adminNearly a third (at least 8 / 26) of the Tripartite countries produce and consume less than one GW per year (1). This low national demand does not justify power plants large enough to exploit economies of scale and this contributes to inflated generation costs. An uneven distribution of other, cheaper energy sources – in the absence of effective trade mechanisms, have forced countries without domestic resources to adopt technically inefficient forms of generation reliant on expensive imported fuels.
In fact, it is almost twice as expensive to operate a predominantly diesel-based power system in comparison to a predominantly hydro-based system. The vast majority of hydropower potential in the Tripartite region, however, is found far from centers of demand in only two countries, namely the DRC and Ethiopia. Both these countries have a GDP of less than $30 billion and, in a fragmented energy market with limited possibility of trading electricity within the region, their full hydropower potential cannot be developed [2]. A larger, interconnected regional energy market, by contrast, would make large, regional power plants more viable and attractive for (potentially cheaper) investment funding.
Over the past two decades, Africa saw the establishment of a number of power pools with the objective of optimising the use of energy resources and increasing cross-border electricity trade. In the Tripartite Region these include, primarily, the Southern Africa Power Pool (SAPP) and the Eastern Africa Power Pool (EAPP). In SAPP, the total installed generation capacity is 9,9 GW (86% operational), while in EAPP it is 1,2 GW (69% operational)
Prerequisites for Successful Integration of Electricity Systems
Despite the substantial potential economic benefits of regional co-operation, actual electricity trade flows in the Tripartite region have been fairly modest so far. In SAPP approximately 10% of total consumption came from trade activities in 2008. This share has since dropped significantly due to general energy shortages. Most of the electricity trade in SAPP, furthermore, is governed by bi-lateral contracts, for example between South Africa and Mozambique and Zambia and Namibia. In the EAPP, only 2,1 % of total consumption came from trade activities in 2005 [5].
Effectively integrated electricity markets and increased electricity trade in the Tripartite region will require solutions to a range of political, institutional, operational and financial obstacles. Below is a summary of some of the requirements for development of an effective regional electricity market (requirements have featured to various degrees in studies of SAPP and EAPP over recent years):
Sector unbundling. Both public and private vertically-integrated utilities generally have strong incentives for self-dealing and thus a continuing high degree of vertical integration could hinder the interchange of power and the extent of cross-border competition that could emerge. Some form of unbundling is necessary in order to avoid the possibility, for example, of network constraints being used as an excuse by vertically integrated utilities (with a general tendency for self-preference towards their own generating units) to exclude competitors and effectively erect barriers to the free cross-border flow of electricity [6].
Open access to transmission. Every country should have transparent, objective and non-discriminatory rules making its transmission facilities available to regional electricity entities on a “fair and equal basis”. Crucial is the publication of technical rules for connection, and a clear definition of equal treatment and non-discrimination. There is also a need for an effective dispute resolution process to deal with cases of refusal or suspension of access. These requirements should be ideally embedded in SAPP and EAPP Grid Code rules.
Free choice of supplier. Purchases and sales should be non-discriminatory. Any restrictions to regional power transactions should be based only on explicitly agreed-upon quality and safety standards with buyers and sellers paying for the losses and congestion they create in the system.
Harmonisation of regulation and market structures. Disparities of regulatory treatment across borders can introduce distortions that hinder both electricity trade and the aggregate flows of investment to the sector on regional basis. Similarly, market opening and restructuring must have a parallel development (reciprocity) across countries.
Otherwise, significant differences in market structures (e.g. in vertical structure and the type of ownership) could hinder cross-border trade. Regulatory harmonization, the elimination of trade-distorting inefficient national regulations, and regulatory cooperation to overcome domestic constraints on regulatory capacity are essential components of regional economic integration.
Tariff rebalancing. When there are significant cross-subsidies embedded in the structure of tariffs, regional trading that may appear to be economically advantageous may actually be inefficient. Even suppliers with inefficiently high costs may find exporting profitable in reaction to pricing that provides a flow of subsidies.
Harmonization of administrative procedures. National permissions, concession and approval procedures related to national or cross-border infrastructure should be harmonised. When administrative procedures vary significantly across countries, it is very difficult to assess and implement cross-border projects.
High-capacity intersystem tie lines. For the benefits of regional coordination and energy transfers to obtain there is a need for high-capacity transmission links. These intersystem tie lines also contribute to improved regional system stability and reliability.
The Cost to Integrate Electricity Systems and Anticipated Savings
Developing sufficiently integrated regional infrastructure to support electricity trade within and between the SAPP and EAPP pose substantial financial challenges.
The region has to address its infrastructure backlog by providing broader and more reliable infrastructure access, but it also has to keep pace with the demands of economic and population growth as well as with targets to increase access to electricity.
Rosnes and Vennemo (2008), as part of the Africa Infrastructure Country Diagnostic study, developed a model to analyze the costs of power sector expansions over a ten-year period, using varying assumptions to test for the lowest cost / most optimal solution.
The model simulates strategies for generating, transmitting, and distributing electricity in response to anticipated demand increases in the four power pools of Sub-Saharan Africa.
This study estimates that, even if electrification rates remain at their 2005 level (7) SAPP will require almost 31 GW of new capacity, and will have to rehabilitate an additional 28 GW of existing capacity in order to meet demand by 2015.
Investments in new generation capacity will cost approximately $30.3 billion, and rehabilitation of existing generation capacity will cost $7.5 billion. Significant investments are also required in the transmission and distribution of electricity to consumers, including $3 billion for cross-border transmission lines, as well as a $12 billion for improvements to the distribution grid. Total investment costs in SAPP therefore amount to approximately $64 billion.
Under the same scenario, the EAPP will require 23 GW of new capacity while 1 GW of existing capacity will have to be refurbished to accommodate market demand growth by 2015. Expanding the generation system accordingly will cost more than $29 billion, of which investments in new capacity accounts for the vast majority of costs.
Additionally, a $1,3 billion investment will be required in transmission lines, while a $7,5 billion will be needed to improve the grid.
The cost of connecting new customers to the grid will amount to $3 billion, or 40 % of the total grid investment. The total investment in transmission and distribution of electricity as well as in connection, therefore totals $11 billion. The overall investment cost in EAPP can be estimated at $40.2 billion [8].
Under these assumptions, seventeen countries in Sub-Saharan Africa face significant funding gaps for their power sectors. By far the most salient cases, both in the Tripartite region, are Ethiopia and the Democratic Republic of Congo.
Ethiopia has an annual funding gap of 23 % ($2.8 billion annually) of its GDP, while the DRC has an annual gap of 18 % ($1.3 billion a year) of its GDP. Mozambique and Madagascar both have funding gaps of 5–10 percent of GDP, while South Africa, Rwanda, Namibia, Zambia, Tanzania, Kenya and Uganda have funding gaps of 1–5 percent of GDP [8].
Pooling energy resources through regional power trade promises to significantly reduce these power costs. Savings of between 5 and 6 % would be achieved on annualized power system operating costs in the SAPP and EAPP Power Pools if energy trade occurred whenever the benefits outweigh the costs associated with system expansion.
These savings can be viewed as a return on the additional capital investments required to facilitate cross-border transmission. Under this scenario, additional capital investment is recovered in under a year in the SAPP – yielding a return of 167 %. In the EAPP, additional investment is recovered over a 3 to 4 year period for a still positive 20–33 % return on investment [8].
Cross-border electricity trade would save money mainly through substituting hydropower for thermal power – leading to a significant reduction in operating costs [8]. It also reduces losses due to power outages by smoothing temporary irregularities in supply and demand in national markets, for example by allowing peak and off-peak power trading between countries with different time zones.
Electricity trade, furthermore, diversifies the generation mix across countries and energy sources, thereby mitigating risks arising from conflict, high oil prices and prolonged drought, which could affect hydro-power generation and lead to energy shortages.
Examples of interruptions to hydropower electricity generation as a result of severe drought include the 1992 drought in Zimbabwe, during which Kariba Lake’s generation dropped to only 8% of its normal capacity. After the drought in 2004, all of Tanzania’s hydroelectric plants were operating at half their normal capacity while, in 2000, Kenya and Tanzania were forced to ration electricity due to persistent drought. – Trade Mark Southern Africa.
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