace at which SHS were distributed and sales and service centers were established. Before its establishment, no cost recovery program for SHS had been delivered and no after-sales services made available for maintaining units. SHS were distributed free or at a price that would not sustain a dealer network. In addition, the distribution networks were limited to the government’s administrative networks.

The project is now assessed primarily by the breadth of the distribution and servicing network and the number of units sold. Figure 9 shows the progress of delivery of SHS units. In September 2012, the number of SHS distributed stood at 100,146, accounting for almost 75 percent of the herder population. Herders use their SHS not only for lighting but also for radio and television reception using satellite dishes and for mobile phone charging, among other things. The demand for these products has stimulated markets within the dealer networks.

A key reason for the program’s success is the relationship between the nomadic herders and their soum (second-level administrative subdivision), where they are registered for administrative purposes. During the short summer months, when herders usually camp near their soum, it is common for them to visit soum administrators to deal with administrative and other matters. This institutional arrangement is a useful channel for reaching distant herders.

The REAP was on track to establish at least two sales and service centers in each aimag (first-level administrative subdivision, of which there are 23). The centers partner with the network of soum administrators, who are located in nearly 350 villages. The network of private dealers, sales and service centers, and soum administrators, with the support of the government, formed public-private partnerships that can reach herders in even the most remote areas. This ability was critical because the success of the program relied upon the availability of the broadest possible network for distribution and after-sales service. In addition to providing after-sales service, sales and service centers have begun purchasing SHS and working as certified dealers.


Before the development and expansion of the 100,000 Solar Ger program, herder households used primarily kerosene and candles for lighting. A typical ger requires only one kerosene light. Data on their monthly consumption of kerosene and candles are not clear, but data on kerosene comsumption in other countries suggest that households would consume close to 7 liters/month. The reported price of kerosene is approximately $0.54/liter (World Bank 2009).

Table 31. Summary of Bangladesh SHS Case Study


Customer Household expenditure on kerosene for lighting is less than 3.1–3.5 percent of monthly income at heavily subsidized price but more than expenditure of grid-connected households; equivalent payment for SHS is 9–10 percent of monthly income with benefits of use of other appliances plus reduced health costs; welfare gains from switch to electricity, represented by consumer surplus, equate to 40 percent of average monthly income

Dealer From IDCOL, partner organizations receive technical support in developing expertise in SHS marketing, installation, and maintenance; also both direct subsidies for each additional installed unit and favorable refinancing terms for 80 percent of vendor financing component for each unit; dealers are profitable, though not easy to observe their profitability. IDCOL subsidy program provides significant additional benefit over comparable commercial program

Nation Program is marginally attractive where some villagers have grid supply and substantially more attractive than grid electrification in unconnected villages, based significantly on assumptions of village density, distance from main grids, and costs of medium-voltage network extension



Assuming a household pays $160 for a 50 Wp unit (with half the cost subsidized), using a microfinance loan that is repayable over five years in monthly installments at an annual interest rate of 30 percent, the monthly payments will be a little more than $5.00. The full cost of the unit equates to $6.40/Wp, which is at the low end of a typical range of international prices for SHS (about $7–12/Wp) but is not unexpected given that the systems are produced and bought in bulk. Maintenance costs vary greatly but are assumed to be about $0.50/month. Table 32 summarizes the monthly costs.

This analysis suggests that without the subsidy, the uptake of SHS could have been much lower, given that households may now pay more per month for power. However, the reduced use of kerosene improves health and lowers health care costs, and the additional power enables households to use more appliances.

About 40 percent of the estimated 170,000 or so herder households have annual cash income of less than $450 (World Bank 2006). However, households can be “asset rich” through their animal herds and therefore may prefer up-front capital payments (funded by the sale of animals) to regular installment payments on financing.


For herder households, electrification options are limited to those that suit their nomadic lifestyle. Before the involvement of development partners, the market appeared limited less by demand for systems and ability to pay than by the absence of suppliers. The government managed the program and relied on its administrative networks for distribution. The subsequent involvement of development partners, including their provision of subsidies and technical assistance, led to the establishment of a private dealer network that now supplies SHS on a commercial basis to nomadic households. This suggests that the subsidies were necessary only to encourage the development of a commercial market—if at all. The fact that households now willingly purchase SHS without subsidies indicates that the benefits exceed the costs from a national perspective and that, even without environmental, educational, and health benefits, SHS have positive net benefits.



0

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del

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REAPbegins 100,146

78,330

67,873

32,922

1,132

FIGURE 9 IMPLEMENTATION STATUS OF SHS, 2000–SEPTEMBER 2012

Source: Ministry of Mineral Resources and Energy, Mongolia

Table 32. Monthly Energ y Expenditure Before and After SHS

Variable Value

Before SHS

Kerosene use (liters/month) 7

Cost of kerosene ($/liter) 0.54

Total cost of energy ($) 3.78

After SHS

Cost of SHS (after subsidy) ($) 160

Monthly installment, 30% interest, five-year period ($) 5.18




• In a nomadic community, where fixed-line electricity connections are not a feasible power solution, portable energy devices may be the optimal long-term solution for energy supply.

• Households may be willing to increase their monthly expenditure on energy to obtain extra benefits, such as mobile phone charging, television access, and improved health.

• Subsidies can be useful for establishing a market for SHS but are not necessarily needed to sustain a market.

5.3.3 Electricity Banking/Net Metering: National Utility (Sri Lanka)

In the past three to five years, Sri Lanka has established a small market for SHS under an electricity banking arrangement, in which a household (or any other customer) may install an SHS while retaining its grid connection. The primary power source is the SHS (or any other renewable energy source), and when it produces surplus power, the grid takes it. Instead of producing financial credit (as in a net-metering system), a household “banks” the equivalent in kilowatt hours with the relevant distribution utility (the CEB or Lanka Electricity Company) as energy credits. When the household needs to draw power from the grid, it can first use any energy credits it has stored. Currently, contracts with the utility last 10 years. Residential customers do not face time-of-use tariffs so that power credited during the day can be withdrawn at any time (normally during the evening). Nonresidential customers do not currently participate in the scheme but if they wish to participate they do face time-of-use restrictions: electricity they bank during the day must be withdrawn during the day.


The major driver of this growth is not technological advancement or economics, but the distorted block tariffs for high-consumption domestic customers. The poorest households benefit from both direct subsidies from the government and cross-subsidies from other residential and nonresidential customers. For consumption greater than 180 kWh/month, households pay very high tariffs for electricity (Rs 58.80/kWh). The Sustainable Energy Authority has estimated that such households can expect to repay their investment in a solar power system in four to five years (based on cost savings from the grid tariff they would have otherwise paid). However, should Sri Lanka change its domestic tariff structure to be more cost reflective, that benefit would disappear. Table 34 presents this rationale.


The cross-subsidized tariff is the factor motivating customers to take up electricity banking arrangements with the grid. Any decrease in demand from large residential customers who are net contributors to that subsidy could undermine the financial viability of the utilities. However, Sri Lanka’s current tariff methodology protects the utility to some extent: at each six-month review, any financial shortfalls caused by reduced contributions from those high-consumption users are compensated through an overall increase in the tariff.

It is assumed that any power that the grid banks on behalf of a user will be withdrawn by the same user at some point. Typically the utility absorbs energy during the day, when the sun is shining, and its power plants then produce less; during the peak evening hours, when electricity generation is most costly, the utility needs to produce more. This is not attractive from the utility’s perspective. Table 35 summarizes the costs and benefits. If the residential tariff structure became more cost reflective, with smaller cross-subsidies from the high-consumption users, then the arrangement would be less of a problem for the utility—but then it would not be of interest to consumers.

Table 34. Rationale for Customer Choice of Supply Option

Grid connection (current tariffs)

Solar electricity banking

Grid connection (cost-refl ective tariffs)

Customers pay Rs 58.80/kWh

Installation cost of a unit is about $2,500/kWp; with savings in power, should be repaid in four to five years

Average national cost of supply is Rs 21.80/kWh, so very challenging to repay cost of a solar home unit

Table 33. Summary of Mongolia SHS Case Study


Customer Households with SHS may now pay more per month than before ($5.18 versus $3.78); benefits include reduced kerosene use, improved health, lower health care expenditure, and ability to use additional appliances; uptake likely much lower without the subsidy.

Dealer Dealer network must be profitable for dealers to engage in program.

Nation SHS now bought without subsidies, so benefits exceed costs from national perspective; positive net benefits accrue, in addition to environmental, educational, or health benefits; infeasible to provide electricity to nomadic households through fixed lines



At present, there are only about 300 systems in operation. With such low numbers, the impact on the CEB is minimal. If the number of households involved in electricity banking arrangements increased greatly, the impact on the CEB would also be greater.


At present, Sri Lanka operates a power system that is generally reliable. In 2015, it plans to commission new coal-fired generation plants, which should reduce the average electricity supply costs to about Rs 17.00/kWh (from Rs 21.80/kWh). However, because of the CEB’s distorted tariff structure, consumers are choosing to obtain electricity from a more expensive source (costing about R 35.00/kWh). The program is not therefore in the national interest.




• Cross-subsidies can encourage net payers to seek alternative sources of electricity and avoid the “tax.” If a utility is forced to continue to subsidize some groups of users, it must then find other sources of revenue.

• Distortions from cross-subsidies can lead to suboptimal outcomes from a national perspective—although, if environmental parameters are considered, it is possible that the outcome could unintentionally be optimal.

5.3.4 Hybr id Solar/Diesel: OMC Power (India)

The Indian company OMC Power supplies electricity to rural areas of India where there is no reliable grid, primarily using solar power in hybrid solar-diesel systems. While developing a business model to provide power to mobile telecommunication towers, it saw a market opportunity to supply power to communities close to the towers. OMC provides power under contract to telecommunication operators at 11 sites and to communities with a total of 6,000 households, and these numbers are growing. OMC operates only in the northern state of Uttar Pradesh, which has a population of more than 200 million and a density of 820 people/km2—demographics that have allowed OMC to develop its pilot projects. OMC intends to continue developing power plants in Uttar Pradesh before considering other parts of India and other countries.

For the communities, OMC provides portable power—rechargeable energy applications delivered to their doorsteps—on a lease/rental basis. The firm describes this as a “milkman” solution.16 The firm has determined that electricity consumption in the households it serves is too low to justify a wired connection, from either the main grid (where available) or an isolated mini-grid. It is effectively undertaking both the supply of power and the sale and distribution of portable power equipment, although its model also allows it to separate these functions and supply power only to an entrepreneur in the village who then manages charging, sales, and distribution, or to a charging hub within the generation compound, where villagers can come to charge their units. OMC’s intention is to develop the capability of local entrepreneurs at all its sites. Already, it employs 10–15 local people in each village to manage its operations, including sales and distribution to the community.

Generation facilities are usually located within reasonable proximity (up to 500 m) of the mobile towers and either within or very close to villages, allowing easy distribution and collection of batteries and battery-operated appliances. Each power generation facility is based around an array of solar panels, lead acid batteries, and backup diesel generators, together supplying 18 kW or more of capacity.

16 It also has similarities to the bottled gas (LPG) market, in which the user pays a deposit for a bottle and exchanges the empty bottle for a fi lled bottle periodically. A key difference between the OMC and LPG models is that OMC also rents equipment (such as packages of lights and charging sockets), whereas LPG marketers rarely do.

Table 35. Rationale for Utility’s Perspective

Grid connection (current tariffs) Solar electricity banking

Cross-subsidies from high-consumption customers to low-consumption customers

Source of cross-subsidy lost; leads to higher tariffs for all customers

Lower generation during day and relatively more generation during costly peak hours (evening); leads to higher tariffs for all customers

Table 36. Summary of Sri Lanka Electricity Banking/Net Metering Case Study


Customer Larger residential customers with consumption above 180 kWh/month can recoup SHS cost in four to five years based on savings on grid tariffs; up-front cost of $2,500/kWp

Utility Customers using more than 180 kWh/month are revenue source for utility, used to cross-subsidize low-consumption users; loss of this source could lead to higher tariffs for all; system peak occurs during evening, not time when solar PV produces electricity; not ideal from utility perspective

Nation Because of the CEB’s distorted tariff structure, electricity consumers choose electricity from a more expensive source (about R 35.00/kWh) than grid supply program; not in national interest unless environmental damage costs of grid-supplied electricity are factored into calculation



Customers pay in advance for a fixed amount of power in a given period (for example, per day or per month). OMC retains responsibility for delivery and for collecting, charging, and servicing all components, including lights installed in households (subject to some conditions). OMC’s primary products are LED lanterns for lighting, for the poorest households, and power boxes that can supply power to a few appliances, including mobile phones, small televisions, and fixed lights and fans included with the power box.

OMC offers a range of products from a small LED lantern to electric bicycles. According to the firm, customers have indicated that their priorities for using electricity are mobile phone charging, lighting, cooling, entertainment, heating, cooking, transportation, and irrigation and other agricultural applications. Even given the limitations of battery power, power boxes can offer income-earning opportunities; for example:

• Lights that allow shops to stay open after dark

• Phone charging for a fee

• Public showing of television for a fee

• Fans to extract smoke while cooking or to keep flies away from food


Information from OMC suggests that the households it serves previously spent Rs 180/month ($3.06/month) on kerosene. This is low in comparison with other countries, in part because in rural India kerosene is subsidized.

OMC’s cheapest lantern costs just Rs 100/month ($1.70/month), a saving of Rs 80 ($1.36) over what households were spending on kerosene. It also provides health benefits and better-quality lighting, which enables children to continue their studies in the evening with less eyestrain and potentially better results, thus delivering long-run educational benefits. OMC delivers a fully charged lantern and collects it when discharged, with daily visits if necessary; a fully charged lantern should last one to two days. Rather than make large up-front payments, customers prefer to lease appliances and power supplies; the small regular payments let them manage their cash flow better—and if they are running low on cash, they can return appliances at the end of the month. Customers also take comfort from OMC’s ongoing obligation to maintain and replace the units, which means the firm can replace appliances with newer technology as it becomes available.

The next step up from the single lantern and the fully portable system is the power box, which includes two

lights and a fan. The charge for a power box is Rs 350/month ($5.95/month). Although this amount is more than households typically spend on kerosene, it is affordable for more affluent households and provides additional benefits such as the ability to charge a phone (households’ primary desired use of power).

Electricity supply is scarce and irregular in rural India. Even where villages are electrified, the supply is often available for only a few hours a day at most, so that in reality, the electricity grid cannot be counted on at all. Therefore, it is not easy to establish the comparable costs of grid connection for rural households. Assuming a low consumption of 15 kWh/month at a cost of $0.10/kWh gives a monthly expenditure of $1.50, or Rs 89—half what households currently spend on kerosene. Adding to this figure are the costs of lightbulbs, a backup supply of kerosene for outages, the connection, and electrical installation in the house. It is therefore not certain that grid connection will always be attractive to households even when it is available.


OMC Power is a commercial company that receives no subsidies. It plans to expand the village power supply business, so it must be assumed that the business is financially viable. The initial motivation for OMC’s power plant developments was to provide power to mobile phone towers, using contracts with large mobile phone companies to supply multiple sites, achieving economies of scale through its specialization. The opportunity to supply power to rural households in the vicinity of the towers came later and has since overtaken the initial motivation in its earning potential; OMC now expects that 80 percent of its revenue at each site will come from the communities. Nevertheless, the company does not currently plan to expand this model to supply communities that are not associated with mobile phone towers.


The national perspective analysis seeks to understand whether the OMC model is optimal compared with electrification through isolated mini-grids or grid connection.

Solar Home Systems versus Mini-grids

A study in India (Chaurey and Kandpal 2010) analyzed the economics of SHS in comparison with mini-grids. The study was not specifically concerned with the type of solution that OMC offers, but it nevertheless provides guidance on the comparative economics of distributed solar products and mini-grids. The study analyzed the break-even size of a village for a mini-grid, taking account



of population density and topography (for example, hilly terrain leads to higher costs for a low-voltage network). It found that distributed systems of the type offered by OMC are more suited to smaller villages with relatively lower population densities or with hillier terrain. Some of its findings:

• In densely populated villages (those with more than 180 households), a micro grid is optimal rather than distributed products (such as OMC’s).

• In less densely populated villages (those where household location is more scattered), the threshold size increases to 270 households; for smaller villages, OMC-type products are the economically preferable solution.

• For better-off villages with higher electricity demand, the threshold size drops to 100 households for a densely populated village or 150 for a village with a scattered population.

Although the study looked at distributed solar PV rather than OMC’s battery solution, the two systems are nevertheless broadly comparable and the results likely to be similar. The results may have changed since 2010 because the cost of solar technology has fallen, but this would have affected the distributed solution as well as the mini-grid solution, so it is not clear whether the threshold village size would have increased or decreased. The study did not compare distributed SHS or mini-grids with grid connection options.

Main Grid Connection

The analysis of connection to the main grid assumes a notional cost to connect a village and the number of households in the village. This analysis considers fewer variables than the 2010 study just discussed, but it is similar to that presented for the national perspective in Bangladesh in section 5.3.1. It looks at the cost of connecting a household that otherwise would lease a power box from OMC. It assumes an economic cost of grid-supplied electricity, excluding connection and house-wiring costs (because OMC’s model requires no wiring), of $0.15/kWh. Table 37 provides a cost-benefit analysis of SHS and grid connection.

This stylized analysis using general assumptions suggests that the OMC solution is better than grid connection. The assumptions are conservative, with a very low grid connection cost. If that cost and the house-wiring costs are added or if

distances from the grid are greater, or if medium-voltage line costs are higher than $15,000/km, then the rationale for the OMC model becomes stronger. However, if the economic cost of electricity from the main grid is lower—for example, $0.10/kWh—then the overall cost for a grid connection drops to $5.63/month, which is lower than the cost for the OMC package. There are too many variables to conclude anything other than that the current costs of battery and solar PV systems make the OMC model economically sensible under some circumstances and not under others.




• A small-scale rural power source with a low-risk anchor customer diversifies the risk to a power supply business and allows it to provide power to higher-risk battery-charging stations, at lower cost, while remaining profitable.

• Rechargeable lanterns can offer a cost-effective alternative to kerosene lighting, with additional benefits for health.

• Rechargeable power boxes may cost more than households currently spend but provide additional benefits that lanterns cannot.

Table 37. Cost-Benefi t Analysis of SHS and Grid Connection

VariableOMC power box lease


OMC power box

Monthly payment per household (Rs) 350


Medium-voltage connection ($/km) 15,000

Distance from main grid (km) 5

Total cost, medium-voltage connection ($) 75,000

Total cost, medium- to low-voltage transformer ($) 5,000

Low-voltage connection per household ($) 200

Number of households to connect 300

Total cost, low-voltage connection ($) 60,000

Total cost, grid connection ($) 140,000

Total cost per household, grid connection ($) 467

Useful life of connection (years) 30

Equivalent monthly cost over useful life ($) 4.13

Electricity usage per household (kWh/month) 15

Electricity cost ($/kWh) 0.15

Total electricity charge per month ($) 2.25

Equivalent monthly payment ($) 5.95 6.38



Distributed systems may be optimal from a national perspective when the expected consumption is low, or the population is distributed, or the villages are in terrain that makes grid extension difficult.

5.4 ConclusionsThis section has considered two main distributed generation options—SHS and battery charging. The SHS case studies looked at Bangladesh, Mongolia, and Sri Lanka and the battery-charging case study at India (Uttar Pradesh). They offer a series of lessons:

• SHS, rechargeable lanterns, and rechargeable power boxes can be viable energy supply options for households whose primary energy expense is for kerosene to supply basic energy needs and basic additional productive uses.

• Where cross-subsidies distort tariffs sufficiently and regulations allow energy banking or net metering, individual power generation units may be viable alternatives to grid connection. The beneficiaries will be customers who pay higher tariffs and are likely to be better off. Individual power generation units may not be an optimal solution for a country where more-expensive forms of energy generation are used in the national generation mix.

• Sustainable markets for SHS dealers can be established with the assistance of external subsidies for purchasing, sales, and distribution costs, and for training and community awareness. It may be possible to reduce or remove such subsidies over time.

• In areas of particularly low density with low household income or projected electricity consumption, or in nomadic households, individual power supply units

may be more attractive from the national perspective than grid connection or the development of mini-grids. With increases in estimated demand for power, grid connection becomes more viable as it outstrips the capacity of the units.

With the exception of Sri Lanka’s solar electricity banking program, none of the systems described in this section depend on fixed power lines connecting customers’ properties, but all involve high fixed costs paid either in a high one-off initial payment to the supplier or in a series of monthly payments to a supplier or a lender. Only the OMC model in India offers an arrangement whereby the customer is not required to agree to pay a fixed monthly amount for a reasonably long period of time (for example, three years). In that case, because the equipment is rented on a daily, monthly, or annual basis and then returned, OMC is able to reallocate the equipment to other consumers. As discussed in the next section, this feature makes this arrangement similar in some ways to mobile telephony. In theory, any packaged SHS could also be offered on a similar rental basis.

References

Barkat, A., M. Rahman, S. Zaman, A. Podder, S. Halim, N. Ratna, M. Majid, A. Maksud, A. Karim, and S. Islam. 2001. “Economic and Social Impact Evaluation Study of the Rural Electrification Program in Bangladesh.” Report to the National Rural Electric Cooperative Association (NRECA), Dhaka.

Chaurey, A., and T. C. Kandpal. 2010. “A Techno-Economic Comparison of Rural Electrification Based on Solar Home Systems and PV Micro-grids.” Energy Policy 38 (6): 3118–29.

Faruquee, Rashid, and M. A. Baqui Khalily. 2011. “Interest Rates in Bangladesh Microcredit Market.” Institute of Microfinance, Bangladesh. http://www.inm.org.bd/publication/briefs/Interest%20Rate.pdf.

IDCOL (Infrastructure Development Company Limited). 2011. “IDCOL Solar Home Systems Model: An Off-Grid Solution in Bangladesh.” Presentation, Bangladesh. http://www.idcol.org/Download/IDCOL%20SHS%20Model_30%20Nov’111.pdf.

IRENA (International Renewable Energy Agency). 2012. “Solar Photovoltaics.” Renewable Energy Technologies: Cost Analysis Series, Volume 1: Power Sector, Issue 4/5. IRENA Working Paper, United Arab Emirates. http://www.irena.org/DocumentDownloads/Publications/RE_Technologies_Cost_Analysis-SOLAR_PV.pdf.

Kojima, Masami. 2012. “Petroleum Product Pricing and Complementary Policies: Experience of 65 Developing Countries Since 2009.” Policy Research Working Paper 6396, World Bank, Washington, DC. http://www-wds.worldbank.org/external/default/WDSContentServer/IW3P/IB/2013/04/01/000158349_20130401160010/Rendered/PDF/wps6396.pdf.

Table 38. Summary of OMC Power Case Study


Customer Replacing kerosene (about $3.00/month) with cheapest lantern will save about $1.35/month; multiple use power box costs $5.95/month but allows customers to power multiple devices; connecting to unreliable national grid may cost just $1.50/month

OMC Commercial company receives no subsidies; plans to expand business, so must be assumed to be financially viable

Nation Distributed systems like this are more suitable than mini-grids for smaller villages, with relatively lower population densities or hillier terrain; given estimated low household consumption, power box is more cost-effective from national perspective in some circumstances than grid connection ($6.38/month vs. $5.95/month)



Momtaz, Shamsun Nahar, and Asif Mahbub Karim. 2012. “Customer Satisfaction of the Solar Home System Service in Bangladesh.” World Journal of Social Sciences 2 (7): 193–210. http://www.wjsspapers.com/static/documents/November/2012/16.%20Shamsun.pdf.

World Bank. 2002. “India: Household Energy, Indoor Air Pollution, and Health.” ESMAP Formal Report 261/02, Washington, DC.

———. 2006. “Renewable Energy for Rural Access Project (REAP).” Project Information Document, Washington, DC.

———. 2009. “Mongolia: Heating in Poor, Peri-urban Ger Areas of Ulaanbaatar.” Washington, DC.

———. 2010. “Restoring Balance: Bangladesh’s Rural Energy Realities.” Washington, DC.

World Bank Independent Evaluation Group. 2008. “The Welfare Impact of Rural Electrification: A Reassessment of the Costs and Benefits.” Washington, DC.


51

6 Mobile Telephony Lessons for APS

This section reviews the drivers of the rapid growth in mobile telephony in developing countries, considers whether APS could follow a similar path, and seeks lessons that could guide policy toward APS.

The mobile phone revolution in developing countries has been remarkable, as shown in figures 10 and 11. While the number of fixed-line subscriptions has remained virtually static since 2005, mobile phone subscriptions have soared from an average of 22.9 per 100 inhabitants to 89.4 per 100 in 2013. This phenomenon has been repeated in developing countries in all regions of the world. The growth of mobile phone penetration has been fastest in Africa, rising more than fivefold from 12.4 per 100 inhabitants in 2005 to 63.5 per 100 in 2013. Despite the fact that residents of Sub-Saharan Africa own only 8 percent of all mobile subscriptions worldwide, that region has seen the highest rate of growth, as shown in figure 12. The rate of growth there from 2000 to 2012 was 44 percent, while in all developing countries on average it is estimated at 34 percent. The rate of growth for developed regions was only 10 percent.

The demand for and willingness to pay for mobile phones by low-income users was not anticipated in the early years of mobile telephony. Telephones were thought to be the last of the utility services that users would obtain, after water, electricity, and waste management. However, it turns out that mobile phones have greater value—both productive and social17—to users than fixed lines because they allow users to communicate on the move. This allows users to take part in greater knowledge sharing (for example, about the prices of produce), coordinate transport of produce or people, and avoid the need for physical meetings, as well as multiple social purposes. Mobile phones have also spawned innovative means of communication, with users using missed call features to send messages as well as short text messages. This has made mobile phones important “must have” items even for low-income households.

17 See, for example, World Bank and African Development Bank (2012) and World Bank, InfoDev (2012).

FIGURE 10 MOBILE AND FIXED-LINE PENETRATION IN DEVELOPING COUNTRIES, 2005–2013

Source: ITU database 2013.a. Preliminary data.

0

10

20

30

40

50

60

70

100

90

80

Sub

scrip

tions

per

100

inha

bita

nts

Year

2005

12.7

13.0 12.4 11.511.1

89.4

78.3

58.3

39.1

Fixed-line subscriptionsMobile subscriptions

22.9

2006 2007 2008 2009 2010 2011 2012a 2013a



Source: ITU database 2013.

Note: CIS = Commonwealth of Independent States. The ultra-high penetration rates in some countries are fuelled by the common practice among users of having two or often three subscriptions with different operators because the operators give discounted tariffs for in-network calls (European Bank for Reconstruction and Development, 2012).

a. Preliminary data.

0

20

40

60

80

100

120

140

180

160

Sub

scrip

tions

per

100

inha

bita

nts

Year

2005

12.4

22.6

Africa

CIS

Arab states

Europe

Asia and Pacific

North and South America

26.8

52.1

91.7

169.8

126.5

109.4105.1

88.7

63.5

2006 2007 2008 2009 2010 2011 2012a 2013a

59.7

FIGURE 11 MOBILE PHONE PENETRATION WORLDWIDE, 2005–2013

0

5

10

15

20

25

30

35

50

4541

32

12

8

25

44

28

40

Sha

re (

%)

Region

NorthernAfrica

EasternEurope

NorthAmerica

WesternEurope

LatinAmerica

Sub-Saharan

Africa

Asia-Pacific

FIGURE 12 GROWTH IN NUMBER OF MOBILE CONNECTIONS, 2000–2012

Source: Wireless intelligence database.


53Mobile Telephony Lessons for APS

This mobile phone phenomenon provokes several questions:

• Was a large unmet demand among consumers unlocked by some regulatory or similar change, or did a technological phenomenon make telephony accessible to mass markets in developing countries?

• Has the price of mobile telephony relative to fixed-line services been a factor in the growth of the market? Has the falling price of mobile telephony been a factor?

• Has competition played an important role in driving the expansion in the market? Have other policies or regulatory frameworks played significant roles?

• What, fundamentally, has driven market expansion in developing countries?

The assessment in this section attempts to answer these questions. To the extent possible, it seeks to draw from evidence and therefore includes reviews of some empirical studies of the drivers of mobile telephony in developing countries. It addresses the possible drivers and the failure of fixed-line telephony to grow in the same countries. Five drivers are considered:

• Falling prices of mobile telephony

• Functionality

• Technical characteristics of mobile telephony compared with fixed lines, including cost structure

• Business models and payment plans for mobile telephony and how they differ from those for fixed lines

• Competition

The assessment then considers whether the drivers of mobile telephony appear in some of the APS schemes discussed in the case studies and whether such schemes are likely to replicate the growth seen in the mobile telephony sector in developing countries.

6.1 PriceThe impact of falling prices for mobile telephony is unclear. For an equivalent bundle of calls, the overall service package costs to users are typically significantly higher for mobile subscribers than for fixed subscribers.18 Linked to the growth in demand and economies of scale as well as to competition, the price of mobile telephony has fallen substantially while the price of fixed-line telephony has remained relatively constant. In the

18 See, for example, GSMA (2012).

countries of the Organization for Economic Co-operation and Development, the price of fixed-line telephony remained relatively stable from 1990 to 2010, though users now pay more for fixed subscription charges and less for calls (OECD 2011). According to the International Telecommunications Union (ITU), the price of a basket of fixed-line charges worldwide fell by 19 percent between 2008 and 2011 while the price of a basket of mobile telephony charges fell by 37 percent (ITU 2012). Although the trend has been toward greater declines in developing countries (35 percent), the decline between 2008 and 2011 was greatest in developed countries (53 percent).19

One determinant in the rapid adoption of mobile telephony in developing countries may have been the advent of cheap devices (see the empirical studies in annex A1).20 The costs of handsets have fallen rapidly over the past decade, in part because of the scale of production and competitive forces in the market.

6.2 Increased Functionality and Productive ValueThe first-generation analogue networks were developed in the 1980s. Subsequent developments focused on data transfer and the Internet, neither of which appears to have been factors in the growth of mobile penetration in developing countries. The subsequent high investment activity in mobile telephony resulted in a raft of innovations, including the introduction of the short message service, or SMS, which mobile phone subscribers in developing countries use extensively.

The simpler features of mobile phones offer more functionality and greater productive value by allowing telephony on the move, thereby enabling—for example—farmers to share produce prices and coordinate transport of produce or people to markets.

Mobile phones offer additional functionality, serving as a watch, alarm clock, calculator, address book, camera, music player, and radio. With Internet access some phones can also be used as a television, newspaper, and magazine. Although technological developments (particularly Internet access) have driven demand in developed countries, they are not yet significant drivers for the growth in demand for mass market mobile telephony in developing countries. For example, a World Bank study of mobile phone usage in South Africa showed that

19 Dominated by a very large one-off drop of 43.4 percent in 2008/09.20 One study by Harvard University and the Center for Information Policy

Research acknowledged the role of cheaper handsets; however, an empirical study by the UN’s World Institute for Development Economics Research failed to fi nd a statistically robust relationship between handset cost and penetration.



calls, missed calls, text messages, and a few other basic functions are the main uses of mobile phones by those at the bottom of the pyramid (World Bank, InfoDev 2012).

Mobile telephony is now used extensively as a means of transferring money in Africa. This is particularly valuable for users without bank accounts. In Kenya, for example, M-Pesa, a mobile phone–based money transfer service, had 17 million subscribers in December 2011. However, this use arose after the large-scale penetration of mobile phones. Although money transfer applications may drive continued penetration, they were not factors in the original expansion.

6.3 Technical Characteristics and Cost StructureIn developing countries in 2013, mobile penetration (measured as the number of subscriptions per 100 inhabitants) was about 89.4 percent, according to the ITU, while fixed-line penetration was only 11.4 percent. This suggests that mobile telephony has managed to overcome the problem of access for those who could not be, or were not, connected with a fixed line. For example, in Bangladesh, Burkina Faso, the Democratic Republic of the Congo, Djibouti, Eritrea, and the People’s Democratic Republic of Lao, more than 90 percent of all fixed-telephone lines are in urban areas, whereas most rural

areas have no fixed-line infrastructure (ITU 2011). The ITU notes that one reason for the increased penetration of mobile telephony in developing countries is that cellular networks can be built faster and reach geographically challenging areas more easily than fixed-line networks (Feldmann 2003).

Different technology means that the structure of costs of fixed-line and mobile phone operators are different. Both have fixed infrastructure costs that must be covered from phone charges, but the proportion of costs that are fixed and customer specific differ. Fixed in this context means capital costs that are incurred up front and recovered from users over time. It is the combination of fixed and customer-specific costs that is important. Infrastructure, such as bridges or roads, may have fixed costs, but if one road user does not use a bridge it is still available to others. But in fixed-line telecommunication networks, typically, once a fixed line is installed to a house, unused capacity provided by that connection cannot be used by a person in another house. Fixed-line costs may also be specific to a small group of users as in a village, so that if some households do not use the capacity then others in that village can.

There is thus no precise definition of when infrastructure costs are fixed and user-specific, but the proportion of such costs for mobile phone operators is clearly less than

Procedure -Waiting list-Registration and credit check

Cost of entry -Deposit -Installation charge

Monthly price and usage-Line rental and call charges-Long-term commitment -Cannot directly control the bill-Cannot be aware of the current bill at any given time

-Line can be cut off if fail to pay the bill

-No waiting time, simply insert a SIM card-No registration at all in most cases-Credit check is not an issue for prepaid cards

-No deposit is required-No installation charges-Mobile phone devices are cheap to obtain-Secondhand market for mobile phones

-No fixed monthly line rental charge-Pay-as-you-go option-No long-term commitment-Low starting price for top-ups -Same charges within the country irrespective of distance

-Other options like missed calls and SMS that lower the total cost of mobile telephony

Previous barriers to telephony in developing countries (fixed lines)

Mobile telephone characteristics

FIGURE 13 MOBILE PHONES REMOVE BARRIERS TO TELEPHONY



for fixed-line operators. With mobile phones, if one or a small group of users does not make much use of their phones, the network capacity is available to other users. This difference in cost structure necessitates different cost recovery mechanisms, as the GSM Association notes: “[T]he efficient mechanism for recovering the cost of radio capacity is in relation to the traffic services that it supports [whereas] the efficient mechanism for recovering the cost of the copper access network is in the form of a rental fee from subscribers” (GSMA 2007).

Some mobile network resources are specific to a group of users (for example, mobile phone towers are specific to the users in the area covered by those towers). However, a larger proportion of the fixed-line network resources is specific to both individuals and groups of users. This has important implications for pricing policies aimed at low-usage customers and allows mobile phone companies to offer service without fixed monthly charges (that is, pay-as-you-go), as discussed in the next section.

The technical characteristics of mobile telephony make it particularly suited to rural areas. The ease of developing the infrastructure combined with the prepaid business model (which reduces administrative costs for the operator) has made it easy for operators to offer access and for users to obtain access. Figure 13 summarizes the barriers to telephony in developing countries and how they are overcome by mobile telephony (GSMA 2006).

6.4 Business Models6.4.1 Prepaid/Pay-As-You-Go Service

Two of the studies described in annex A1 show that pay-as-you-go and prepaid21 options are a significant factor in the widespread uptake of mobile phones in developing countries.22 The business model—prepaid service/scratch cards, with very low administration costs, sold by street vendors or shops—has been adopted by the majority of users in developing countries (Gillwald and Stork 2012). This has been made possible, in part, by the cost structure of mobile phone networks (GSMA 2007).

21 “Prepaid” and “pay-as-you-go” here generally describe a system in which users pay in advance using a scratch card or similar arrangement and charges are deducted from the credit balance when the user makes calls. Prepaid can also describe a model in which users pay a fi xed monthly amount that is debited from their bank accounts and a periodic reconciliation is made of actual usage charges against advance payments. This type of prepaid model is not the one discussed here.

22 The studies are by Harvard University and the Center for Information Policy Research and by the UN’s World Institute for Development Economics Research. The latter found the availability of prepaid options to be a highly statistically signifi cant driver of mobile penetration.

From the viewpoint of operators, lower fixed and user-specific costs mean that pay-as-you-go works as a business model because operators do not rely on regular minimum monthly revenue streams from individual users to cover their costs. The prepaid business model also reduces revenue collection costs and credit risk to a very low level.

From the viewpoint of users, this business model is also attractive. Fixed-line operators normally require customers to pay a fixed monthly or quarterly charge that is independent of the number and length of calls and independent of whether they can afford the charge. This fixed monthly charge is necessary because the operators’ costs are fixed and linked to individual customers and groups of customers. Fixed charges of this type are unaffordable for mass users in developing countries, whose income may vary from month to month. Because mobile operators have no costs tied up in specific users, they can allow pay-as-you-go. If a user does not have enough income in one month (or one day) and has no credit, then the user simply does not use the phone. According to a survey of mobile phone use in Latin America, “the poor generally pay a cost premium for using prepaid subscriptions that allow better expenditure control, though in many cases this premium is much lower than expected” (Barrantes and Galperin 2008).

6.4.2 Can Fixed-Line Companies Offer a Prepaid Service?

If the pay-as-you-go/prepaid business model is so important to the growth of mobile telephony in developing countries, why have fixed-line operators not adopted the model universally as an option? This analysis concludes that the main reason is the structure of fixed-line costs. As described in section 6.3.2, mobile phone technology entails fewer consumer-specific costs for operators. This enables operators to offer pay-as-you-go tariffs to customers. Customers with low usage are welcome because this cost structure makes it financially viable for the operators to serve such customers. By contrast, fixed monthly charges or minimum monthly usage requirements are essential if fixed-line operators are to cover their high fixed and user-specific costs. So the structure of costs of fixed-line telephony prevents fixed-line operators from offering pay-as-you-go pricing.

Fixed-line operators could implement prepaid systems that would lower their revenue collection costs and lower the credit risks for users. In developed countries, they do offer such systems; however, they do so largely by using sophisticated banking services and regular monthly payments through banks. Few users in developing countries have access to such banking services. But more



crucially, to avoid losses on supplying low-consumption users, fixed-line operators must impose a substantial fixed charge (or its equivalent in the form of a minimum monthly consumption).

In principle, fixed-line operators could introduce prepaid business models in the way that electricity operators do through prepayment meters. However, doing so would not overcome the problem of high user-specific fixed costs that need a matching regular revenue stream from fixed monthly payments. Electricity operators manage to combine prepayment meters and pay-as-you go for service with high fixed costs through the cross-subsidization of low-consuming rural users by high-consuming urban users. For electricity distributors that are obliged by government or regulatory policy to serve rural communities, prepayment meters are a better mechanism than credit meters, but do not by themselves solve the problem of high fixed and user-specific costs in the electricity supply cost structure.

6.5 Competition6.5.1 Competition in Fixed-Line Telephony

Fixed-line telephone networks tend to become natural monopolies, and competition is not possible in the network part of the supply chain.23 In other parts, competition is possible to some extent but it is a complex endeavor and has been less successful in developing countries. In more developed countries, competition has developed in fixed networks through two main approaches:

• Investment in separate physical infrastructure, including fiber and fixed wireless connections to households and business premises. This has happened mainly in cities.

• The use of wholesale access models, in which competing service providers purchase capacity on the incumbent operator’s network at wholesale rates in order to provide services to end users at a retail rate. Examples of the enabling wholesale services are local loop and fiber unbundling, wholesale broadband access, carrier selection and preselection, and line rental.

These competitive models have been necessarily complex, requiring proactive (ex ante) regulatory intervention and a degree of cooperation between competing entities that is difficult to enforce. In practice (especially in developing countries), fixed-line competition has been severely limited, for three main reasons:

23 Investment in alternative networks has been limited to the more profi table urban areas in developing countries.

• The lack of regulatory capacity and expertise prevents achievement of the level of regulatory intervention required.

• State-owned interest in the incumbent operator has favored the incumbent, often resulting in “regulatory capture” whereby incumbent interests against competition prevail.

• The monthly rental rates and local call charges for fixed-line telephony have been kept artificially low, often justified by “universal service” cross-subsidies paid for by super-high profits on national and international calls. This distortion of retail tariffs has greatly discouraged fixed-line competition in local retail access.

6.5.2 Competition in Mobile Telephony

Competition in retail mobile telephony has occurred without complex frameworks. In fact, reforms introduced in the telecommunications sectors have allowed competition to flourish. In most developing countries, multiple operators (at least two, typically three, and sometimes more) compete for customers. This competition is thought to have helped drive down costs and make mobile telephony more affordable for the mass market.

Competition is thought to be a fundamental determinant of investment, speed to market, quality, prices, and subsequent penetration rates. Countries that have very low penetration rates (below 10 percent), such as Eritrea, Ethiopia, and Myanmar, are also those that have no competition (ITU 2011). Anecdotal evidence also suggests that competition has a positive impact on fixed-line penetration. In Côte d’Ivoire, for instance, greater competition among mobile network providers has led to an increase in fixed-line penetration. This also occurred in Senegal: fixed-line penetration increased where the fixed-line operator faced competition from mobile network providers (ITU 2003).

The empirical studies24 described in annex A1 show that the introduction of competition, among other factors, has played an important role in increasing the magnitude and size of the mobile market over the past decade:

• Harvard University and the Center for Information Policy Research noted that the impact of competition declined as the number of competing firms increased beyond three or four.

24 The studies by Harvard University and the Center for Information Policy Research, the UN’s World Institute for Development Economics Research, and the World Bank’s Development Research Group all fi nd competition to be a factor affecting penetration. The extent varies by study or was not quantifi ed.



• The United Nations’ World Institute for Development Economics Research found that countries with two or more competing operators had substantially higher penetration than those with only one.

• The World Bank’s Development Research Group estimated that liberalization (privatization plus competition and an independent regulator) led to an 8 percentage point increase in penetration.

The ITU report on the determinants of the widespread adoption of mobile telephony in Africa indicates that greater competition drove greater penetration (ITU 2003). This was not, however, an empirical study.

6.6 Parallels with APSIn the electricity sector, the supply chain comprises three (or four) elements:

• Generation (the production of electricity)

• Transmission and distribution (networks for the transportation of electricity)

• Supply (the activity of buying and selling electricity to end users)

Table 39 indicates the location of the five APS models in the supply chain (generation, transmission, distribution, and supply).

In terms of function, telecommunications is primarily a network industry; its closest equivalents in the electricity sector are the activities of transmission and distribution. Both telecommunication networks and electricity transportation are natural monopolies in which competition is not generally possible.25 Competition occurs in both retail telecommunications and electricity supply when competing service providers use the same physical infrastructure. Competition is also possible in electricity generation, which has no functional equivalent in telecommunications. Both mobile and fixed-line telephony are functionally similar to only one of the APS models—SPD systems. Nevertheless, one can ask whether the factors that drove the growth in mobile telephony are likely to drive a similar revolution in electricity. This section therefore considers the potential drivers (price, technical characteristics, business models, and competition) for telecommunications and whether they are likely to apply to each APS model. Although this review did not directly

25 Competition through investment in separate infrastructure has been used in telecommunications but generally only in urban centers where businesses and medium- to high-income groups can afford the higher cost of the greater capacity and better quality of newer technology.

consider technological innovation leading to new service offerings as a driver for the mobile telephony revolution, it could be a driver in the electricity sector and is therefore also considered.

6.6.1 Price

As considered in this subsection, price broadly encompasses technological innovation in cases where such innovation leads to lower prices. Another type of technological innovation occurs when a new service is provided—for example, when mobile telephones are combined with access to the Internet. This second type of technological innovation is discussed in the next subsection.

Falling prices were not definitively a driver of the growth of the mobile telephony market in developing countries. Initially, prices for a bundle of mobile services were considerably higher than for fixed-line services, and yet the market grew dramatically. Subsequently, prices for mobile services fell, which likely contributed to greater penetration.

In the electricity sector, by contrast, price declines brought about by innovation in the manufacture of generation technologies may be a key factor in making some forms of APS attractive. One technology in particular could lead to growth in usage in both conventional and APS approaches. Solar energy is reasonably universal in its availability and, unlike most other energy sources, is not location specific. Consequently, it can be used in captive power, P2P, mini-grids, and coordinated individual supply. Solar PV costs have fallen dramatically, and most commentators believe that will continue. At present, solar PV remains more expensive than most other grid-scale generation sources. However, it is competitive in some applications for supplying isolated loads that would otherwise be supplied with diesel-generated electricity.

6.6.2 Increased Functionality

The preceding subsection discussed one type of technological innovation that leads to lower costs

Table 39. Location of APS Models on Electricity Supply Chain

APS categoryLocation on electricity supply chain

Captive power Generation and supply

P2P Generation and supply

Mini-grids Generation, distribution, and supply

SPD system Distribution and supply

Coordinated individual supply Generation; avoiding transmission, distribution, and supply



of delivering the same service. A second type of technological innovation leads to the delivery of new services. An example in mobile telephony is enabling users to access the Internet on the move. However, this innovation was not be a key driver for the growth of the market in developing countries.

In the electricity sector, some mobile telephony innovations may have provided a key building block for potential growth in the market. These innovations make it possible to meter electricity consumption remotely and to pay charges remotely through a mobile phone. This particularly affects one APS model—coordinated individual supply. However, this is only one component of a possible electricity supply revolution; it is not sufficient by itself to spark that revolution.

6.6.3 Technical Characteristics and Cost Structure

As in fixed-line telephony, the cost structure in the electricity sector is characterized by high fixed costs (the capital costs of generation, transmission, and distribution), some of which—particularly for distribution and supply—are also specific to individual customers or groups of customers. The specificity of costs is particularly true in relation to the distribution and supply of electricity and less so for generation and transmission.

An important technical characteristic of mobile telephony was that it reduced the need for a dedicated physical connection to the user. It still requires a network and some infrastructure dedicated specifically to groups of users (geographically) but, beyond the handset, there is less dedicated infrastructure than in fixed-line telephony.

Among the APS models, captive power is generally user-specific and the cost structure is, if anything, less attractive than grid-connected electricity in terms of the goal of avoiding fixed costs. An exception are rented plants that may be moved from site to site, which makes them less user-specific. Often the rental plants are container-mounted diesel generator sets, but more recently a few firms have been offering rental plants that

are solar powered, with price structures calculated for a fixed contract duration. The fixed period is usually at least five years and the costs are high, so the cost structure for such plants differs significantly from that for mobile telephony. It is not conducive to a revolution triggered by the combination of rental business model and “captive” solar power plants.

The cost structures for supply from mini-grids and SPD systems—like the cost structure for conventional grids—entail high fixed costs. For mini-grids, the fixed costs are proportionately higher than for grid-connected electricity; for SPD systems, they are essentially identical to grid-connected electricity because SPD systems are effectively a way of operating a segment of the supply chain of a conventional power system. So the cost structures do not support a revolution in either APS model. Ascertaining the proportion of electricity costs that is fixed and customer specific and the proportion that is variable or non–customer specific is complex. Table 40 provides cost structures for a hypothetical conventional electricity supply chain and for a hypothetical mini-grid. The fuel and variable O&M costs depend on the amount of electricity consumed; if a consumer chooses not to use electricity then these costs are avoided. At the other extreme, low-voltage distribution costs are fixed and user-specific; if the user chooses to use only a little electricity then these costs are still incurred. The power plant(s) and the transmission assets are fixed costs. The capacity of the plants is not customer specific. The capacity of the transmission lines is specific to large geographical groups of customers, so they are only partially specific.

Table 40 indicates that for conventional power systems a substantial proportion of costs are fixed and that for mini-grids the proportion is even higher.

Unlike mini-grids and SPD systems, coordinated individual supply (for example, SHS) has essentially 100 percent fixed costs and virtually no variable costs (though batteries have a finite number of charge/discharge cycles, so their costs depend on usage to that

extent). Whether the costs are user-specific depends partially on the possibility of removing the equipment and transferring it to another user. SHS are normally 100 percent customer specific. Some providers offer a service in which the customer rents the equipment (typically lighting and sockets for charging mobile phones but sometimes televisions or electric motorbikes as well) and the provider

Table 40. Electricity Supply Cost Structure, Proportion of Costs (%)

Variable Conventionala Mini-gridb SHS

Fuel and variable operation and maintenance 59 0 0

Generation fixed costs 15 58 100

Transmission and distribution 25 42 0

Total 100 100 100a Calculated using ESMAP’s model for electricity technology assessment and based on a combined-cycle gas turbine plant burning natural gas with a 65 percent system load factor.b Calculated using ESMAP’s model and based on a mini-grid with a 45 percent system load factor supplied by a mini-hydro plant.



regularly collects the discharged batteries and replaces them with fully charged ones. The equipment can be returned in months when the customer’s income is low. In these cases, the costs are not customer specific but they are relatively high, driven by the limitations of battery technology.26 Technical innovations in batteries that lower the costs of storing electricity, improve efficiency and durability, and lengthen battery life would make this model radically more attractive to service providers who sell to users at the bottom of the pyramid.

6.6.4 Business Models

As noted, prepaid/pay-as-you-go pricing was a key driver for the mobile phone revolution in developing countries. Such options have been available in conventional electricity supply for many years and are used extensively and successfully in developing countries (for example, prepayment meters). Prepayment is attractive to consumers because it allows better control of their cash flows, and it is attractive to utilities because it reduces collection costs, lowers theft, and improves their cash flow. But the prepayment model for conventional electricity supply to rural and low-income users—with no fixed charges and no minimum monthly consumption levels—is made financially feasible only by cross-subsidies between high-consumption users (typically relatively high-income and urban) and poor rural or peri-urban consumers. This is identical to the situation in the fixed-line telecommunications sector.

Electricity and fixed-line telecommunications utilities expanded into rural areas because they had a social obligation to do so, not because it was commercially attractive. Although pay-as-you-go/prepaid systems are more attractive than conventional credit metering, utilities would prefer not to supply electricity to low-consumption users in rural areas at all because they are loss-making for the utilities.

Metered pay-as-you-go arrangements are also available for users of SHS linked to mobile phone networks, enabling consumers to pay for electricity and the SHS by purchasing credit on their mobile phones. However, the availability of such technology does not overcome the problem of the cost structure of SHS, just as it does not solve the problem for conventional electricity supply or fixed-line telecommunications—namely that users with low consumption do not contribute sufficiently to the providers’ high fixed costs (and the re-sale value of SHS

26 The cost of batteries is relatively high, and the life and performance of the batteries depends heavily on how they are used. A rental model is less suitable for equipment that is less robust to user mishandling.

does not recompense the provider if the user stops using the system or stops paying).

In contrast, the rental and battery recharging model does have a fundamentally different cost structure, one that is closer than that of mobile telephony. Improvements in battery technologies that lower costs a little and improve performance could result in a revolution in the market for those at the bottom of the pyramid.

6.6.5 Productive Value

Anecdotal evidence suggests that enhanced productive value was a key factor in the growth of the mobile telephony market in developing countries. Electrification does offer potential benefits in terms of productive use—particularly electrification that allows the use of larger electrical equipment. This is not the case for technologies used in coordinated supply of individual power generation, and some mini-grids may have limits on the capacity of equipment that can be used. While investigating the benefits of rural electrification, the World Bank’s Independent Evaluation Group (World Bank 2008, xvi) concluded

Rural electrification does not drive industrial development, but it can provide an impetus to home businesses, even though few households use electricity for productive purposes. [The] analysis shows that the number of enterprises grows as a result of electrification and that these enterprises operate for more hours. There is, therefore, a positive impact on household income. However, the broader literature has found these effects to be less than expected, except when there has been a specific program to promote productive uses of electricity.

The relative magnitude of the productive benefits of mobile telephony versus electricity to rural communities is uncertain, but in terms of benefits and costs, the cost-benefit ratio (and measures of economic net benefit) appear more favorable for mobile telephony than for electricity.

6.6.6 Competition

Competition was an important factor driving growth in the mobile telephone market in developing countries. In the electricity sector, it is also likely to be important in promoting the market for some of the APS models, though it may be less important than the unbundling of the electricity market into separate organizations responsible for generation, transport, and supply, and the introduction of third-party access arrangements.



Captive power is perhaps least affected by the introduction of competition. Apart from the existence of suitable conditions (cheap energy sources, cogeneration opportunities, opportunities to use waste products), its success depends primarily on the existence of a regulation requiring the utility to purchase surplus electricity from CPPs at a reasonable price. Such regulations may be introduced with or without competition. In some instances, competition may undermine the attractiveness of captive power because regulations obliging utilities to purchase surplus electricity from CPPs may be seen to conflict with the concept of a competitive market.

P2P of course depends crucially on the existence of competition. Without third-party access to the transmission and distribution networks, P2P schemes cannot exist.

Mini-grids are not affected significantly by the introduction of competition. Their success often depends instead on the existence of simple rules, or the absence of rules, that enable them to charge cost-reflective prices.

SPD systems may be accepted more readily in countries where competition has been introduced. They may be able to enter into bilateral contracts to purchase electricity in bulk from generators and transport it through the transmission and distribution grids to their networks. However, competition is not necessary to allow SPD systems to operate successfully.

Coordinated individual supply is also largely unaffected by competition. Competition typically refers to grid-supplied electricity, whereas individual supply solutions are generally provided in an environment of suppliers competing to sell SHS or other individual technologies or services.

6.7 Conclusions6.7.1 Mobile Telephony Drivers

This review of the literature suggests that the surprisingly rapid growth in the mobile telephony market in developing countries derived from the following four characteristics of mobile telephony:

• Technology/cost structure: The cost structure of mobile telephony is unlike that of other network services because it has relatively low fixed and user-specific costs. Both mobile and fixed-line operators have fixed infrastructure costs that must be covered from phone charges, but their proportions of such costs differ. It is the combination of fixed and customer-specific costs that is important. In fixed-

line networks, capacity provided to one user cannot be used by another.27 The favorable cost structure of mobile telephony, where effectively only the handset is user-specific, makes it financially viable for operators to offer services to low-income, low-consumption users using a prepaid/pay-as-you-go charging model.

• Business model/pay-as-you go: Empirical studies generally agree that the prepaid/pay-as-you-go option was a key driver of the mobile phone revolution in developing countries. For traditional fixed-line services, prepaid models may be technically feasible,28 but to make service provision financially viable for the operators, the cost structure requires monthly payments. In mobile telephony, the cost structure makes the pay-as-you-go model commercially feasible for the provider. For the operator, it means low revenue collection costs and low or zero credit risk. It gives users control over expenditure and, despite higher unit costs, is much more attractive for low-income households in developing countries. But the pay-as-you-go model does not by itself overcome the problem of the challenging cost structure of fixed-line telephony.

• Productive value (unmet demand): The services provided by mobile and fixed-line phones are similar, but the simplest mobile telephony functions offer important additional benefits. These appear to have a high productive value in developing countries by enabling telephony on the move.

• Policies and regulations (competition): Competition is easier to achieve in mobile telephony, and competition helped drive down prices and encouraged innovation. Empirical evidence suggests that it was a key driver of high levels of mobile phone penetration.

The cost structure of mobile technology is not the only factor driving growth in developing countries, but the prepaid/pay-as-you-go business model is made possible only by the core characteristic of low fixed user-specific costs. This model is attractive to low-income households and acceptable to operators. As penetration has

27 Costs may also be specifi c to a small group of users (for example, a small village) so that if some households do not use the capacity then it can be used by others within that village, but the capacity cannot be used by other villages. There is a progression of such types of infrastructure whose costs are fi xed and specifi c to individual users and increasingly large groups of users.

28 The pay-as-you-go model without fi xed monthly charges may be adopted by fi xed-line operators but typically only when governments place social obligations on the operators to serve rural or peri-urban communities that could not otherwise afford access.



increased, the costs of mobile telephony have fallen, making it more affordable, and to some extent increasing penetration even further.

The cost structure of mobile telephony appears to have been a necessary characteristic for the rapid growth in the market, though it was not sufficient by itself. Competition and reform appear also to play important roles but are not sufficient by themselves. Of equal importance was the enhanced functionality of mobile services and the unmet demand in developing countries for those functions.

6.7.2 Applicability of Mobile Telephony Drivers to APS

No evidence exists to suggest that the drivers of the revolution in mobile telephony will be replicated in the electricity sector. One driver—a favorable cost structure that makes a pay-as-you-go model attractive for suppliers—is missing from all APS models, with the possible exception of certain forms of coordinated private supply. If APS providers are unable to adopt a pay-as-you-go business model, competition (policies and regulation) by itself will not be enough to spark a revolution in distributed electricity supply to the base of the pyramid.

Nevertheless, there is an emerging industry of energy service companies offering what are advertised as pay-as-you-go solutions, both for mini-grids and individual power units, in particular solar home systems (SHS).29 Compared to the payment model typical for mobile phones, however, the flexibility in “pay-as-you-go” models for many mini-grid and SHS providers is considerably more constrained. In particular, many companies impose significant restrictions on the timing and size of payments. While a limited number of companies offer complete flexibility on when and how much customers must pay to maintain service, most either require customers to make weekly or monthly payments or to pay a total amount over a pre-determined period of time. The specific constraints imposed may depend on whether a fixed asset is provided on a lease-to-own basis or energy is provided as a perpetual service (the utility model). Companies with lease-to-own systems (only applicable to individual units) may be more likely to require a pre-determined total payment with flexibility in increments and timing, as from the company’s point of view the asset simply must be paid for in full by a certain date.

29 As detailing in an upcoming World Bank Group “LiveWire” note, to be published in late 2014.

The table “Payment Flexibility” identifies a number of mini-grid and SHS providers offering some degree of payment flexibility, their payment plans, and service model.30

Ultimately, the risks presented by user-specific costs are directly proportional to the level of under-usage or default. While it appears that a number of APS providers have been encouraged by the size and regularity of payments, even from low income customers on flexible plans, it is far too soon to know whether this trend will continue—and equally importantly, whether companies will be able to add significantly to their customer base without the fully flexible payment model used by mobile telephony.

In either case, however, it is important to recognize that APS technologies may ultimately be driven to scale up by factors that do not necessarily mimic those that drove the mobile phone revolution. This report has focused on the current state of APS systems, but technology developments in particular—for example, improvements in battery efficiency or continued reductions in solar PV costs—may be able to dramatically change the product offerings and overall costs of distributed energy supply. Smaller, more efficient batteries would increase the value of the variable renewable energy sources that drive many APS systems, lowering the cost of captive power (through reduced diesel purchases) and mini-grids (through more efficient generation sizing). It would also increase the ability of APS operators to meet their customers’ need for reliable, available power and, in the case of individual units, perhaps even low-cost, portable, charging stations. Lower solar panel costs would of course help reduce the capital costs of mini-grids and solar home systems, lowering individual consumer payments and thus expanding the potential customer base regardless of payment model.

30 It is perhaps worth noting that there does not seem to be a strong correlation between the level of user-specifi c costs and the fl exibility of the payment model offered. This does not imply that the cost structure is not important in determining the level of fl exibility that is sustainable; instead, each company is trying to fi nd a model that would work best for their own circumstances. Nonetheless, it appears that many providers have taken measures to reduce user-specifi c element of fi xed costs, from using much less expensive DC wiring (reducing user-specifi c connection costs) to specifi cally choosing high-density service areas (reducing the proportion of user-specifi c costs) to renting devices rather than leasing them to own (changing hardware cost from user-specifi c to easily transferable). All these measures reduce total costs as well, so it is diffi cult to determine the extent to which the user-specifi city of costs was a conscious factor in each decision.



References

Barrantes, Roxana, and Hernan Galperin. 2008. “Can the Poor Afford Mobile Telephony? Evidence from Latin America.” Telecommunications Policy 32 (8): 521–30.

European Bank for Reconstruction and Development. 2012. “Electronic Communications Sector Comparative Assessment.” London.

Feldmann, Valerie. 2003. “Mobile Overtakes Fixed: Implications for Policy and Regulation.” ITU, Geneva.

Fink, Carsten, Aaditya Mattoo, and Randeep Rathindran. 2002. “An Assessment of Telecommunications Reform in Developing Countries.” Policy Research Working Paper 2909, World Bank, Washington, DC. http://elibrary.worldbank.org/doi/pdf/10.1596/1813-9450-2909.

Gillwald, Alison, and Christoph Stork. 2012. “ICT Access and Usage Survey 2011: First Round Findings from the 2011/2012 Household and Individual ICT Survey.” Research ICT Africa Network, South Africa. http://www.researchictafrica.net/docs/RIA%202011%20ICT%20survey.pdf.

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———. 2012. “Sub-Saharan Africa Mobile Observatory 2012.” United Kingdom. http://www.gsma.com/publicpolicy/wp-content/uploads/2012/03/SSA_FullReport_v6.1_clean.pdf.

ITU (International Telecommunications Union). 2013. “ICT Facts and Figures 2013.” Database. http://www.itu.int/en/ITU-D/Statistics/Pages/stat/default.aspx.

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Kalba, Kas. 2007. “The Adoption of Mobile Phones in Emerging Markets: Global Diffusion and the Rural Challenge.” Prepared for the 6th Annual Global Mobility Roundtable, Center for Telecom Management, Marshall School of Business, University of Southern California, Los Angeles, June 1–2. http://classic.marshall.usc.edu/assets/006/5577.pdf.

———. 2008. “The Global Adoption and Diffusion of Mobile Phones.” Center for Information Policy Research and Harvard University, Cambridge, MA. http://pirp.harvard.edu/pubs_pdf/kalba/kalba-p08-1.pdf.



OECD (Organization for Economic Co-operation and Development). 2011. OECD Communications Outlook, Section 7. Paris.

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65

7 Key Findings

From the case studies we can draw two broad conclusions:

• The best solution depends on national circumstances, site location, and time (economic growth, international trends in price of fuels, technological developments, and other changing factors). There is no one-size-fits-all solution, and there is no solution that is best under all circumstances and at all times. All the APS solutions can be optimal under some circumstances, but more conventional solutions can be optimal under other circumstances.

• The best solution is not always the optimal solution. Many developing countries experience chronic power shortages from time to time. Though the long-term optimal solution may be for conventional utilities to develop conventional power generation and networks, consumers may have to wait a very long time for this solution, or even a semblance of it. In such circumstances, APS solutions provide a good second-best solution and are far better than the alternative of blackouts or self-generation using expensive and dirty diesel fuel.

Some specific findings from the case studies:

• Captive power using cogeneration or waste is attractive for all parties. P2P is attractive because it encourages efficient developers and operators to come forward (India). However, some captive power and P2P schemes are made attractive by distortions in tariffs, which causes problems for incumbent utilities. Solutions (such as surcharges) are available to neutralize these distortionary incentives while continuing to encourage attractive schemes.

Captive power and P2P arrangements have been useful ways to minimize or avoid problems caused by failures of conventional power companies to provide reliable supply. Creative arrangements (as in Zimbabwe and in Pune, India) have been introduced to supply power selectively to those willing to pay or to improve reliability more generally. In Pune, P2P is driven partially by the poor reliability of the incumbent utilities.

• Mini-grids have been successful in Asia, but despite large subsidies, they have been less successful in Africa. Low affordability, low consumption levels, and high costs per kW or kWh supplied are the main constraints and causes of failure. Other mini-grids in Africa may have failed because communities they serve lobby politicians who then impose ceilings on the tariffs to match the (subsidized) prices charged by the main grid company or because the community is unwilling to pay tariffs that are higher than those charged by the main grid company.

• SPD systems can be a good way to achieve electrification goals when conventional routes (through the grid company) are not available (as in Cambodia).

• Coordinated supply of individual generation can be very attractive and can become self-sustaining without subsidies once the solar PV market is established (as in Mongolia and India). Coordinated supply is often the best solution to electrification in communities in rural areas far from existing grids, with low incomes, low density, or difficult terrain. Even in electrified areas, coordinated supply can be the best option for users with low demand.

The mobile telephony revolution had three main drivers:

• Technology and cost structure: The cost structure of mobile telephony is unlike that of other network services because the technology requires fixed user-specific costs that are relatively low. This makes it financially viable for operators to offer telephony services on a pay-as-you-go model to low-income users who have low monthly consumption.

• Business model: For traditional fixed-line telephony services, financial viability for providers requires monthly payments from customers. For mobile telephony services, as just noted, this is not the case. The avoidance of fixed charges and the use of pay-as-you-go charging give users control over expenditure in situations where income can be erratic.



• Competition: Competition is easier to develop with mobile telephony, and competition helped drive down prices and encourage innovation. Empirical evidence suggests that competition was a key driver in particular for the high levels of mobile phone penetration.

The technology and its cost structure was the necessary condition; without it, the revolution would not have occurred. Competition was a driver but not sufficient by itself.

These three drivers do not appear to exist at present in the electricity sector. All current APS models are missing a favorable cost structure, one of the fundamental drivers. Innovation in battery technologies has the potential to make the cost structure of one of the APS models (coordinated individual supply) closer to that of mobile

telephony and, when combined with a rental and battery-charging business model, could spark a revolution in supply of some electricity-related services to those at the base of the pyramid.

If a revolution occurs in the electricity sector, it will have different drivers. The most likely is that technological developments will lower the cost of solar PV technology which, combined with improvements in battery technology, will make solar PV competitive with grid-supplied electricity. Captive power, P2P, mini-grids, and coordinated individual supply would all benefit from such technological-cum-price developments. Only in the case of coordinated individual supply might falling technology costs trigger a change in cost structure and a revolution that would be analogous to that of mobile telephony.


67Empirical Studies

Annex 1Empirical Studies

Many empirical studies have sought to understand the benefi ts of the mobile phone revolution in developing countries. Others have attempted to untangle the primary causes of that revolution. A 2007 paper by Jonathan Donner entitled “Research Approaches to Mobile Use in the Developing World: A Review of the Literature”31 reviews 200 studies covering a range of topics, including the high rates of mobile phone diffusion or penetration. This appendix summarizes some of those studies. Some were undertaken about 10 years ago when the revolution had really only just begun and penetration rates were still relatively low; nevertheless, they provide some insights into the causes. One of the studies relates to the cost structure of mobile telephony, which was a key factor.

Harvard University and Center for Information Policy ResearchHarvard University and the Center for Information Policy Research sponsored a study entitled “The Global Adoption and Diffusion of Mobile Phones” (Kalba 2008), which sought to assess key drivers across the world. Although it did not focus particularly on developing countries, it did cover some and addresses the issues relevant to APS. A parallel paper entitled “The Adoption of Mobile Phones in Emerging Markets: Global Diffusion and the Rural Challenge” (Kalba 2007) focused more on developing countries.

The methodology did not rely on econometric analysis but on fi eld studies in both developed and emerging markets, combining survey research, some statistical analysis, and international benchmarking. Some of the author’s conclusions relate to specifi c issues relevant to comparisons with the electricity sector:

• Not a response to failures by fi xed-line operators. The author describes a close association between fi xed-line phone connections and mobile phone adoption in emerging markets, including low-income African countries. This runs contrary to the common view that

31 This document is posted on the Internet by the author, published with the permission of the Taylor & Francis Group.

users often adopt mobile phones because traditional fi xed-line operators are unable or unwilling to connect them. It is also contrary to the author’s fi ndings for the United States: he concludes that the very high number of fi xed-line connections there was one reason why the mobile penetration rate was low at the time of the study.

• The impact of pricing. The author fi nds that call charges have a signifi cant impact on talk time and that inter-country variations in talk time are not, as is commonly believed, due to different cultures. He also he notes that the relationship between price and penetration is complex.

• Prepaid charging. The author emphasizes the role of prepaid technology in the penetration of mobile communications in both developed and emerging markets. He concludes that the prepaid model has been the most important product innovation: “Prepaid has made mobile communications accessible to nonsalaried individuals, who on a worldwide basis outnumber people with automobiles and people with fi xed salaries—the targets of the fi rst two waves of mobile adoption.” He does not, however, identify factors that made prepaid charging possible for mobile telephony providers.

• Cost of handsets. The author acknowledges the important role of low-cost handsets in increasing the penetration rate in developing countries.

• Competition. The author fi nds that competition has positive effects until more than four operators enter the market.

GSMA—Comparison of Fixed and Mobile Cost StructuresA 2007 report from the GSM Association (GSMA) analyzed the cost structures of fi xed-line and mobile telephony, both qualitatively and quantitatively. The analysis considered intuitive and theoretical reasons why the cost structures might differ, including these:

• Treatment of access network costs

• Scarcity of spectrum

• Useful lives of assets

• Age of networks

• Scope and scale economies

• Ability to reduce costs through cost sharing

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The report also looked at the implications that the signifi cant differences in cost structure have on regulated cost-based charges for fi xed and mobile call termination. Though it did not directly address the issue of what drove the revolution in mobile telephony in developing countries, its analysis is relevant to this issue:

The biggest single difference is the access network and how its costs are driven and hence should be recovered. The access network in a fi xed network (predominantly the copper loops) is almost entirely driven by the number of subscribers, and increases in traffi c, independent of the number of subscribers, require no further investment in the access network. As such, the costs of the access network are appropriately recovered from a subscription service. This is not the case for mobile networks, where the access network (base stations and associated equipment) is not dedicated to individual subscribers. An increase in traffi c on mobile networks does require further investment in the access network. As such, the costs of the access network are appropriately recovered from traffi c services.

The report also noted other factors that lead to different cost structures. In sum, it concluded, “[T]hese differences support the view that the cost of a unit of traffi c is more expensive on a mobile network than on a fi xed network and that such a cost difference is unlikely to disappear in the foreseeable future.”

UN—World Institute for Development Economics ResearchA research paper from the World Institute for Development Economics Research (WIDER) (Rouvinen 2004) considered whether the drivers for mobile telephone penetration differ fundamentally in developing and developed countries.32 Although the paper did not directly address the question of what drove high rates of penetration in developing countries, it did address this question indirectly. The research examined data for 1990–2000 covering about 200 countries. In 2000, the average penetration rate in developed countries was 34 percent

32 This was studied using a Gompertz growth model.

while the average rate in developing countries was only 5 percent. The results of a similar study today using data over a 20-year period might be substantially different.

For the purposes of the APS study, fi ve drivers33 were particularly interesting:

• The availability of prepaid charging (prepaid cards). This variable was found to be very statistically signifi cant. Those countries with prepaid options had substantially higher penetration than those without. This was also true in developed countries but the effect was markedly lower and the supporting data less statistically robust.34

• The number of mobile phone network standards. This variable was also found to be highly statistically signifi cant. The research found that countries with more than one network standard had a substantially lower penetration rate than those with only one network standard.

• Competition. Although the research did not assess the impact of competition in developing and developed countries separately, it found substantially higher penetration rates overall in those countries with two or more competing operators than in those with only one operator.

• Price. The research found a relatively weak effect of mobile phone prices on penetration. The parameter was the monthly charge for 120 minutes of local peak-time calling. Because this fi nding was not statistically robust and had the wrong sign,35 conclusions cannot be drawn from it. The variable itself may be inappropriate for measuring typical mobile phone usage in developing countries.

33 Other factors affecting penetration included population size (which suggests that larger developing countries tend to have higher penetra-tion rates, probably refl ecting a relatively high number of potential us-ers with a reasonable income) and democracy. Other factors included in the equation that are likely to correlate with penetration rather than drivers of penetration were the use of personal computers and the penetration of analog mobile phones.

34 That is, it was not statistically signifi cant at the normally accepted 5 percent confi dence level.

35 The value of the parameter was positive, suggesting that higher calling charges lead to a small increase in penetration.


69Empirical Studies

• Cost of mobile phone handset. As with price, the research did not fi nd a statistically robust effect of the cost of mobile phone handsets on penetration.

International Telecommunication Union (ITU)A 2003 ITU study ((Feldmann 2003) investigated, among other things, the key drivers and inhibitors of the growth in mobile communications. It did not analyze the drivers empirically.

World Bank—Development Research GroupA 2002 paper by the World Bank’s Development Research Group (Fink et al. 2002), like the WIDER study, was a large-scale econometric analysis of a large number of

countries (86). And like the WIDER study, it used data from the preceding decade or so (1985–99). However, it focused primarily on the effect of telecommunications reform on the performance of the sector.

The research showed that both privatization and competition improve performance signifi cantly, but the largest gains come from comprehensive reform involving policies and an independent regulator. Performance was described in terms of productivity, measured in terms of “teledensity,” or penetration. It also showed that liberalization (privatization plus competition and an independent regulator) led to an 8 percentage point increase in teledensity. However, these effects were dominated by other drivers which were not analyzed directly. The authors recognized the need for further research into these drivers.


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