Where it’s beneficial, state utilities in Sub-Saharan Africa can leverage distributed private-sector business models to extend the grid to areas without electricity access or make critical upgrades —without going further into debt.

In the industrialized world, public electric utilities in regulated markets are tasked with a universal service mandate, an obligation to extend and maintain service to all customers in their service territory.

In contrast (with a few notable exceptions) their Sub-Saharan African counterparts are either unregulated, are not necessarily obligated to provide universal service, have such serious cost-recovery issues that they cannot fulfil the obligation, or face unenforced or unfunded mandates to maintain and extend service to new customers.

Power for All’s Energy Access Target Tracker shows that less than 30 percent of Sub-Saharan African countries have stated rural electrification targets.

But even for utilities that are actively trying to connect rural customers, last mile distribution and rural grid extension are notoriously difficult and expensive, notwithstanding existing system reliability issues and line loss rates.

Simply put, they either don’t face or cannot meet a universal service mandate through business-as-usual operations, leaving more than 600 million potential customers across the continent on the table and in the dark, including 110 million living directly beneath existing grid infrastructure.

Fiscal woes

Part of the problem is that all but two of Sub-Saharan Africa’s public electric utilities run quasi-fiscal deficits between their capital/operating expenses and cash collected.

These deficits can be due to non-cost reflective tariff structures, significant system underperformance and line losses, power theft, customer payment delinquency, corruption, or general mismanagement. Across the continent, utility deficits average USD $0.12 per kilowatt-hour and can range as high as $0.49 per kilowatt-hour.

Figure 1: Grid extension projects in Sub-Saharan Africa can cost up to $5.5M per MW/km

Source: GTM Research and Power For All

Grid infrastructure upgrades are big projects, particularly for cash-strapped utilities. A GTM Research-Power for All snapshot of ongoing grid extension projects in Sub-Saharan Africa shows that unit costs for these projects average well over $1 million/MW-km (the cost of transmitting 1 megawatt of power a distance of 1 kilometer), and take an average of five years to complete.

Extensive planning, procurement, and construction phases, and infrastructure precautions like environmental and social impact assessments weigh heavily on budgets and extend project timelines, compounding the economic opportunity cost of access to energy. A

Power for All analysis of World Bank-funded grid extension and power projects between 2000 and 2014 finds on average projects cost $2,500 per connection and take nine years to materialize. Other studies find similar averages ($2,300 per connection in Tanzania).

Even when these projects are completed, customer capture issues — including high connection fees, which average US $136 per single-phase connection across the continent, often more than double average monthly income — mean that even well-planned and necessary grid extension projects are often doomed to be unprofitable, let alone rural grid extension projects with high marginal costs and low concentrated demand.

Figure 2: Connection charges are prohibitively expensive 

Source: World Bank, 2016

Further, evidence shows that traditional large-scale public investment projects into grid extension and transmission upgrade projects have not significantly grown the utilities’ customer bases.

A World Bank study examined six different measures of fiscal deficit against GDP, access rates and the poverty gap for Sub-Saharan African countries, and found no statistical correlation, concluding that there is “little indication of a tradeoff between quasi-fiscal deficits and access.” Public investment into grid extension has not been an effective model for expanding energy access or enjoying its requisite economic benefits in the African context.

The challenges of traditional grid extension projects and service provision are clearly evidenced through the case of Kenya Power and Lighting Company (KPLC), which owns and operates most of the electricity transmission and distribution in Kenya. In 2015, KPLC launched the US $150 million Last Mile Connectivity Project, which extended low-voltage distribution networks country-wide and introduced a subsidized connection fee of $150.

In one year, this installment-based payment plan ostensibly led to a 30-fold increase in electricity connections in low-income districts. But the project was marred by cost overruns and inflated and misreported new connection numbers. On top of this, newly connected households often have very low consumption levels and low-income customers were often unable to make their connection payments, even at subsidized rates.

Furthermore, without the necessary supporting distribution upgrades, local experts argue that the program has put a strain on the technical and financial resources of the utility, putting cost recovery and reliability at serious risk. Indeed, KPLC is now embroiled in a pending High Court case over public claims of inflated, back-dated and wrongly estimated customer bills.  

Decentralized utility business models

Emerging market utilities need to understand the impact of digitized, decarbonized, and decentralized technologies on their electrification strategies. In many service territories, they have not been given a choice to ignore these changes, as the penetration of private pay-as-you-go (PAYG) solar home systems are already making a dent in targeted customer expansion strategies.

Scale-appropriate solar home systems and mini-grids can be far more rapidly, affordably and easily deployed to reach last-mile consumers and have created a billion-dollar sector that is well poised to meet last mile needs. Mini-grids, for instance, can service customers at $500-1000 per connection, roughly between a third and half the average cost of grid extension.

The Tanzanian government estimates that about half its rural population may be served more cost-effectively by decentralized options like mini-grids. Similarly, the IEA finds that decentralized renewables offer the least-cost solution for three-quarters of additional electricity connections needed in Sub-Saharan Africa.

The utility of the future in Sub-Saharan Africa will thus need a suite of innovative, modern legal and policy frameworks to implement this integrated vision. Here are a few decentralized utility business models that could accelerate rural electrification and the transition to a financially sustainable future.

Utility concessions are public-private agreements — often competitively tendered — that allow private firms to obtain rights to provide services under government partnership or oversight. These partnerships are a means to leverage private capital and must have a clear legal structure that balances between ensuring adequate financial returns and meeting the public objectives of the governing agency, particularly given that the fundamental economics of grid-based rural electrification remain difficult.

According to a 2017 World Bank study, this typically requires a combination of subsidies, cost-sharing agreements, loan guarantees, and a well-designed tariff regime. Public-private grid extension concessions for improving energy access have successfully increased access rates in Cameroon (ENEO), Uganda (Umeme), and Gabon (SEEG), and were also used in Côte d'Ivoire (CIE), where access rates have not yet seen significant improvement. Of course, for more forward-thinking utilities, the concessions model could also be used to create command and control markets for mini-grids or even solar home systems, but there is limited proof-of-concept success to date in this area.

Distribution franchising could similarly create public-private partnerships for electricity distribution networks and revenue collection at the end of the grid. This model was implemented in India in 2005, with positive results in more than a dozen Indian states according to a 2012 TERI analysis, but was scaled back in 2012-2013 in part because of opposition by state-owned distribution companies.

Depending on local teams responsible for meter reading, billing, and signing up new connections, the distribution franchising model has been shown to improve revenue sustainability for distribution companies (DISCOMs), reductions in customer grievances and power theft, and increases in new customer sign ups.

According to Power for All, with distributed energy solutions deployed by rural micro-utilities that are “grid-interoperable, while providing a more nimble, customer-centric and flexible electricity supply,” make even more sense, and have already seen interest from major private energy companies after some initial success with the state utility in Odisha state.

Rural electricity cooperatives are typically islanded generation and distribution infrastructure systems — connected to the national grid upon its arrival — that are owned by the rural customers off-taking power from the system. They are typically financed by cheap credit, either offered or guaranteed by a government agency.

This model was pioneered in the United States in 1935 through the Rural Electrification Act under President Roosevelt’s New Deal. It is not currently popular with African utilities. In Burkina Faso, one of the few countries in the region that has embraced the cooperative model, there are at least 93 cooperatives authorized by the national utility SONABEL to manage their local distribution network, though their performance thus far has been disappointing.

Despite more than half being connected to the national grid in the last decade, the majority of Burkina Faso’s cooperatives are not financially sustainable and depend on regular funding and increased subsidies from the country’s Electricity Development Fund, which is funded through a cross-subsidization levy on SONABEL’s bulk power sales. These subsidies are primarily applied toward the purchase of diesel fuel.

More problematically, cross-subsidization simply does not work when the connections that should be profitable do not cover their own costs (SONABEL currently runs an estimated quasi-fiscal deficit of $0.11/kWh). While this is a far from picture-perfect case, the co-operative model has been successful even in the United States, with over 900 consumer-owned electric co-operatives today, and shows promise in the African context, particularly for solar mini-grids with very low operating costs.

Regulatory frameworks for micro-utilities and distributed energy service companies (DESCOs) are critical to clarifying how the national utility defines a mini-grid, streamlining the permitting process, and predetermining outcomes and tariffs if/when the grid arrives to a site containing a mini-grid.

Without this policy certainty, micro-utilities and DESCOs face an outsized risk of sinking capital into an unpermitted project or holding a stranded asset. Policies enacted in Nigeria, a few key states in India, and in Tanzania have blazed the trail for lessons on best practices regarding cross-subsidization mechanisms, tariff setting, and sizing buckets. In markets without these signaling policies in place, such as Ghana, national tariffs apply to mini-grid development unless exempted, putting cost-recovery almost certainly out of reach and keeping that project’s capital on the sidelines.

When developed alongside decision-makers from the public utility, as in the case of Tanzania’s TANESCO, DESCO policies can create a viable market for islanded mini-grids operating in the service territory of a national public utility. Without clear regulatory frameworks as a starting point for implementation, mini-grid developers are competing for customers with an unpredictable state utility.

Innovate and integrate

It is time for utilities in Sub-Saharan Africa to evolve their approach toward universal energy service provision by thinking beyond public infrastructure investment toward integrated electrification planning that accounts for the role of decentralized renewables already being deployed. This comes in part by addressing fiscal deficits, and in part by moving toward distributed business models like concessions, franchising, co-operatives, and clear DESCO policies that can allow private capital to start to bridge the deficit gaps keeping Sub-Saharan African utilities deeply in debt.

Developing transparent and comprehensive master grid extension planning that allows DESCOs to have a clear picture of the shape and size of their market and long-term risks is critical. Morocco’s national utility ONE’s leadership provides an excellent case study on the possible results of well-coordinated electrification efforts.

While integrating decentralized renewables holds much potential, less than 1 percent of those with access in developing countries currently benefit from them, and they also receive less than 1 percent of total electricity investments. Much work is still needed to drive investment in the sector and improve affordability of such technologies for consumers.

Sub-Saharan African utilities should move away from the binary thinking of grid vs off-grid solutions. While centralized grid extension is certainly useful, distributed technologies are proving themselves a critical component to integrated energy planning efforts that balance cost, timeline, reliability, decarbonization, and changes in population dynamics and load growth over time, while increasing systems resilience.

Grid extension has never been sexy and is not always the right solution for providing reliable electricity access, but getting it right is a necessary step in the transformation from massive deficits to utilities of the future.

Ben Attia is a global solar market analyst at GTM Research; Dr. Rebekah Shirley is the research director at Power for All.





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