From Subsidy to Sustainability:
Diagnostic Review of Sudan’s Electricity Sector
Final Report
June 30, 2019
1
Acknowledgements
This diagnostic review was prepared by a World Bank team led by Kenta Usui (Energy Specialist) and
including Laurencia Karimi Njagi (Senior Energy Specialist) and Mbuso Gwafila (Senior Energy Specialist),
Ananda Covindassamy (Energy Consultant), and Amin Sabri (Energy Consultant). Analytical input was
provided by Samuel Kwesi Ewuah Oguah (Senior Energy Specialist), Debabrata Chattopadhyay (Senior
Energy Specialist), Rhonda Lenai Jordan (Energy Specialist), Isaura Espinosa De Los Monteros (Consultant
– poverty and social impact assessment), Donghui Park (Consultant – least-cost planning analysis), Hicham
Latnine (Consultant – geospatial analysis), Kawther Berima (Consultant – geospatial analysis). Additional
analytical support was provided by LDK Consultants and MRC Consultants. The document was edited by
Molly McCloskey.
The diagnostic review was developed in close collaboration with Sudan’s Ministry of Water Resources,
Irrigation and Electricity (MoWRIE) and its related sector entities, as well as the Ministry of Finance and
Economic Planning (MoFEP). Special appreciation goes to engineer Adil Ali Ibrahim (Director General of
Policy and Planning, MoWRIE) and Ali Abdalrahman Ali Adam (Director, Planning and Policies, Sudan
Electricity Holding Company), who facilitated this diagnostic review from the Government of Sudan as the
focal points.
The team benefited from discussion with representatives in Khartoum of European Commission, United
Nations Development Programme (UNDP), Embassy for Sweden, and British Embassy.
The team would like to thank internal peer review inputs provided by Defne Gencer (Senior Energy
Specialist), Debabrata Chattopadhyay (Senior Energy Specialist), Mikul Bhatia (Senior Energy Economist),
Victor Loksha (Senior Energy Economist) at the concept review stage, and Defne Gencer, Joeri de Wit
(Energy Economist), Alvin Etang Ndip (Senior Economist), and Daniel Stanley Kanda (Deputy Division Head
- International Monetary Fund) at the decision review stage. Additional review by Ani Balabanyan (Lead
Energy Specialist) for quality enhancement is gratefully acknowledged. Managerial guidance and review
were provided by Sudeshna Ghosh Banerjee (Practice Manager), Adama Coulibaly (Country
Representative of Sudan), Richard Spencer (Program Leader), and Nicole Klingen (Country Program
Coordinator).
The team is grateful to the Energy Sector Management Assistance Program (ESMAP), including its Energy
Subsidy Reform window, which partially funded this work.
2
Abbreviations
BAU Business as Usual
CAGR Compound Annual Growth Rate
CAPEX Capital Expenditure
CBoS Central Bank of Sudan
DIU Dam Implementation Unit
DO Diesel Oil
EAPP Eastern Africa Power Pool
ERA Electricity Regulatory Authority
ESMAP Energy Sector Management Assistance Program
GDP Gross Domestic Product
GIS Geographic Information System
GoS Government of Sudan
HCGO Heavy Coked Gas Oil
HFO Heavy Fuel Oil
HV High Voltage
IFI International Financial Institution
IMF International Monetary Fund
IPP Independent Power Producer
LCP Least-cost Plan
LDO Light Diesel Oil
LFO Light Fuel Oil
MoFEP Ministry of Finance and Economic Planning
MoWRIE Ministry of Water Resources, Irrigation, and Electricity
MTF Multitier Framework
MV Medium Voltage
NEC National Electricity Corporation
NHHBPS National Household Budget and Poverty Survey
NPV Net Present Value
OECD Organization for Economic Co-operation and Development
O&M Operation and Maintenance
OPEX Operational Expenditure
PPA Power Purchase Agreement
PPP Public-Private Partnership
PPP Act Public-Private Partnership Act
PSIA Poverty and Social Impact Assessment
RISE Regulatory Indicators for Sustainable Energy
SAIDI System Average Interruption Duration Index
SAIFI System Average Interruption Frequency Index
SC Sponge Coke
SE4ALL Sustainable Energy for All
SEDC Sudanese Electricity Distribution Company
SEHC Sudanese Electricity Holding Company
SETCO Sudanese Electricity Transmission Company
SHGC Sudanese Hydropower Generation Company
3
SHS Solar Home System
SIP Social Initiative Program
STPG Sudanese Thermal Power Generation
SUBSIM Subsidies Simulation
UNDESA United Nations Department of Economic and Social Affairs
UNDP-GEF United Nations Development Programme-Global Environmental Finance
4
Table of Contents
Acknowledgements......................................................................................................................... 2
Abbreviations .................................................................................................................................. 3
Executive Summary ............................................................................................................... 8
Introduction ........................................................................................................................ 11
PART 1: SECTOR PROFILE ................................................................................................. 13
1.1: Sector Governance Structure ............................................................................................ 13
1.2: Sector Policies and Plans.................................................................................................... 14
1.3: Sector Performance ........................................................................................................... 16
1.4: Sector Challenges ............................................................................................................... 27
PART 2: FINANCIAL OUTLOOK.......................................................................................... 30
2.1: Sector Cost and Revenue ................................................................................................... 30
2.2: Medium-term Financial Outlook ....................................................................................... 33
PART 3: OPTIONS FOR SECTOR RECOVERY ....................................................................... 36
3.1: Measures to Manage Costs ............................................................................................... 37
3.2: Measures to Increase Revenues ........................................................................................ 44
3.3: Measures to Facilitate Reforms ......................................................................................... 47
Annexes
Annex 1: List of Current and Prospective Generation Assets in Sudan .................................... 49
Annex 2: Sudan’s Electricity Tariff Structure ............................................................................ 50
Annex 3: Electricity User Profile in Sudan................................................................................. 51
Annex 4: Power System Map of Sudan ..................................................................................... 52
Annex 5: Description of Key Sector Entities ............................................................................. 53
Annex 6: Least-cost Analysis for Sudan’s Electricity Generation.............................................. 55
Annex 7: Sector Capacity Building and Technical Assistance Needs ........................................ 57
References .......................................................................................................................... 58
5
List of Figures
Figure ES.1: Projected Sector Revenue Gap and Subsidy Needs to 2023 ...................................... 8
Figure 0.1: Evolution of Exchange Rate Between Sudanese Pound and United States Dollar ..... 11
Figure 1.1: Institutional Structure and Financial Flow of Sudan’s Electricity Sector .................... 14
Figure 1.2: Daily Load Curve in May 2018 .................................................................................... 17
Figure 1.3: Sudan’s Electricity Generation .................................................................................... 18
Figure 1.4: Power Transmission and Distribution Losses (%) in African Countries ...................... 20
Figure 1.5: High-voltage and Medium-voltage Network in Sudan ............................................... 22
Figure 1.6: Estimated Number of Unelectrified Households in Each State .................................. 23
Figure 1.7: SHS Model Developed by the GoS .............................................................................. 24
Figure 1.8: Distribution of Households Connected to the Grid (2014)......................................... 24
Figure 1.9: International Comparison of Sudan’s Residential Electricity Consumption ............... 25
Figure 1.10: Comparison of Electricity Tariffs in Sub-Saharan Africa ........................................... 26
Figure 1.11: Nominal and Real Electricity Tariff in Sudan ............................................................ 26
Figure 1.12: Expenditure for Electricity Consumption as Share of Household Expenditure ........ 27
Figure 2.1: Historical Revenue Gap and Subsidy .......................................................................... 32
Figure 2.2: Distribution of Electricity Subsidy by Region and Quintile ......................................... 33
Figure 2.3: Impact of Inflation on Future Sector Cost .................................................................. 34
Figure 2.4: Cost-reduction Measures to Reduce Sector Deficit ................................................... 35
Figure 3.1: Projected Sector Revenue Gap to 2023 ...................................................................... 36
Figure 3.2: Historical and Projected Electricity Access in Sudan .................................................. 38
Figure 3.3: Geospatial Map of Sudanese Grid and Population Settlements ................................ 39
Figure 3.4: Impact of Demand Growth Management on Sector Cost .......................................... 43
Figure 3.5: Social Tariff Threshold in Selected Sub-Saharan African Countries ........................... 44
Figure 3.6: Impact of Tariff Increase on the Well-being of Different Income Quintiles ............... 46
Figure A0.1: Comparison of Cumulative Generation CAPEX (US$, millions) ................................ 56
6
List of Tables
Table ES.0.1: Potential Short-term Actions for Sector Recovery (1–2 Years)................................. 9
Table 1.1: Large Power Generation Projects Included in Power System Plans and Their Actual
Status of Implementation ............................................................................................................. 15
Table 1.2: Electricity Demand Growth in Sudan (%) ..................................................................... 17
Table 1.3: Ownership of Key Electric Appliances in 2014 (grid-connected households) ............. 18
Table 1.4: 2017 Thermal Fuels for Power Generation in Sudan ................................................... 19
Table 1.5: Sudan’s Power System Scorecard (2017) ..................................................................... 20
Table 1.6: Percentage of Households and kWh Consumed by Tranche ....................................... 27
Table 1.7: RISE Score of Sudan...................................................................................................... 28
Table 2.1: Sector Cost and Revenue (2017) .................................................................................. 30
Table 2.2: Five-year Projection of Sector Cost .............................................................................. 34
Table 3.1: Potential Short-term Actions for Sector Recovery (1–2 Years) ................................... 36
Table 3.2: 2023 Installed Capacity with Least-cost Option........................................................... 40
Table 3.3: Impact of Imports on Cost of Supply ........................................................................... 41
Table 3.4: Cost Savings from Accelerated Development of Solar PV and Wind Generation
Capacity ......................................................................................................................................... 42
Table 3.5: Payback Time of Renewable Energy Program ............................................................. 42
Table 3.6: Percentage of Average Tariff Adjustment Needed to Achieve Fivefold Increase in Five
Years .............................................................................................................................................. 45
Table A0.1: Summary of Cost Savings (NPV 2019–2023 at 10 percent in US$, millions) ............. 55
Table A0.2: Comparison of Capacity (MW) and Generation (GWh) in 2023 ................................ 56
7
Executive Summary
Sudan’s electricity sector is operating efficiently from a technical standpoint, compared to other
countries in the region. Sudan has one of the largest power systems in Sub-Saharan Africa, with 3,500
MW of electricity generation capacity from hydro and thermal sources. System loss is relatively low for
the region, and bill collection is almost universal, making Sudan one of the top performers in Sub-Saharan
Africa in that category. Cost of service, which is estimated at US¢20 per kWh, is close to the regional
average. However, the sector does face many of the operational challenges common to countries in the
region with regard to management and finance. These include a low electricity access rate of 32 percent
and load shedding during summer peak hours.
The most urgent issue facing the sector is financial sustainability. Sudan’s electricity tariff is the lowest
in Sub-Saharan Africa, with a rate under US¢1 per kWh. Driven by the low tariff, electricity demand has
grown by 11 percent a year since 2013. Sudanese householders with grid access consume significantly
more electricity than their regional peers. Consequently, the sector has been increasing spending on
thermal fuels and capital investment to meet the demand. The Government of Sudan (GoS) is subsidizing
the sector by fully covering the cost of fuel and capital investment. The amount of this subsidy in 2017
was estimated to be SDG 14.7 billion (US$667 million), which amounted to 13.5 percent of GoS
expenditure and 1.8 percent of gross domestic product (GDP) in that same year. This level of subsidy has
significant implications for Sudan’s fiscal and macroeconomic management.
The subsidy does not reach the poor due to their limited access to electricity. Most electricity access is
provided for urban and relatively rich segments of the population. Electricity access in Kordofan and
Darfur regions is particularly limited. The sector has been connecting a significant number of customers
to the grid, but the increased access has been mostly offset by population growth.
In the coming years, sector costs will likely increase exponentially and may trigger a power crisis. Sector
costs will continue to increase due to the use of imported fuels and capital investments needed to meet
growing demand. These costs require payment in U.S. dollars, which will be very expensive given Sudan’s
rapidly depreciating local currency. The sector’s operational cost, which is largely the cost of fuel, is
projected to increase by 50 percent every year and reach SDG 560 billion (US$1.3 billion) by 2023. Given
the ongoing economic crisis and the GoS’s heavily constrained access to external financing, there is a risk
that the GoS cannot sustain the current subsidy level for fuel and capital investment. This will create fuel
shortages and constrain thermal generation output, resulting in the quality of electricity service
deteriorating, with frequent and long load shedding.
Figure ES.1: Projected Sector Revenue Gap and Subsidy Needs to 2023
600.00
SDG Billion
500.00
400.00
300.00
200.00
100.00
-
2019 2020 2021 2022 2023
Revenue SDG million Revenue Gap
Source: World Bank staff calculation
8
A range of policy measures can mitigate increases in sector costs. Key actions the sector can take to
mitigate cost increases are (a) using low-cost power from Ethiopia and Egypt by optimally utilizing the
existing interconnection, (b) redirecting available investment capital away from thermal generation to
domestic solar and wind generation, and (c) curbing demand growth through efficiency measures and
price signals. All of these measures can be implemented in the relatively short term. In particular, power
imports from Ethiopia and Egypt can potentially save US$200 million a year without major capital
investment.
The GoS may set an interim tariff target to guide the short-term tariff transition. The current level of
tariff, by far the lowest in Sub-Saharan Africa, is not sustainable and needs to be placed on an upward
trajectory. However, in the context of Sudan, additional revenue through tariff increase will do little to
close the revenue gap in the short term due to the exponential growth in costs driven by macroeconomic
factors outside the sector’s control. Therefore, operational cost recovery through tariff revenue is a
moving target. In such a context, an interim tariff that is independent of macroeconomic factors can guide
the sector’s short-term tariff pathway for several years. After achieving the interim target, the sector can
set a new target based on the sector and macroeconomic contexts at that point. The impact of tariff
increase on the poor will likely be limited as most of the poor are not connected to the grid. However, it
will likely affect the urban middle-class population. The GoS can implement a reform package that will
gradually increase the tariff and strengthen the social security net for those affected. Such reform plans
need to be strategically and effectively communicated to ensure understanding by the public, especially
the middle class. In addition to increased revenue, tariff is an effective instrument to curb unsustainable
demand growth and thus avoid increases in fuel and capital investment needs.
Finally, the sector needs to strengthen its planning capacity and corporate governance structure. The
sector’s planning has so far focused on system expansion to meet growing demand, paying limited
attention to sector sustainability and cost optimization. The GoS needs to develop in-house capacity to
carry out least-cost planning for electrification, power system development, and demand-side
management. To remain relevant, the plan will need to be flexible, reflecting changing sector context and
financing availability. In addition, the sector’s current corporate governance does not allow sector
companies to make autonomous investment and pricing decisions. To further improve sector efficiency
and transparency, the GoS may consider commercialization and corporatization of sector companies while
clearly delineating roles and responsibilities for policy making, regulation, and operational management
among sector entities.
Given the current volatility in political and economic circumstances, short-term policy actions are
critical to paving the path for sector recovery. Such options are listed in the table below.
Table ES.0.1: Potential Short-term Actions for Sector Recovery (1–2 Years)
Actions Responsible Entities
Optimizing cross-border trade
(These low-cost measures can save up to US$200 million a year.) SEHC and SETCO
• Complete technical studies and implement remedial measures to
increase power trade in cooperation with EAPP and the governments
of Ethiopia/Egypt.
• Agree on new/revised PPA as needed.
• Make supplementary investment to enable enhanced power trade.
Tariff adjustment/energy efficiency
(These measures will reduce electricity consumption growth and create an MoWRIE, including ERA
enabling environment for tariff reform.)
• Set interim target for tariff adjustment.
9
Actions Responsible Entities
• Raise the GoS’s internal awareness of electricity subsidy.
• Prepare and launch communications campaign for tariff reform.
• Reduce lifeline tariff threshold to 100 kWh/month and promote
energy efficiency.
• Introduce peak/off-peak pricing once technically feasible.
Least-cost planning/private sector engagement MoWRIE
(These measures will allow optimal allocation of budgetary resources and
strengthen GoS capacity to engage the private sector.)
• Carry out least-cost generation and electrification planning.
• Redirect planned capital investment to renewables while piloting
renewable energy IPPs.
• Engage the private sector in the off-grid electrification space.
This electricity sector diagnostic review constitutes the first step of the World Bank’s engagement in
Sudan’s energy sector. Additional analysis and technical assistance to help sector recovery will be carried
out to inform both policy decisions by the GoS and engagement by other development partners. In the
next phase of engagement, the World Bank will review the energy sector in its totality, with specific focus
on fuels.
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Introduction
1. Sudan’s economy faces extremely complex challenges. The secession of South Sudan in 2011 has
resulted in the loss of oil revenue, which constituted more than half of the Government’s budget at the
time. Furthermore, Sudan was placed under economic sanctions by the United States in 1997. These
sanctions were partially lifted in October 2017, allowing for financial and trade transactions between U.S.
citizens/entities and their Sudanese counterparts. However, the legacy of the long economic isolation
remains and is exacerbated by the inclusion of Sudan on the list of countries that sponsor terrorism.
Several successive changes in the administered exchange rate contributed to uncertainty about the
macroeconomic framework. Sudan’s economic performance continued to deteriorate in 2018 with GDP
declining by 2.3 percent, inflation at 64.8 percent, and the Sudanese Pound devaluing rapidly (Figure 0.1).
While economic sanctions imposed by the U.S. were lifted in 2017, Sudan remains on the State Sponsors
of Terrorism List.
Figure 0.1: Evolution of Exchange Rate Between Sudanese Pound and United States Dollar
60
Official Exchange Rate (USD/SDG)
50
40
30
20
10
0
Jun-13
Jun-10
Jun-11
Jun-12
Jun-14
Jun-15
Jun-16
Jun-17
Jun-18
Jun-19
Oct-18
Feb-10
Feb-11
Feb-12
Feb-13
Feb-14
Feb-15
Feb-16
Feb-17
Feb-18
Feb-19
Oct-10
Oct-11
Oct-12
Oct-13
Oct-14
Oct-15
Oct-16
Oct-17
Source: World Bank
2. Public and external debt remain high and unsustainable. Since the early 1990s, Sudan has faced
major economic challenges stemming from severe indebtedness and the accumulation of significant
external arrears. Sudan’s external debt was at US$58 billion in 2018, the equivalent of 111 percent of GDP,
with about 84 percent in the form of accumulated arrears. Sudan has been in nonaccrual status with the
World Bank Group since 1994, and development aid to support economic productivity and human
development outcomes has been scant. With a still-overvalued exchange rate, weak business
environment, and loose fiscal policies financed by money creation, external imbalances and inflationary
pressures are likely to intensify, raising risks of disorderly adjustment and compromising growth prospects
over time.
3. Sudan is a net importer of fuel products. Although Sudan was historically an oil exporter until the
secession of South Sudan, its current domestic production and distillation capacity is insufficient to meet
the domestic demand. Therefore it is importing a significant amount of oil products from the international
market.
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4. Electricity generation is the largest usage of oil products in Sudan. Sudan consumed
approximately 5.1 million tons of oil products in 20161, of which approximately 40 percent was for thermal
electricity generation and 17 percent for transport. It is likely that the share of electricity in oil-product
consumption has increased since 2015 due to increased power generation from thermal plants. The fuel
for private or commercial use is regulated and significantly subsidized by GoS.
5. In Sudan’s challenging economic context, electricity is important in two ways. First, it plays a
vital role in economic growth and diversification, which have been key to the development agenda
following the secession of South Sudan and the loss of oil revenue. Access to affordable and reliable
electricity will underpin development. Second, efficient and effective management of the electricity
sector is important to ensure fiscal sustainability of the GoS. In Sub-Saharan Africa, it is common for the
electricity sector to incur major financial losses and require capital injection by government budgetary
instruments. Such fiscal burdens reduce the availability of resources for other sectors, including health
and education, which are key to a country’s efforts to lift people out of poverty.
6. Against this backdrop, the GoS requested that the World Bank reengage in the energy sector to
strengthen its performance. As the first step of the reengagement, the World Bank carried out this
diagnostic review of the Sudanese electricity sector to identify key sector challenges and formulate
approaches to addressing them, and to identify engagement opportunities. The review was carried out in
close consultation with GoS counterparts and is based primarily on data provided by the GoS.
7. The diagnostics review provides electricity sector facts and prospects, as well as options for
sector recovery. Part 1 presents the historical electricity sector profile of Sudan, including its governance
structure, key performance indicators, and challenges. Part 2 presents the near-term sector outlook,
including investment, access, and financial prospects. Part 3 presents options to strengthen sector
performance, with particular focus on financial performance. The review includes broad spectrum analysis,
including legal and institutional frameworks, sector financial flow, geospatial analysis of electricity access,
least-cost analysis of generation expansion, and Poverty and Social Impact Assessment (PSIA). Considering
the limited availability of data related to Sudan in the public domain, this diagnostic review is an important
contribution to understanding the state of the sector and its ability to serve the needs of the Sudanese
people.
1
Data shared by GoS.
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PART 1: SECTOR PROFILE
1.1: Sector Governance Structure
8. Sudan’s electricity sector has been governed by the Electricity Act since 2001. This act
designated the National Electricity Corporation (NEC) as the body for electricity generation, transmission,
and distribution, and designated the Electricity Regulatory Authority (ERA) as the sector regulator. The
legal framework has been generally open to private participation in the areas of generation, transmission,
distribution, and third-party access to the transmission system. However, the act did not provide detailed
provisions for how the private sector could engage in the electricity sector; for example, there are no clear
procedures for independent power producers (IPPs) to obtain licenses and other permits specific to the
sector, and the sector lacks detailed and transparent regulations and procedures.
9. The GoS is strengthening its legal framework to attract more private investment in the sector.
The Electricity Act is now being updated to reflect the current sector context; it is expected to include
provisions for renewable energy and energy efficiency and clarify the role of the regulator in tariff-setting.
It also aims to provide for greater openness to the private sector by allowing private investment in isolated
grids and clarifying that the Sudanese Electricity Holding Company (SEHC) is the off-taker for power
purchase agreements (PPAs). Beyond the power sector, the GoS in 2013 introduced the National
Investment Act, which set certain incentives for priority sectors for Sudan’s development. More recently,
the GoS has been finalizing the Public-Private Partnership Act (PPP Act) to increase private participation
in infrastructure development, including the electricity sector. The PPP Act is expected to establish a High
Commission for public-private partnerships (PPPs) and a dedicated PPP Unit in the Ministry of Finance and
Economic Planning (MoFEP). This revised legislation is expected to provide more incentives for private
investment in the sector and promote renewable energy and energy efficiency.
10. Since 2010, the sector has been unbundled along technical lines. Until 2010, the NEC was
functioning as a vertical integrated utility, a state-owned entity fully responsible for electricity generation,
transmission, and distribution. In 2010, it was unbundled into five separate electricity companies (later
reduced to four).2 In 2016, the SEHC was created to oversee and own four of the subsidiary companies.
Within the unbundled structure, each subsector is self-contained and has a clear technical function. The
mandate of the Sudanese Hydropower Generation Company (SHGC) was extended in 2018 to include
other forms of non-hydro renewable energy generation such as solar and wind.
11. Despite unbundling, sector companies have limited autonomy. All sector companies remain
integral parts of the Ministry of Water Resources, Irrigation, and Electricity (MoWRIE) and are largely
dependent on government budgetary allocations. Key functions such as finances, investment, and
personnel management are determined by the Ministry, not by the individual sector companies. The SEHC
receives an annual appropriation from the MoFEP for the entire electricity sector and allocates it to the
four SEHC subsidiaries based on the quantity of electricity supplied to the Sudanese Electricity
Transmission Company (SETCO) (for the SHGC and Sudanese Thermal Power Generation [STPG]) and the
power supplied by SETCO to the Sudanese Electricity Distribution Company (SEDC). This financial flow is
illustrated in Figure 1.1.
2
The unbundling led to the creation of Merowe Hydropower Company and the SHGC. The Merowe Hydropower
Company was merged into the SHGC in 2017.
13
Figure 1.1: Institutional Structure and Financial Flow of Sudan’s Electricity Sector
Note: CAPEX = Capital expenditure.
12. In addition, sector companies do not have access to finance for their own investment decisions.
The sector fully relies on the MoFEP to secure financing to invest in the power system. Capital investments
in the sector are financed directly by the MoFEP, which also services the debt, although the assets are
shown in the balance sheets of the respective sector companies. Given the GoS’s fiscal constraints, the
MoFEP engages external donors (largely Arab and Chinese) to fund investments. Such high dependence
on external financing creates unpredictability with regard to available financing and poses major
challenges to investment planning and execution.
13. The roles and responsibilities of sector entities are ambiguously defined. The function of each
sector entity is often defined only in its broad principles, leaving key decisions to ad hoc committees. In
particular, the responsibilities of planning and investment are disbursed between MoWRIE and the SEHC,
with significant overlaps. This approach enables flexibility in the decision-making process but also results
in important weaknesses: a dilution of responsibility and accountability, unpredictability of decisions, and
a decreased level of commitment in technical departments. For instance, the responsibility for electricity
access is spread between MoWRIE, SEDC, and state governments. The main sector functionalities are
expanded upon in Annex 5.
1.2: Sector Policies and Plans
14. The electricity sector is prominently featured in Sudan’s national development strategy. The
Sudan National Quarter-Century Strategy (2007–2031) presents the national development goals across
sectors. Goal 3 — sustainable development — features a number of goals related to the electricity sector,
including loss reduction, interconnection with East Nile Basin countries, energy efficiency, data
management, and capacity building. It should be noted, however, that the strategy was developed before
the secession of South Sudan in 2011, when the entire country context significantly changed. Nonetheless,
the strategy is being referred to as a national strategy to which the sector contributes.
14
15. The electricity sector operation is currently guided by the ‘2015–2020 Power Sector
Development Framework.’ The framework presents the list of priority investments for the electricity
sector. The list of projects includes the development of thermal generation to meet growing demand,
acceleration of the rehabilitation and strengthening of the distribution system, and addressing the fuel
storage issue for thermal plants. The sector framework is built on long- and medium-term power system
plans for 2012–2031 prepared by an international consulting firm in 2012. The plan was built on system
modelling for generation and electrical network expansion based on a least-cost approach. The plan
suggests that the least-cost option for Sudan will derive from coal-based thermal generation in the Red
Sea as the base load and supplemented by gas-powered generation to meet peak demand. The plan also
suggests various network reinforcements, including interconnection with Ethiopia and maintenance of
existing hydroelectric plants. Importantly, renewables such as solar and wind were not identified as part
of the least-cost options.
16. The focus of the framework is to identify key projects that require financing. The document
correctly identifies future sector challenges, particularly the projected widening financial gap between
sector resources and financing needs for operation, maintenance, and new investments. Although the
framework document presents a technically sound and detailed description of power sector challenges
and investment needs, it does not spell out the sector priorities and overarching strategy, as its focus is
mainly on physical investment proposals to the MoFEP.
17. Only a portion of the projects identified in the sector framework have actually been
implemented. Notably, there has been a significant difference between the framework document and
the investments that actually took place. Table 1.1 compares key generation investments referenced in
the sector framework and the system plan. It is evident that around half of the proposed generation
projects did not take place. Major delays of between one and three years were also observed, even for
the projects that were commissioned. This is partly due to the unpredictability of financing availability,
which is at the discretion of the MoFEP and must be raised from external partners. In addition, the system
plan overestimated demand growth. In 2017, a peak load of 4,534 MW was forecast, while the actual peak
load for the year was 2,972 MW; less investment in generation was thus required. Consequently, the
framework document and the underlying system plan have limited relevance to future planning.
Table 1.1: Large Power Generation Projects Included in Power System Plans and Their Actual Status of
Implementation
Installed Planned
Name of Project Technology Capacity Commission Current Status
(MW) Year
Upper Atbara Hydro 320 2015 Commissioned in 2018
Roseires Dam Hydro 280 2012 Completed in 2013
Heightening
Sennar Upgrading Hydro 26 2015 Not started
Red Sea 1 Thermal (coal fired) 300 2016 Not started
Red Sea 2 Thermal (coal fired) 300 2016 Not started
Al Fula 1 Thermal (crude oil fired) 135 2015 Not started
Al Fula 2 Thermal (crude oil fired) 135 2015 Not started
Al Fula 3 Thermal (crude oil fired) 135 2015 Not started
Kosti 1 Thermal (crude oil fired) 125 2012 Commissioned in 2015
Kosti 2 Thermal (crude oil fired) 125 2012 Commissioned in 2015
15
Installed Planned
Name of Project Technology Capacity Commission Current Status
(MW) Year
Kosti 3 Thermal (crude oil fired) 125 2013 Commissioned in 2015
Kosti 4 Thermal (crude oil fired) 125 2013 Commissioned in 2015
Roseries Upgrading Hydro 442 tbc Not started
Sennar new power Hydro 146 tbc Not started
plant
Source: STPG and SHGC.
18. The GoS has an ambitious plan to expediate electricity access. In line with the Sustainable Energy
for All (SE4ALL) initiative, the GoS has set the target of universal access to electricity by 2031, of which at
least 80 percent is expected to be through grid connections. According to the SEDC’s plan, the GoS will
connect about 250,000 households per year — a large increase from 2016 to 2018, when the sector added
100,000 households per year. Such scale-up will need significant investment; as the distribution network
extends beyond higher-density cities and settlements, the cost and time needed to connect new
customers is likely to increase. The GoS also plans to provide 2.5 million stand-alone solar home systems
(SHSs) by 2023 for areas where grid connection is not feasible.
19. The GoS is committed to attracting private sector investment to the electricity sector. Given the
constrained public financing and known renewable energy potential, the GoS has made considerable
efforts to attract private investment to the sector. Since 2001, the GoS has attempted to develop private
sector projects, including the 257 MW thermal project in Khartoum, which was awarded to DIT Power
Kilo-X, a Malaysian company. More recently, the GoS engaged developers for utility-scale solar in West
Omdurman, Port Sudan, and Berber, as well as for a wind project in Dongola. These developers were
engaged based on unsolicited proposals without a competitive process.
20. Despite the GoS efforts, no private sector project has been finalized to date. Many projects
progressed as far as the signing of a Memorandum of Agreement between the company and the GoS but
did not advance further. The developers often lacked the project development experience, as well as the
technical and financial capacity, needed to advance the project. The GoS often requested a low tariff,
which was insufficient for developers to secure adequate return to attract debt financers. The only
exceptions are semi-IPPs contracted to provide temporary rental thermal capacity under PPAs: SEMI FZE
of Turkey (16 MW at Nyala in 2017 and 30 MW at Great Darfur in 2018) and Karpowership of Turkey (150
MW at Port Sudan). All power plant rental contracts include a minimum load factor guaranteed by the
GoS, and the GoS supplies generating fuel for the power plants. These rental agreements are short term,
with a duration of six months to three years.
1.3: Sector Performance
21. Sudan’s electricity demand has been growing faster than the demand in many other countries
in Sub-Saharan Africa. Between 2013 and 2017, demand in Sudan increased by 70 percent — at an
average rate of 11.3 percent each year (Table 1.2). A demand growth of 10 percent annually is considered
high in Sub-Saharan Africa. Sudan’s steep rise in demand is largely the result of increasing per customer
electricity consumption and industrial demand rather than the addition of new customers. As of 2017,
there were 2.2 million residential customers, constituting about 60 percent of the total electricity sales.
Residential users in 2017 consumed an average of 275 kWh per month, high by Sub-Saharan African
standards, which show consumption typically ranging between 50 and 100 kWh per month. The
breakdown of usage by customer category can be seen in Annex 3.
16
Table 1.2: Electricity Demand Growth in Sudan (%)
2013 2014 2015 2016 2017 Average
13.1 12.8 9.0 11.5 10.1 11.3
Source: SEDC.
22. The electricity demand doubles in the summer season, resulting in significant power outages.
During peak hours in June and July, Sudan’s hottest months, as much as 40 percent of electricity demand
is subject to load shedding. This is because the use of air-conditioning represents the largest share of
household and commercial electricity consumption in Sudan. Load shedding is likely to be the biggest
concern for electricity users and is also driving them to overuse electricity when it is available (for example,
overcooling spaces and food). In 2018, 3,146 MW was recorded as the peak demand, which has been
increasing at the pace of 200–300 MW per year since 2015. Since recorded peak demand excludes unmet
demand during load shedding, the real demand was likely higher.
Figure 1.2: Daily Load Curve in May 2018
Weekday (May 21, 2018) Weekend (May 25, 2018)
3500
3000
2500
2000
MW
1500
1000
500
0
Hour of the day
Source: World Bank staff calculation
23. The demand growth has been driven by increases in both grid connectivity and levels of
consumption. The number of grid-connected customers and electricity consumption per customer both
increased at an average rate of 5 percent a year between 2016 and 2018. Rising per customer usage of
electricity is likely due to increased ownership and usage of electric appliances as well as increasing
urbanization (i.e., rural populations moving to cities and living with households that are connected to
electricity). Table 1.3 provides an overview of selected electric appliance ownership in Sudan. This is not
an exhaustive list, and households are likely to have additional appliances such as light fixtures, electric
cookers, and cellphones.
17
Table 1.3: Ownership of Key Electric Appliances in 2014 (grid-connected households)
Percentage of households that Average number of units
own the asset
TV 78.7 1.1
Radio 27.0 1.0
Computer 8.4 1.2
Refrigerator 59.8 1.1
Fan 73.9 2.7
Air conditioning 22.6 1.5
24. In an attempt to keep up with rising demand, the GoS invested in large-scale thermal and hydro
generation. With an installed capacity of 3,500 MW in 2018, and expected capacity of 4,500 MW in 2019,
Sudanese power generation capacity is one of the largest in Sub-Saharan Africa. Of the installed capacity,
48 percent is hydroelectric, and 52 percent is thermal (consisting of diesel, heavy fuel oil [HFO], crude oil,
and other forms of petroleum fuels). As of 2018, the Merowe Hydropower Plant is by far the largest
generation asset in Sudan, with 1,250 MW of installed capacity. The composition of generation capacity
is illustrated in Figure 1.3, and a full list of current and prospective generation assets is provided in Annex
1. Sudan is part of the Eastern Africa Power Pool (EAPP) and imported 319.6 GWh of power from Ethiopia
in 2017.
Figure 1.3: Sudan’s Electricity Generation
2018 Installed Generation Capacity 20,000
(MW) 18,000
16,000
Seitat&Upper Others 167
Atbara 350
14,000
12,000
GWh
Merowe
Roseires 10,000
280 1,250
8,000
6,000
Khartoum 4,000
North 380 2,000
0
2016 2017 2018
Garri 579 Kosti 500
Hydro Thermal Import
Source: Sudanese Electricity Holding Company
Note: Total Installed Capacity - 3,676 MW. Available Capacity - 3,400 MW.
25. Sudan is home to vast but largely untapped renewable energy resources. It is evident that
Sudan’s solar and wind energy potential is greater than that of most other Sub-Saharan African countries.3
Solar potential is high almost everywhere in Sudan. Wind energy potential, which is more location-specific
than solar, is high along the coast of the Red Sea and in the inland area of the Northern State. The GoS is
also exploring geothermal potential at the Bayuda site in the Northern State. However, these renewable
3
Solar and resource map in Sub-Saharan Africa can be viewed at Global Solar Atlas (https://globalsolaratlas.info/)
and Global Wind Atlas (https://globalwindatlas.info/).
18
resources are largely untapped. Hydropower is the only renewable resource that has been significantly
used for power generation: Sudan currently has 2,000 MW installed capacity of hydropower.
26. Recent investments in the sector prioritized thermal generation. The share of electricity
generated from thermal power plants has risen to about 46 percent and is expected to continue rising, as
most of the generation plants in the pipeline are thermal (see Annex 1). The GoS is expected to
commission additional 1 GW thermal generation units in Garri and Port Sudan plants in 2019. Sudan’s oil
production and refinery capacity (for example, Khartoum refinery) is small, and domestic production is
only capable of providing for household/commercial fuel use (for example, vehicle fuels and liquified
petroleum gas). Hence, most of the fuels used for electricity generation are imported. Crude oil is
imported from South Sudan and is directly tapped at Kosti power station. Sponge coke (SC) is a low-value
byproduct from Khartoum refinery operation. Other fuels, including HFO, heavy coked gas oil (HCGO), and
diesel are largely imported from the international market.
Table 1.4: 2017 Thermal Fuels for Power Generation in Sudan
Fuel Quantity (tons) Percentage
HFO 198,420 11.7
HCGO 158,663 9.3
Diesel 25,845 1.5
Light diesel oil (LDO) 448,861 26.4
SC 136,181 8.0
Crude oil 731,962 43.1
Total 1,699,932 100.0
Source: Sudanese Thermal Power Generation
27. GoS investment in maintaining generation assets has been adequate despite challenges. Most
of Sudan’s generation assets are of significant age but are in good working order. Roseires HPC (280 MW)
is 45 years old; original parts of Khartoum North thermal plants (380 MW) are 33 years old; and Garri 1–
2 thermal plants (456 MW) are 16 years old. The high availability rate of these generation assets indicates
that they have been maintained in sound working condition despite the challenge of procuring spare parts
while the country was under economic sanctions. The GoS has worked with countries with which it has
economic relationships — Arab countries, as well as China and Turkey — to procure the necessary spare
parts. An important exception is Garri 4 thermal plant (110 MW), which is not operating at full capacity
due to technical deficiency.
28. Sudan’s power system is relatively well maintained and performs at average or high levels
compared to other systems in the region. Transmission and distribution losses in Sudan are low at 20
percent (15 percent distribution losses and 5 percent transmission losses). This level of loss is comparable
to Kenya and Tanzania and lower than Ghana and Uganda (Figure 1.4). Bill collection rate is 93 percent,
due to the quality of commercial management and the universal installation of prepayment meters.
System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index
(SAIFI), which measure the duration and frequency of unplanned power interruptions, are 9.18 hours and
10.14 times per year, respectively. This puts the country in the first quartile in Africa for both indexes but
places it below the international average of 5.5 hours and 6.4 times per year, respectively. Sudan’s
performance compares well with other African countries, but there is room for improvement. It should
be noted that Sudan does suffer from regular load shedding in summer peak hours due to generation
shortage.
19
Table 1.5: Sudan’s Power System Scorecard (2017)
Indicators Sudan Regional Benchmarking
Transmission loss 5.4% Relatively low compared to Sub-Saharan African
average, with room for improvement.
Distribution loss 15.1% Average for Sub-Saharan Africa, with room for
improvement.
Collection rate 93% High by Sub-Saharan African standards (99.7% of
residential users are prepaid - 2017).
SAIDI 9.18 hours System duration of interruption per customer. Average
(2017) by Sub-Saharan African standards, with room for
improvement.
SAIFI 10.14 (2017) Average frequency of interruption per customer.
Average by Sub-Saharan African standards, with room
for improvement.
Cost of service US¢20/kWh Average by Sub-Saharan African standards.
(2017)
Average US¢1.5/kWh Lowest in Sub-Saharan African. Dropped to US¢0.7/kWh
electricity tariff (2017) in 2018 due to currency depreciation.
Figure 1.4: Power Transmission and Distribution Losses (%) in African Countries
Source: Regional Data based on Kojima and Trimble (2016)
29. The relatively sound performance of the system is underpinned by a local manufacturing base
that supplies the power sector. Over the years, local industries have developed in response to sanctions
imposed on the country. These industries manufacture and supply prepayment meters, small- to medium-
size transformers, and other equipment. Local industries also have a recognized level of competence in
civil works and construction of transmission lines and distribution systems. This local manufacturing base
and skilled labor have helped the sector to maintain its infrastructure despite having limited access to the
international market.
20
30. The level of staffing is also relatively efficient by regional standards. Sudan’s power sector staff
productivity, measured as the number of customers per employee, was 275:1 in 2017. This ratio is
comparable to that of power sectors in countries considered strong performers in Africa, whether under
private management (Côte d’Ivoire and Kenya [partly]) or public management (Rwanda), and confirms
that the technical operation of Sudan’s system is efficient by regional standards.
31. Sudan’s power system covers its major demand centers but does not reach the western part of
the country. Although the Sudanese power system is among the most technically and commercially
efficient in Sub-Saharan Africa, the transmission and distribution systems are in need of extension and
rehabilitation. The states around Khartoum are equipped with several transmission lines, but other states
have very limited or no coverage. The five states comprising Darfur, in the southwest of Sudan, have no
transmission line coverage, as the 220 kV line ends at Babanosa before reaching East Darfur. In the eastern
parts of the country, transmission lines are devised to connect state capitals and power generation plants.
In the north, transmission lines are built along the Nile River to cover riverside towns. There are also 500
kV lines that connect Merowe HPC, Khartoum, and Atbara. Sudan’s power system map is provided in
Annex 4.
32. Expansion of the transmission network to the west is under way but only slowly. Investment is
being made to extend the grid to the western parts of the country, with financing from several donors.
However, the inability of the MoFEP to fulfill its debt repayment obligations to the Arab Funds (e.g., Islamic
Development Bank, Arab Fund for Economic and Social Development, Qatar Fund for Development)
interrupted the implementation progress. In the states with no transmission coverage, diesel-fueled
isolated systems are serving the state capitals. Hence, all 18 state capitals are served either by the national
grid or by isolated grids. The GoS plans to interconnect these systems as transmission coverage is
increased.
33. Sudan’s power system connects to the regional market, but the volume of power trade is limited.
Sudan is an active member of EAPP and has 200 MW interconnections with Ethiopia at 220 kV and Eritrea
at 66 kV levels, both of which are operational. The PPA between Sudan and Ethiopia includes 100 MW of
firm capacity at US¢5 per kWh and provisions for monthly scheduled and annually scheduled electricity
trade from Ethiopia to Sudan with the volume and price to be mutually agreed for each transaction.
However, this interconnection and PPA have been used only at an average capacity of 40 MW, which is
less than a quarter of the capacity provided for in the PPA. This is due to the lack of coordinated system
operation between the two countries, which is needed to ensure stability in the system when increasing
import volume. Sudan also completed a 300 MW interconnection with Egypt in February 2019, but the
two countries are still negotiating the PPA; therefore, the price has not been agreed.
34. The distribution network is concentrated in several states of the country. As illustrated in the
geographic information system (GIS) network map in Figure 1.5, Sudan’s distribution network is
concentrated in (a) Khartoum State, (b) Jazeera State, and (c) along the Nile rivers (Blue Nile from Ethiopia,
White Nile from Uganda, and the Nile to Egypt). To a degree, this concentration represents the size of the
population in each state: Khartoum and Jazeera States are the two most populous in Sudan, with a
combined estimate of 11 million people and a number of settlements and agricultural fields along the Nile
rivers.
21
Figure 1.5: High-voltage and Medium-voltage Network in Sudan
Source: World Bank Staff Analysis
Note: HV = High voltage; MV = Medium voltage. The boundaries, colors, denominations, and any other information
shown on this map do not imply, on the part of the World Bank Group, a judgement on the legal status of any
territory, or any endorsement or acceptance of such boundaries.
35. Each state is responsible for investing in the distribution network. Sudan follows a decentralized
model of electrification, in which each state is financially responsible for the construction of the MV
network. In addition, the cost of providing low-voltage lines and last-mile connections is borne by
electricity users, with varying levels of connection fees depending on the location and the length of lines
to be built. Over the past several years, the average connection fee has been around SDG 4,500 with cost
fluctuations resulting from fluctuating exchange rates. In Sudan’s decentralized model of electrification,
the national government, including the SEDC, functions as the technical adviser on project design and the
operator of built assets.
36. The estimated rate of electricity access in Sudan in 2018 was 32 percent, with significant
regional disparity. Approximately 2.2 million households are connected either by national grid or isolated
systems, while about 4.5 million households remain without access to electricity. 4 In line with the
geographical locations of distribution grids, the highest electrification rates (60 percent and above) are in
Khartoum, Jazeera, River Nile, and Northern States. The largest electricity access deficit is observed in the
4
The national household baseline poverty survey in 2015 indicated that 46.6 percent of Sudanese households use
grid-connected electricity as the primary source of energy. However, due to methodological reasons, the survey may
be overestimating the electrification rate (for example, one connection may be serving multiple households). A
comprehensive survey based on multitier framework (MTF) of electricity access is needed to accurately estimate the
actual level of access.
22
Darfur and Kordofan regions, where the national grid has not reached despite the significant population
residing there.
Figure 1.6: Estimated Number of Unelectrified Households in Each State
1,400,000
1,200,000
Number of households
1,000,000
800,000
600,000
400,000
200,000
0
Connected households Unconnected Households
Source: SEDC, World Bank analysis
37. To expediate electrification, the GoS is investing in off-grid electrification solutions. The GoS,
through the SEDC, designed SHSs, and by mid-2018 had distributed 15,000 of them. The SHSs are
distributed using SEDC branches in state capitals where national grids have not reached. To enhance
affordability of the SHS, an installment payment option is offered in cooperation with a local government-
owned bank. There is also a United Nations Development Programme-Global Environment Facility (UNDP-
GEF) funded program to scale up solar water-pumping systems through a cost-sharing scheme. High-
quality (that is, certified by Lighting Global) SHSs from international suppliers are absent from the
Sudanese market, partly due to the challenges local businesses face in accessing foreign currencies.
23
Figure 1.7: SHS Model Developed by the GoS
Source: World Bank, courtesy of Sudanese Electricity Distribution Company
38. Most of the electrified households belong to the relatively richer segments of the Sudanese
population. In Sudan, 67 percent of electrified households fall within the fifth and fourth quintiles (42
percent and 24 percent, respectively), whereas only 5 percent of connected households are in the poorest
(first and second) quintiles. This disparity partly reflects the fact that most of the distribution network has
reached only urban populations in relatively well-off states such as Khartoum and Jazeera. Access remains
particularly low for rural households.
Figure 1.8: Distribution of Households Connected to the Grid (2014)
5%
11%
1 Poorest
42% 2
18% 3
4
5 Richest
24%
Source: NHHBPS 2014. 1 represents the poorest quintile and 5 represents the richest quintile.
39. The high consumption levels of Sudan’s grid-connected households are equivalent to levels in
some Organization for Economic Co-operation and Development (OECD) countries. 5 In 2014, the
average household consumption of electricity in Sudan was 308 kWh per month, with consumption
ranging from 177 kWh among the poorest quintile to 368 kWh among the top quintile. Urban users
consume significantly more than rural users; those in the richest quintile consume on average 439 kWh,
around 180 kWh more than the rural population in the richest quintile. The level of energy efficiency of
electrical appliances in Sudan, including air conditioners, is considered low, due to the history of restricted
access to the international market under economic sanctions. As Figure 1.9 illustrates, the average
5
Using 2014 tariff structure.
24
Sudanese household consumes as much electricity as a German household and five times that of a Kenyan
household. Cooling is likely to be the largest use of electricity in Sudan. It is estimated that approximately
40 percent of electricity consumption goes to space cooling or air conditioning in Sudan due to summer
temperatures that often exceed 40°C.
Figure 1.9: International Comparison of Sudan’s Residential Electricity Consumption
300
250
200
kWh/month
150
100
50
0
Source: World Energy Council, World Bank
40. The high level of consumption is partly driven by the very low tariff level. Sudan’s average
electricity tariff is the lowest in Sub-Saharan Africa and among the lowest in all of Africa (Figure 1.10). The
tariff was already one of the lowest in Sub-Saharan Africa in 2015, but subsequent depreciation of the
Sudanese pound reduced tariff significantly in real terms. The average retail tariff in Sudan in 2017 was
SDG 0.35 per kWh or US¢1.5 per kWh.6 The tariff charged to businesses and large consumers whose use
exceeds 400 kWh per month was increased by 88 percent in 2018, but the average tariff is still far below
the cost of supply and remains low by international standards. The average tariff nominally increased by
80 percent between 2015 and 2018, but after adjusting for domestic inflation, the real average tariff
decreased by 30 percent over the same period.
6
Ranging from US¢0.8 per kWh for the social tariff to US¢9 per kWh for large industries.
25
Figure 1.10: Comparison of Electricity Tariffs in Sub-Saharan Africa
0.60
0.50
0.40
US$/kWh
0.30
0.20
0.10
0.00
Central…
São Tomé…
Sudan
Burkina Faso
Burundi
Comoros
Guinea
Zambia
Gambia, The
Benin
Rwanda
Côte d'Ivoire
Ghana
Lesotho
Ethiopia
Cape Verde
Niger
Malawi
Liberia
Sierra Leone
Togo
Mauritania
Mauritius
Kenya
Seychelles
Senegal
Tanzania
Mozambique
Gabon
Uganda
Madagascar
South Africa
Mali
Swaziland
Zimbabwe
Congo, Rep.
Nigeria
Botswana
Cameroon
Source: Trimble et al. 2016
Figure 1.11: Nominal and Real Electricity Tariff in Sudan
0.50
0.40
SDG/KWh
0.30
0.20
0.10
-
2015 2016 2017 2018
Nominal tariff Real tariff (index to 2015)
Source: World Bank Calculation
41. The lifeline tariff in Sudan is very generous. The tariff structure includes a low lifeline tariff of
US¢0.7 per kWh with a high threshold of 200 kWh per month (in most countries with a lifeline tariff, the
threshold is 100 kWh per month). This relatively generous threshold of social tariff reflects higher per
customer consumption than is seen in other countries in Sub-Saharan Africa, as well as the GoS’s aim of
ensuring that electricity is affordable. As seen in Table 1.6, almost half of the residential users fall within
the lifeline tariff category. The data also suggest that the highest-consuming 1 percent of users account
for more than a quarter of electricity consumption. A full tariff table is presented in Annex 2.
26
Table 1.6: Percentage of Households and kWh Consumed by Tranche
% of Households % of kWh Consumed
Residential (0–200 kWh) 46 21
Residential (201–400 kWh) 46 39
Residential (401–600 kWh) 5 8
Residential (601–800 kWh) 1 3
Residential (801–1,500 kWh) 1 3
Residential (1,501+ kWh) 1 26
Source: National Household Budget and Poverty Survey (NHHBPS) 2014
42. At the current low tariff, electricity is considered affordable, even for the poorest population in
Sudan. Based on the National Household Baseline Survey in 2015, average electricity consumers spend 1
percent of their monthly budget on electricity. In some of the most urbanized and electrified states, the
share increases to 3 percent (Figure 1.12). According to the framework developed by the SE4ALL initiative,
which defines subsistence level as 30 kWh per month, electricity is considered affordable if a household
does not have to spend more than 5 percent of its total monthly income to purchase it (World Bank and
International Energy Agency 2015). Accordingly, electricity is affordable to all connected households in
Sudan, as they pay a low tariff of SDG 0.15 for the first 200 kWh.
Figure 1.12: Expenditure for Electricity Consumption as Share of Household Expenditure
Rural Urban
2.6%
2.3%
1.6%
1.2%
1.1%
0.9%
0.9%
0.6%
0.4%
0.1%
1 POOREST 2 3 4 5 RICHEST
Source: National Household Budget and Poverty Survey (NHHBPS) 2014. The percentage covers only households
connected to the grid.
1.4: Sector Challenges
43. The electricity access rate is growing very slowly, and increasing grid connections incurs
financial loss to the sector. In the past five years, the GoS has been connecting approximately 100,000
new households annually to the grid, providing electricity services to an estimated 560,000 people every
year. However, the additional connections are largely offset by rapid population growth. Population in
Sudan has been growing by about 2.4 percent a year, which translates into an annual increase of close to
1 million people. Consequently, the access rate lags behind population growth, and the number of
households without electricity access is likely to be increasing. From a financial perspective, connecting
more customers to the grid is loss-making. Although the sector and SEDC do not pay to connect
households (which are covered by state governments and customers’ own contributions), tariff
27
underpricing below the level of cash required to cover operational expenditure (OPEX) means that every
kWh sold represents a net financial loss.
44. The sector policy and planning framework is weak. The current sector framework document and
system plan are obsolete, meaning that sector investment is not guided by least-cost options such as
renewables. Hence, the GoS‘s current and future investment plan is predominantly thermal. There is also
underutilization of existing assets, most notably the interconnection with Ethiopia. The weak policy and
planning framework is hindering the country’s progress toward key energy goals. In the international
analysis of Regulatory Indicators for Sustainable Energy (RISE) conducted in 2017 by the World Bank and
the Energy Sector Management Assistance Program (ESMAP), Sudan scored 32 out of 100, slightly below
the Sub-Saharan African average of 35. Sudan fared relatively well with regard to electricity access, owing
to its target for universal access by 2031 and its program to scale stand-alone systems and affordable
electricity. In contrast, Sudan’s scores on energy efficiency and renewable energy were low, largely due
to the lack of incentives and financial mechanisms to support these policies.
Table 1.7: RISE Score of Sudan
Overall Electricity Access Energy Efficiency Renewable Energy
Sudan 32 53 24 19
Sub-Saharan African Average 35 — — —
Source: ESMAP (2017) RISE
Note: Full score is 100.
45. The sector has not yet created a sufficiently enabling environment for private sector investment.
The low cost-recovery rate and reliance on government subsidies reduce the private sector’s appetite for
investment. Private sector investors require a financially strong off-taker with adequate revenues from
electricity sales to support monthly payments under PPAs. Many countries that have a sound power sector
but lack a credit record receive the support of international financial institutions (IFIs) to provide
guarantees on behalf of utilities and/or governments. Such credit enhancement tools build private sector
confidence. In the case of Sudan, however, the GoS is in arrears with IFIs. Until these arrears are addressed,
guarantees and credit enhancement instruments will be difficult to secure. Furthermore, there is a
weakness in the GoS’s capacity to effectively procure IPPs. In the past, the GoS opted to accept unsolicited
proposals without launching competitive tenders based on a least-cost plan (LCP). The private sector also
has to go through complex procedures for PPPs, involving a sometimes unpredictable decision-making
process undertaken by various committees and councils. The long processing time and the uncertainties
concerning the outcome represent risks for potential investors.
46. Macroeconomic factors also create barriers for private investment. These factors, such as
domestic inflation and the fluctuating exchange rate, present significant risks to private investors. Private
investors in the power sector usually require most transactions and PPA tariffs to be denominated in hard
currencies such as U.S. dollars or euros. Given that the sector’s revenue from electricity sales is in
Sudanese pounds, the sector’s ability to make timely payments to IPPs will be compromised by domestic
inflation and the corresponding depreciation of the currency. The private sector will consider this a
significant payment risk that could result in default. Such risk can typically be mitigated by government
guarantees, usually issued by the Ministry of Finance, to backstop the payment to IPPs. However, the
value of these guarantees is based on a government’s track record of honoring such guarantees. In the
case of the Sudanese government, whose borrowings are mostly in arrears, the track record is poor. To
attract more private sector investment and lending, the credit standing of the GoS would need to be
restored and the issue of international payment arrears settled.
28
47. Restricted access to foreign currency is limiting private sector growth. IPPs need access to
foreign currency for financing and operations in Sudan, as well as parts and maintenance services, and
these must be procured quickly to avoid lengthy shutdowns of plants. Off-grid companies, which invest in
and/or operate mini-grids as well as stand-alone SHSs, also need access to foreign currency to import the
products and materials necessary for their operations. Such access to foreign currency is a challenge in
Sudan, partly due to international banks’ overcompliance with international sanctions. Although U.S.
sanctions were lifted in 2017, investors and lenders remain cautious about engaging with Sudan due to
the reputational risk associated with transacting business with a country still on the U.S. list of states
sponsoring terrorism. There is also a perceived risk of sanctions being reimposed during the PPA period,
which typically lasts 20 years.
29
PART 2: FINANCIAL OUTLOOK
48. In the coming years, the sector will face increasing challenges. Using sector financial models and
a least-cost planning tool, a projection has been made to illustrate how the sector will look in the medium
term, by 2023. Key factors that affect the sector’s future performance include domestic inflation, growing
demand, generation mix, and the level of tariff. The combination of these factors is driving the sector
toward a worsening financial performance.
2.1: Sector Cost and Revenue
49. The sector’s full cost of service was estimated at SDG 43.5 billion (US$2.4 billion) in 2017 or
US¢18 per kWh. This level of cost of service is approximately average in Sub-Saharan Africa. The full cost
of service includes the following:
(a) The cash OPEX of the sector was SDG 19.1 billion (US$1.3 billion) in 2017. This figure
represents the minimum expenditure that the sector needs to cover (for example, fuel, basic
operation and maintenance [O&M], and staffing). The cash OPEX recorded in financial
statements by sector companies totaled SDG 8.5 billion. However, the financial statements
use the official exchange rate, which is subsidized by the Central Bank of Sudan (CBoS) and
undervalues the cost of fuel import. Using the parallel market exchange rate for fuel cost,
estimated cash OPEX in 2017 was SDG 19.1 billion.
(b) CAPEX annuity was SDG 24.5 billion (US$1.1 billion) in 2017. This is a theoretical figure that
the sector would need to recover if it were to raise debt to finance its existing assets through
repayment of principles and interest. In reality, however, the MoFEP raises finance (debt
and grant) or secures budgetary resources and on-grants them to the sector companies.
Given that some CAPEX is funded by grants and budgetary allocation that do not require
repayment, the real CAPEX annuity is likely to be lower. It is assumed that the CAPEX annuity
is incurred in U.S. dollars and the parallel exchange rate is being used to estimate the figure
in Sudanese pounds.
50. The sector generated cash revenue of SDG 4.3 billion (US$194 million) in 2017, far below the
minimum OPEX. Owing to the almost universal use of prepayment meters by residential customers,
collection loss has been low at 5-6 percent. Revenue has been increasing at 20-30 percent a year, owing
to increased sales and consumption of electricity. However, the amount of revenue falls far below sector
costs by all measures. The cost recovery ratio, with multiple levels of cost, is presented in Table 2.1. In
most of the countries in Sub-Saharan Africa, the electricity sector does not recover full cost due to the
large scale of new investments needed and the limited ability of users to pay higher tariffs. Nonetheless,
the full cost is a useful indication of the level of revenue that the sector needs to generate in the long run
to be sustainable.
Table 2.1: Sector Cost and Revenue (2017)
Unit: SDG, billions Cost Revenue Cost Recovery Rate (%)
Cash OPEX (official rate) 8.5 4.3 50
Cash OPEX (parallel rate) 18.9 23
Theoretical full cost (cash OPEX and CAPEX annuity, 43.5 10
parallel rate)7
7
Full cost includes (a) cash OPEX: costs required to pay for operating cash expenses, basically including OPEX minus
depreciation (which is the main noncash item), and (b) CAPEX annuity: the annuity of the utilities’ asset base value
at New Replacement Value, representing the recovery of the principal of the investment plus interest. A discount
30
51. The revenue gap is significant and is widening quickly. The gap between sector revenue and the
cost of cash OPEX under the parallel rate8 increased at an average rate of 40 percent a year between 2015
and 2017. The gap is driven by the increasing cost of fuel, which accounts for 85 percent of the sector
OPEX. Since the GoS imports fuels used for thermal generation, it is exposed to domestic currency
fluctuation. In 2017, the sector’s revenue gap was SDG 14.7 billion (US$667 million).
52. Sudan’s electricity sector operation cost has been increasing exponentially due to a
combination of factors, notably currency depreciation. The largest factor in increasing cost is the
depreciation of the Sudanese pound, which lost about 50 percent of its value per year over the past few
years. Sudan’s domestic refinery industry has been unable to meet the demand by the electricity sector,
so the sector depends heavily on imported thermal fuels. Consequently, Sudanese pound currency
depreciation immediately translates into increased sector operational cost. Such increase in operational
cost is noticeable when accounted in parallel exchange rate but is less noticeable when the accounting
practice uses the official exchange rate, which is tightly controlled by the GoS. Hence, policy makers in the
GoS may have been unaware of the magnitude of the real cost increase the sector is going through.
53. The rising cost is exacerbated by the increased use of thermal fuels and plants to meet the
growing demand. As noted earlier, Sudan’s electricity demand has been increasing at a rate higher than
11 percent a year. Such rapid demand growth is driven by a combination of increasing numbers of
customers and the widespread use of high-load appliances such as air conditioners and generators. The
low level of tariff also encourages inefficient use of electricity, resulting in a consumption level equivalent
to some OECD countries. Consequently, the electricity demand outstrips available generation in peak
summer hours, when the load doubles. The sector has had to implement a significant load-shedding
program, which affects livelihoods and economic activity in Sudan. It is likely that such load shedding has
negatively affected people’s confidence in the sector and their willingness to accept a higher tariff.
Furthermore, adding new generation to meet the peak demand is a costly investment. For example, the
GoS is currently constructing 1 GW of thermal plants, which will require an approximate investment of
US$1 billion. Given the current fuel shortages in Sudan, there is a risk that fuel supply to the thermal plants
will be interrupted even if they start their operation.
54. Sudan’s electricity tariff adjustment has been insufficient to keep up with rising costs and
inflation. The GoS modified the tariff structure in 2016 by charging higher rates to customers consuming
more than 200 kWh per year. In 2018, the GoS increased by 88 percent the tariff for customers consuming
more than 400 kWh per month. However, these efforts were insufficient to keep up with domestic
inflation, which was around 20 percent per year between 2015 and 2017. Therefore, in real terms, Sudan’s
electricity tariff has decreased over the years. This real decrease in tariff is evident when the average tariff
is expressed in U.S. dollars using the parallel rate. In 2015, the tariff was US¢2.1 per kWh, but in 2017, it
was US¢1.6 per kWh.
55. To fill in the revenue gap, the sector is heavily subsidized. The sector revenue gap for cash OPEX
(parallel rate) was SDG 14.7 billion (US$667 million). The shortfall was made up by a direct subsidy of the
rate of 12 percent was applied to the market value of assets. This is a simplified theoretical calculation to represent
what the tariff would be if all investments were to be made by the utility.
8
OPEX under parallel rate is considered an appropriate benchmark because (a) in most Sub-Saharan African
countries, it is unrealistic to recover CAPEX cost through sector revenues due to large investment needs and people’s
limited ability to pay, and (b) the GoS has recently modified official exchange to a rate much closer to a parallel rate.
31
MoFEP budget allocation of SDG 4.2 billion (US$191 million) and the CBoS, which covered SDG 10.5 billion
(US$475 million) through the provision of the implicit exchange rate subsidy. The exchange rate subsidy
was significant in 2017 because the official rate was about a third of the parallel price. In the same year,
the combined subsidy amounted to 13.5 percent of GoS expenditure and 1.8 percent of GDP. The scale of
subsidy is so significant that it is impeding sound macroeconomic management. It should be noted that
this is cash OPEX only and does not include capital investments. Inclusion of CAPEX would at least double
the revenue gap and the subsidy.
Figure 2.1: Historical Revenue Gap and Subsidy
20.00
SDG, Billions
18.00
16.00 Subsidy through
Central Bank
14.00
12.00
10.00
8.00
Subsidy through
6.00 MoFEP budget
4.00
Sector’s own
2.00
revenue
-
2015 2016 2017
Revenue SDG million Direct Subsidy Exchange Rate Subsidy
Source: World Bank staff calculation
56. The subsidy only minimally benefits the poor, who largely lack access to electricity. Given that
only 32 percent of the Sudanese population is connected to the electricity grid and most of those
households are in the rich income quintiles, the distribution of electricity subsidy is highly regressive. A
simple extrapolation shows that more than 60 percent of the subsidy benefits the richest 40 percent —
that is, the two richest quintiles. By contrast, 5 percent of the subsidy goes to the poorest quintile. Across
states, most of the subsidy goes to urbanized areas, such as in the State of Khartoum. The contrast is also
visible between rural and urban areas, with the subsidy benefiting urban more than rural populations.
32
Figure 2.2: Distribution of Electricity Subsidy by Region and Quintile
By state, urban, and rural By quintile
60% 45%
50% 40%
40%
35%
40%
30%
30%
25%
20%
20%
20%
10% 18%
15%
0% 10%
River Nile
Al-Gadarif
Rural
Blue Nile
White Nile
Khartoum
Central Darfur
West Darfur
South Darfur
South Kordufan
Kassala
Northern
East Darfur
Red Sea
West Kordufan
Sinnar
Al-Gezira
North Kordufan
North Darfur
10%
Urban
5%
4%
0%
1 2 3 4 5
Poorest Richest
Source: NHHBPS 2014
2.2: Medium-term Financial Outlook
57. The electricity demand is projected to grow rapidly, at a rate of 10 percent annually. Driven by
greater user consumption and an increased number of connections (residential and non-residential),
electricity demand is likely to grow by around 10 percent per year. Although this pace is fast by Sub-
Saharan African standards, it is a conservative estimate in the Sudanese context. Between 2015-2017, the
annual demand grew at a compound annual growth rate (CAGR) of 10.79 percent. The GoS projects 17
percent annual demand growth in the future, but given the supply constraints, the historical track record
of 10 percent is more likely. At this pace, demand would double within seven to eight years. By 2023,
demand is projected to grow to 28,000 GWh a year, with a peak demand of 5,200 MW.
58. To meet the demand, the government is planning significant investment in thermal generation.
According to a five-year generation plan (2018–2023), the GoS intends to invest in a range of thermal
generation of 3,500 MW by 2023. This mix is to include HFO, flare gas, and coal, as well as the addition of
combined cycle units to existing plants to use flue gas. The GoS also plans to invest in solar and wind
energy, as well as in additional interconnection with Egypt and Ethiopia, but the scale and capacity of
these options are significantly lower than those of thermal (500 MW for solar and wind, 300 MW
interconnection with Egypt, and 600 MW interconnection with Ethiopia). The list of pipeline generation
plants is provided in Annex 1.
59. With this plan, the sector cost will increase to approximately US$2.7 billion a year. This figure
includes an annual average capital investment (primarily thermal generation plants) and fuel procurement.
Since new generation plants are normally constructed by international firms and thermal fuels are
imported from the international market, the cost will be primarily incurred in U.S. dollars. By 2023, in U.S.
dollar terms, the sector’s full cost will increase by approximately 50 percent.
33
Table 2.2: Five-year Projection of Sector Cost
2019 2020 2021 2022 2023 2018–2023
Cash operating US$, millions 1,012 1,356 1,031 1,085 1,357 34%
costs
Full cost US$, millions 1,827 2,241 2,127 2,325 2,727 49%
Cash operating SDG, millions 70,202 145,308 171,686 283,136 558,095 695%
costs
Full cost SDG, millions 126,797 240,097 354,202 606,380 1,121,372 784%
60. With the current macroeconomic outlook, the sector cost in Sudanese pounds will grow
exponentially, driven by domestic inflation and Sudanese pound depreciation. For 2018–2023, the
International Monetary Fund (IMF) projects an average annual inflation rate of 58.3 percent. This will
directly translate into the depreciation of the Sudanese pound, which would be valued at US$1 = SDG 411
by 2023. This depreciation will have a major impact on sector costs, which are incurred primarily in U.S.
dollars. In Sudanese pound terms, the full cost of the sector will rise to SDG 1.1 trillion by 2023, an increase
of 780 percent from 2019. A scenario analysis that compares continued macroeconomic crisis (IMF
projection of 58 percent annual inflation) and macroeconomic stabilization (annual inflation of 10 percent,
which is close to the Sub-Saharan African average) shows that the macroeconomic factors will increase
the sector cost by five times. Domestic inflation and Sudanese pound depreciation are external factors
that are outside the direct control of the sector. With the current level of tariff, the sector’s cost recovery
will drop to a negligible 1.7 percent of cash OPEX and 0.85 percent of full cost by 2023. This would mean
that virtually all sector costs would need to be covered by subsidies.
Figure 2.3: Impact of Inflation on Future Sector Cost
1,200,000
1,000,000
SDG, millions
800,000
600,000
400,000
200,000
-
2019 2020 2021 2022 2023
Full cost - base case (58% inflation) Full cost - 10% inflation
Source: World Bank Staff Calculation
61. A range of cost-reduction measures exists. These include improving supply-side efficiency,
scaling solar/wind renewables, and importing from Ethiopia and Egypt. These measures could reduce the
sector operational cash deficit by 45 percent by 2028 as compared to the base case scenario. Details of
these measures are elaborated in Part 3.
34
Figure 2.4: Cost-reduction Measures to Reduce Sector Deficit
Source: World Bank calculation
Note: BAU = Business as Usual
62. The remaining revenue gap needs to be covered by increased tariff revenue. Approximately 15
percent annual increase of tariff in real terms would be needed by 2028 to cover the remaining gap.
However, this is an increase needed in addition to inflation; the increase needed in nominal terms would
be 70-75 percent per year. This pace of tariff increase is unlikely to be feasible, meaning that
macroeconomic stabilization is a prerequisite if the sector is to recover full operational cost through tariff.
35
PART 3: OPTIONS FOR SECTOR RECOVERY
63. Reaching operational cost recovery and containing the otherwise fiscally unsustainable cost of
subsidies are the most important priorities for Sudan’s electricity sector and are critical for economic
stabilization. The electricity sector subsidy accounted for 15 percent of GoS expenditure and over 2
percent of GDP in 2017. Under a business-as-usual scenario, the sector operating losses (deficits) will
continue growing and the annual subsidy requirement is estimated to reach US$1.3 billion by 2023.
Figure 3.1: Projected Sector Revenue Gap to 2023
600.00
500.00
400.00
SDG, billions
300.00
200.00
100.00
-
2019 2020 2021 2022 2023
Revenue SDG million Revenue Gap
Source: World Bank Staff Calculation
64. A range of measures would be necessary to increase sector revenues while carefully managing
and reducing sector costs to reach operational cost recovery. On the cost side, the key measures include
conducting electrification and system expansion on the basis of a least-cost development plan, increasing
the share of solar photo voltaic (PV) and wind power plants, improving energy efficiency, and increasing
cross-border electricity exchanges with Ethiopia and Egypt. On the revenue side, measures would include
adjustment of end-user tariffs and revision of tariff structure. In addition, the reform effort should be
accompanied by rigorous and well-designed public communication, institutional improvements to
delineate roles and responsibilities among sector oversight institutions, and the commercialization of
sector companies. The sections below discuss these measures in detail while Table 3.1 presents a potential
action plan of reforms.
Table 3.1: Potential Short-term Actions for Sector Recovery (1–2 Years)
Actions Responsible Entities
Optimizing cross-border trade
(These low-cost measures can save up to US$200 million a year.) SEHC and SETCO
• Complete technical studies and implement remedial measures to
increase power trade in cooperation with EAPP and the governments
of Ethiopia/Egypt.
• Agree on new/revised PPA as needed.
• Make supplementary investment to enable enhanced power trade.
Tariff adjustment/energy efficiency
MoWRIE, including ERA
36
Actions Responsible Entities
(These measures will reduce electricity consumption growth and create an
enabling environment for tariff reform.)
• Set interim target for tariff adjustment.
• Raise the GoS’s internal awareness of electricity subsidy.
• Prepare and launch communications campaign for tariff reform.
• Reduce lifeline tariff threshold to 100 kWh/month and promote
energy efficiency.
• Introduce peak/off-peak pricing once technically feasible.
Least-cost planning/private sector engagement MoWRIE
(These measures will allow optimal allocation of budgetary resources and
strengthen GoS capacity to engage the private sector.)
• Carry out least-cost generation and electrification planning.
• Redirect planned capital investment to renewables while piloting
renewable energy IPPs.
• Engage the private sector in the off-grid electrification space.
3.1: Measures to Manage Costs
Strengthening Least-cost Planning
65. Sudan’s population is expected to grow significantly, which poses challenges for electrification.
The population is growing at a pace of 2.4 percent a year. By 2031, it is expected to increase to 56 million
from its current level of 40 million. This change represents an additional 1 million people each year.
Achieving universal access will require that electricity access grows at a rate faster than population growth.
66. With the current plan, the GoS is unlikely to achieve its universal access target. The GoS plans
to increase grid-connected households to 5.3 million by 2023. Although this will more than double the
number of households connected to the grid as of 2018, it will only achieve an electrification rate of 56
percent (Figure 3.2). To achieve universal access, the GoS needs to connect 600,000 new households per
year — six times the current rate of connection, which is a very ambitious target.9
9
This is based on the population forecast by the United Nations Department of Economic and Social Affairs (UNDESA)
that Sudan will have approximately 56 million people in 2031, with the assumption that the household size of 5.4
per household remains the same.
37
Figure 3.2: Historical and Projected Electricity Access in Sudan
10
Millions HH
9
8
7
6
5
4
3
2
1
-
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Households with access (historical continuation) HH
Households with access (SEDC plan)
Total households
Source: Figure based on United Nations projection of population in Sudan, 2015 household survey, and SEDC
customer data.
Note: The projection can vary depending on geographical distribution of population growth and household size.
67. A multipronged approach with both grid and off-grid electrification would be required to
accelerate electrification efforts. If the current pace of new grid connections and population growth
continues, roughly 60 percent of the Sudanese population (6 million households) would need to be served
by off-grid electricity. The GoS plans to distribute 2.5 million SHSs by 2031, but this will not meet the
demand of 6 million households. To scale up the SHS market in Sudan, the GoS needs to effectively work
with the private sector. The GoS currently contracts out the assembling of its own SHS model by using
private contractors, but importing internationally distributed, Lighting Global certified products may be a
more cost-effective solution to take advantage of economies of scale. The GoS can incentivize the local
private sector to distribute SHSs. Mini-grids may also provide cost-effective solutions for relatively densely
populated settlements in Sudan. However, the experience of other countries in Sub-Saharan Africa
indicates that the development of mini-grids requires substantial public funding to reduce the investment
cost and make them commercially viable. Therefore, careful economic screening needs to take place
before committing resources to mini-grid development. The preliminary geospatial analysis in Figure 3.3
suggests that significant grid densification opportunities exist in Khartoum and Jazeera States, and high-
density settlements potentially suitable for mini-grids (marked with red dots) exist in the Kordofan and
Darfur regions.
68. The GoS can use planning tools to carry out electrification in a least-cost manner. Specifically,
the GoS could use its existing high-level GIS capability and its extensive data on prospective customers in
each state to carry out geospatial planning and identify the optimal balance between grid, mini-grid, and
stand-alone off-grid electrification solutions. This approach will enable the GoS to design cost-effective
interventions, which are essential in the present sector context. The GoS can also strengthen its tracking
and monitoring for electricity access in Sudan. One way to do this is to integrate an MTF for energy access
in its national census. The MTF classifies energy access from Tier 0 to Tier 4 instead of using the
dichotomous on-grid and non-grid classification. The inclusion of MTF in the census would allow the GoS
to effectively track its progress toward universal access to energy, as stipulated in SE4ALL.
38
Figure 3.3: Geospatial Map of Sudanese Grid and Population Settlements
Source: World Bank, based on data provided by Sudanese Electricity Distribution Company
Note: The boundaries, colors, denominations and any other information shown on this map do not imply, on the
part of the World Bank Group, a judgement on the legal status of any territory, or any endorsement or acceptance
of such boundaries.
69. On the basis of the overall electrification plan, the GoS would need to update the least-cost
development plan for the grid expansion. Sudan’s most recent least-cost development plan dates to 2012
and needs to be updated. The update would need to consider sector developments and actual investment
decisions made since 2012 and the financial resources that are realistically available to Sudan. Grid
expansion consistent with the LCP is important to ensure that investments are cost-effective and sector
costs are therefore not expanding in an uncontrollable manner.
70. A preliminary least-cost generation plan suggests that approximately US$700 million can be
saved between 2019 and 2023 by aligning the investment to least-cost option. The least-cost modeling
has found that solar and wind generation have sizable potential and could account for 1,610 MW — 20
percent of installed capacity, or 10 percent of annually generated energy. Power imports from Ethiopia
and Egypt are to be maximized for lowering the cost of electricity supply. The use of liquid fuels, such as
HFO and diesel, will be reduced substantially over time. The cost saving is a combination of avoided fuel
use and deferred capital investments to meet the demand. More detail of the least-cost analysis is
provided in Annex 6.
39
Table 3.2: 2023 Installed Capacity with Least-cost Option
Capacity (MW) Generation (GWh)
Least-cost Least-cost
GoS Plan Difference GoS Plan Difference
Plan Plan
Thermal
Coal 600 600 0 4,468 4,730 −262
Coke 110 110 0 819 819 0
Diesel 99 99 0 0 0 0
HFO 2,438 3,668 −1,230 4,725 6,023 −1,298
Light fuel oil (LFO) 580 1,030 −450 938 401 537
Renewable
Hydro 1,974 1,974 0 11,412 11,412 0
Solar 810 660 150 1,539 1,254 285
Wind 800 240 560 1,265 380 885
Import
Ethiopia/Egypt 500 390 110 2,799 2,946 −147
Total
7,911 8,771 −860 27,965 27,965 0
71. It is important that planning be institutionalized and implemented. An integrated least-cost
electrification and expansion plan, reflecting the increase of access as well as traditional generation
expansion planning, would need to be developed. This will require consultation with MoWRIE’s water
department (to optimize the use of water), the Ministry of Petroleum and Gas (to optimize the use of
fuels), and the MoFEP (to optimize financial resources and engage private sector investment). The
expansion plan would need to be regularly reviewed and updated based on changes in the prices of
technologies and fuel, as well as other external factors. It is therefore important that MoWRIE develops
in-house capacity for regular updating of the plan. This will require MoWRIE staff with economic/financial
analysis expertise, as well as specialized software. It is also critical that any new investments implemented
are consistent with the least-cost expansion plan.
Optimizing Cross-border Trade
72. Sudan has cross-border trade opportunities with Ethiopia and Egypt. Specifically, there are three
existing and planned interconnections between the three countries: (a) Sudan-Ethiopia interconnection
with 200 MW capacity in operational condition; (b) Sudan-Ethiopia planned interconnection with 1,000
MW capacity, which does not have confirmed financing; and (c) Sudan-Egypt interconnection with 300
MW capacity, which is under construction and expected to start commercial operation in 2019.
73. Increased use of these interconnections can help Sudan save US$200 million annually in the
short term. The interconnection with Ethiopia operates under a PPA allowing for a firm capacity import
of 100 MW at the price of US¢5 per kWh. This is a very attractive price given that the marginal fuel cost
of domestic thermal generation is US¢15 per kWh. Reportedly, the commercial utilization of the
interconnection was on average less than 40 percent of the firm PPA quantity in 2017 due to the lack of
dynamic interconnection study, which is required to ensure system stability as import volumes increase.
The interconnection with Egypt is close to being completed. However, as of February 2019, the two
countries were still negotiating the PPA. As long as the price that the countries agree under the PPA is
below the marginal cost of Sudan’s domestic electricity generation, power trade with Egypt will generate
net economic and financial savings for Sudan. If both interconnections are used at 75 percent of their
respective capacities, Sudan is estimated to realize annual savings of US$118 million from the increased
40
power imports from Ethiopia and US$79 million from the imports from Egypt, assuming PPA price of
US¢10 per kWh10.
Table 3.3: Impact of Imports on Cost of Supply
Capacity Fuel Savings (US$, Import Cost (US$, Net Saving (US$,
MWh
(MW) millions) millions) millions)
Ethiopia 200 1,314,000 183.96 65.7 118.26
Egypt 300 1,971,000 275.94 197.1 78.84
Total 459.90 262.8 197.10
74. The GoS needs to undertake measures to increase the use of interconnections and realize the
associated cost savings. Specifically, the National Dispatch Center would need to carry out a system
dynamic study for the Sudan-Ethiopia interconnection to establish the preconditions for maintaining
system stability with increased import. Based on this study, the GoS may need to make small investments
in Sudanese infrastructure to address congestion and other constraints that may hinder the full utilization
of the Ethiopia interconnection. The GoS could also negotiate a PPA for medium- to long-term import
contracts with Ethiopia and Egypt, potentially with firm take-or-pay thresholds and step-up or step-down
options. To do so, Sudan could actively participate in and contribute to the promotion of regional
electricity cooperation within the framework of the EAPP.
Increasing Renewable Energy utilization
75. Sudan has sizable and largely untapped renewable energy potential. The country is endowed
with significant hydro, solar, and wind resources, as well as the potential for geothermal. Other than using
some of its hydro potential (2,000 MW), Sudan has realized a very limited share of its renewable energy
potential; attempts to engage renewable IPPs in the past did not materialize due to complex procedures
and the lack of market understanding.
76. Sudan’s electricity system can accommodate a significant amount of intermittent renewable
energy capacity in the short term. The use of solar and wind power generation is unlikely to destabilize
the system in the short term. The exact grid integration capacity depends on the available capacity for
storing energy, which in Sudan is ensured through hydro power plants that have a reservoir; an integration
of 1,600 MW solar and wind by 2023, as suggested by the LCP, is considered to be feasible. The capacity
of the Sudanese power system to absorb intermittent energy on a large scale in the medium term will
require careful examination in the context of least-cost planning and its implementation.
77. The cost of solar and wind power generation is estimated to be roughly half that of thermal
generation and could result in savings of almost US$100 million annually. Based on international
experience, the full cost of renewable energy is presently in the range of US¢8 per kWh for solar PV IPPs
of medium size and less than US¢7 per kWh for wind IPPs with good quality wind, which is the case in
several locations in Sudan where wind velocity is above 7 m/s. When these technologies are financed by
the public sector through concessional financing, the cost is usually less than US¢6 per kWh for solar PV
and US¢5 per kWh for wind power; however, they require more government fiscal resources. These
generation costs compare very favorably with Sudan’s marginal generation costs of US¢14 per kWh for
thermal generation based on imported HFO and diesel. The reduction in generation cost, assuming Sudan
develops 400 MW of solar PV and 150 MW wind power potential within the coming two years, would be
US$97 million per year after Year 2, according to Table 3.4.
10
This is a hypothetical figure – the actual price has not been agreed yet.
41
Table 3.4: Cost Savings from Accelerated Development of Solar PV and Wind Generation Capacity
Full cost Full cost of Net savings
Full cost renewable Full cost of production Net savings public
Load renewable Public sector production Public sector Fuel saving PPP sector
Capacity factor Generation PPP financing PPP (million financing (million (million (million
(MW) (%) (MWh) (USD/kWh) (USD/kWh) USD) (million USD) USD) USD) USD)
Solar PV 400 20% 700,800 0.08 0.06 56,064 42,048 98,112 42,048 56,064
Wind 150 35% 459,900 0.07 0.05 32,193 22,995 64,386 32,193 41,391
Total 550 1,160,700 88,257 65,043 162,498 74,241 97,455
78. Given the macroeconomic and sectoral situation in Sudan, the development of solar and wind
power is likely to initially require significant public support in the form of financing and credit
enhancements. Given the significant opportunity cost associated with each year of delaying the
deployment of solar and wind resources in Sudan (US$100 million annually, as indicated above), Sudan
would need to define an adequate partnership framework between public and private sectors that can
enable the development of solar and wind potential at scale and in a sustainable manner. Initially, under
this framework, larger public sector support in the form of financing and assumed risks may be necessary
given the difficult macroeconomic situation of the country and the lack of a successful track record
implementing IPPs. Over time, the required public support should decrease as the macroeconomic and
sectoral reforms improve the investment environment and Sudan establishes a track record of working in
partnership with the private sector.
79. Solar and wind power projects have high financial viability. For a 400 MW solar and 120 MW
wind program, assuming a 12 percent discount rate, the payback is estimated to be four years for the
entire program, with the payback for solar at 4.8 years and the payback for wind at 3 years. The difference
in payback between solar and wind is due to the higher load factor of wind and slightly higher cost per kW
of installed capacity.
Table 3.5: Payback Time of Renewable Energy Program
Net annual
Capital cost benefit
Load Fuel saving per kW Capital cost excluding Pay-back
Capacity factor (million installed (million financing costs time @
(MW) (%) USD) (USD/kW) USD) (million USD) 12%
Solar PV 400 20% 98 800 320 91 4.8
Wind 150 35% 64 950 143 60 3.0
Total 550 162 463 151 4.0
80. The GoS should undertake several steps to implement solar and wind power projects. These
steps include completing feasibility studies and site-specific measurements for potential sites; identifying
the appropriate structure for public and private participation; launching a few pilot projects to test market
appetite and allow the GoS to gain experience by engaging qualified transaction advisers; streamlining
and standardizing the procedures for engaging IPPs consistent with the new PPP Act; and strengthening
GoS capacity in legal issues, financial analysis, cost-benefit analysis, and other aspects of PPPs.
Managing Demand through Energy Efficiency
81. A holistic approach to energy efficiency is required to contain large and increasing energy
consumption and manage peak demand. As discussed earlier, Sudan’s current levels of electricity
consumption and demand growth are not sustainable. To manage electricity consumption and peak
42
demand, it would be useful to pursue a combination of both supply- and demand-side energy-efficiency
measures. Supply-side measures would involve increasing the efficiency of generation plants to reduce
losses in transmission and distribution networks. A non-exhaustive list of supply-side measures could
include using high-efficiency transformers, expanding line capacity, optimizing voltage levels, improving
network reconfiguration, switching off redundant transformers, and balancing three-phase loads.
Demand-side management could be also considered for energy savings and for shifting the consumption
from peak to off-peak hours; such a shift would reduce the need for large investments in generation and
network infrastructure to satisfy peak demand. The energy-efficiency measures should be planned and
phased in the context of integrated sector least-cost planning.
82. Managing demand growth can significantly reduce the sector cost. As shown in Figure 3.4,
curving the demand growth to 5 percent will reduce the sector cost by 30 percent; keeping the demand
at 2018 levels can halve the sector cost compared to the base case scenario. The cost reduction is the
result of avoided fuel cost and capital investment to meet the growing demand. On the other hand, higher
demand growth, such as 15 percent a year (in line with SEDC projections), will result in increased cost of
about 50 percent by 2023. Potential demand-side energy-efficiency measures would include promoting
the use of energy-efficient appliances such as air conditioners and light bulbs through the application of
energy-efficiency norms and standards, and improving access to finance and information for efficient
equipment. Improved building design, such as the use of reflective roofs and better insulation, may offer
low-cost opportunities to reduce cooling needs and therefore reduce electricity demand. A more detailed
assessment of demand-side energy-efficiency measures and their impact would need to be carried out to
identify high-impact and economically and financially viable measures. The demand-side energy-efficiency
measures are most effective when deployed in conjunction with tariff adjustment, which creates better
incentives for customers to conserve energy while helping to mitigate the impact of tariff adjustments on
customers.
Figure 3.4: Impact of Demand Growth Management on Sector Cost
1,800,000 Full cost - demand growth 10% (base case) SDG
Full cost - demand growth 5% SDG
1,600,000 Full cost -demand growth 15% SDG
1,400,000 Full cost - No demand increase
1,200,000
SDG million
1,000,000
800,000
600,000
400,000
200,000
-
2019 2020 2021 2022 2023
Source: World Bank Staff Calculation
83. If the sector’s access to finance deteriorates, the sector may need to consider measures to
reduce demand in absolute terms to maintain the quality of service. Given the ongoing economic crisis
and the GoS’s heavily constrained access to external financing, there is a risk that the GoS cannot sustain
43
the current subsidy level for fuel and capital investment. This inability would create fuel shortages and
constrain thermal generation output. In such a case, the sector would not be able to meet the demand,
resulting in planned or unplanned load shedding, with the quality of electricity service deteriorating.
Demand-side management measures in combination with appropriate price signals could potentially
reduce the demand to mitigate the negative impact on the quality of service.
3.2: Measures to Increase Revenues
Reducing the Social Tariff Threshold
84. The threshold for social tariff in Sudan is high and enlarges the sector’s operating losses and
required subsidy. Contrary to the aim of the policy, the social tariff is not effectively supporting poor
households. At the current threshold of 200 kWh per month, roughly half of residential customers fall into
the social category, which is excessively broad. In addition, most of these customers are likely to be urban
and belong to a relatively well-off segment of the population, given that 60-70 percent of the population
does not have access to electricity. As a result, the lifeline tariff benefits a large number of consumers
with higher income at a significant loss of revenue to the power sector.
85. Reducing the threshold for social tariffs to 100 kWh could increase sector revenues by US$6
million annually while achieving the goal of the social policy instrument, which is to protect poor
households. The threshold for the social tariff should be at the subsistence level, which SE4ALL defines at
30 kWh per month. The social tariff threshold in Sub-Saharan Africa ranges from 30 kWh to 100 kWh per
month (Figure 3.5). Sudan could consider a phased approach for reducing the threshold. The GoS could
immediately reduce the threshold to 100 kWh per month, followed by a reduction of the threshold to 50
kWh over five years, which is the current average in Sub-Saharan Africa. The impact of such an adjustment
on poor households is likely to be negligible. A typical poor (lowest quintile) household with grid access in
Sudan consumes 200 kWh per month. The social tariff threshold adjustment from 200 kWh to 100 kWh
would increase the household bill to SDG 11 per month (the price for the 100-200 kWh portion will
increase by SDG 0.11 per kWh). This is only 0.15 percent of monthly household expenditure, which is SDG
7,000. At the same time, this adjustment would increase sector revenue by SDG 300 million or US$6
million per year.
Figure 3.5: Social Tariff Threshold in Selected Sub-Saharan African Countries
250
200
200
kWh/month
150
100 100
100
50 50
50
0
Egypt Ethiopia Kenya Morocco Sudan
Source: World Bank
Adjusting Tariffs
86. Sudan’s electricity tariffs need to be put on an upward adjustment trajectory. If Sudan aims for
full operational cost recovery by 2028, the average end-user tariff would need to increase significantly
44
from the 2017 level of US¢1.5 per kWh to US¢11.5 per kWh by 2028. This change would translate into an
annual tariff increase of 20 percent over 10 years, assuming that the cost-reduction measures discussed
earlier are also implemented.
87. However, the tariff adjustment necessary for reaching operational cost recovery is extremely
sensitive to external factors such as the exchange rate and domestic inflation. Given the sector’s
dependence on imported fuel for thermal generation, continued devaluation of the Sudanese pound can
potentially offset the sector’s efforts at cost reduction and revenue increase. The international good
practice is to introduce automatic adjustment mechanisms so that changes in external factors are
reflected in the tariff. However, given the hyperinflation in Sudan, such an adjustment may not be feasible.
For this reason, cost recovery will remain a moving target in the medium term in Sudan.
88. The GoS may set an interim tariff target to guide the short-term tariff transition. For example,
an average tariff of SDG 1.2 or US¢2.6 per kWh in five years could be expected to enable the sector to
recover 50 percent of the operational costs under certain external conditions.11 Although this level is
approximately three times the current tariff level, it would still be one of the lowest tariff levels in Sub-
Saharan Africa and would keep the tariffs in the affordability range for the Sudanese people. After
achieving the interim target, the GoS could revisit the target, taking into account evolving external factors
outside the sector’s control to determine the next course of action. Such an approach would allow the
sector to focus on factors within the sector’s control in its effort to achieve cost recovery.
89. The GoS can mitigate the impact of a rising tariff through frequent and incremental increases.
In the past, MoWRIE reviewed the tariff annually at the beginning of the year; the last revisions were in
2016 and 2018. International experience suggests that more frequent revisions, such as semiannual,
quarterly (as in Uganda), or even monthly, allow consumers to adapt to new tariff levels more effectively.
Such an approach allows the government to pause the tariff hike if a significant negative impact on the
public is observed.
Table 3.6: Percentage of Average Tariff Adjustment Needed to Achieve Fivefold Increase in Five Years
Annual Semiannual Quarterly Monthly
(5 Adjustments) (10 Adjustments) (20 Adjustments) (60 Adjustments)
38 17 8 3
90. The tariff increase is unlikely to significantly affect the poor. As part of this diagnostic, a PSIA
was carried out using household survey data and the subsidies simulation (SUBSIM) model12 to assess the
impact of tariff increases on households, especially poor households, as summarized in Figure 3.6. The
impact of the price change is the difference in household well-being13 (of the same year) between the
current tariff level and the price change suggested in each scenario. The PSIA indicates that the direct
effects of tariff increases are relatively small since electricity accounts for a small share of household
11
This assumes an exchange rate of US$1 = SDG 47.5, constant international fuel price, and implementation of
various cost-reduction measures.
12
SUBSIM measures changes in well-being as changes in total consumption (as approximated by expenditure).
Moreover, SUBSIM uses a marginal approach, meaning it assumes the total change in expenditure is approximated
by the change in expenditure on the good whose price changes. See Araar and Paolo, 28.
13
Household consumption is approximated by household expenditure on electricity. The calculations are made
based on data from the NHHBPS 2014 household survey. Expenditure is estimated as monthly expenditure in 2014,
updated by inflation using the IMF World Economic Outlook Database.
45
expenditure (less than 5 percent on average). Depending on the scenario, the total direct loss for
households would range from 0.06 percent, when only the SDG 0.15 lifeline changes from 200 kWh to 100
kWh per month, to 3.14 percent in the scenario when the lifeline of SDG 0.15 decreases from 200 kWh to
100 kWh per month and the rest of the tariffs are increased by 50 percent. The impact of the social lifeline
threshold adjustment is negligible at an average loss of 0.05 percent, with the smallest impact seen on
the poorest quintile. For all scenarios, the impact on the poor was less than half the impact on the middle
class.
Figure 3.6: Impact of Tariff Increase on the Well-being of Different Income Quintiles
4.5
% impact on well-being
4
3.5
3
2.5
2
1.5
1
0.5
0
Q1 Q2 Q3 Q4 Q5
Income Quintile
Lifeline thershold adjustment 5% increase 25% increase 50% increase
Source: World Bank based on NHHBPS 2014
91. Urban middle-income households are likely to be most affected by tariff adjustments. The GoS
should thus target this group with an effective information campaign to ensure public acceptance of tariff
reforms. The PSIA indicates that the largest impact of tariff reforms is likely to be felt by urban middle-
income households (the third income quintile). The majority of the poor (the first quintile and, to a large
extent, the second quintile) do not have access to electricity; for those connected, the consumption level
is relatively low: 177 kWh per month for the first quintile and 208 kWh per month for the second quintile.
Therefore, the direct tariff-adjustment impact on the poor would be limited. The richer households (in the
fourth and fifth quintiles) will be paying higher tariffs, but their high income levels would mitigate the
impact of the increase. In terms of the absolute amount (not percentage), the impact would be the
greatest on the richer segment of the Sudanese population. The urban middle-income population is likely
to be the most vocal and organized in contesting tariff reform. A communications campaign would need
therefore to effectively target the middle class. In addition, the GoS could use a part of the subsidy
reduction to strengthen its social safety net, such as the Social Initiative Program (SIP). Strengthening and
scaling up such a program in conjunction with tariff adjustment is likely to mitigate the tariff reform impact
on the poor and also increase general public acceptance of the reform. Part of the middle-income
population may also be eligible for such support.
92. Timing of tariff adjustment needs to be carefully assessed. Tariff increase in a short timeframe
would likely allow greater cost recovery of the sector, but would have a more significant impact on people
than adjusting tariff over the medium- to long-term. This impact may create political pushback against
further tariff increase. As noted above, a strengthened social safety net can play an important role in
mitigating impact. On the other hand, tariff reform in a longer timeframe would reduce the shocks felt by
people and also allow GoS to take long-term cost-reduction measures. However, such an approach would
require fiscal resources to sustain tariff underpricing in the medium term.
46
93. Beyond the direct impact on households, certain industries and businesses could be impacted
by increased electricity tariff. Energy-intensive industries and businesses – such as ice-making factories,
cold store, private schools/hospitals, workshops, and waterworks – could be affected by increased tariff.
Assessing the magnitude of that impact on the Sudanese economy will require a dedicated analysis.
However, in general, the cost of electricity constitutes a small portion of business operation, and therefore
the overall impact of tariff increase is likely to be small.
3.3: Measures to Facilitate Reforms
Accompanying Reforms with Public Communication
94. Currently, public acceptance or support for tariff increase in Sudan is likely to be low due to
several factors. First, because of Sudan’s legacy as an oil-producing nation, the public is likely to be used
to low-cost electricity and broader energy services. Second, it is likely that the ongoing economic crisis
and public unrest in the country are undermining confidence in the Sudanese authorities and reducing
willingness to accept any price increase. Similar cases have been observed in other countries (for example,
Egypt, Tunisia, Jordan, and Nigeria), where the public had very limited understanding of energy sector
realities and challenges. In those countries, the public also believed that the country was rich in energy
(for example, oil and gas) but that the energy was expensive because the government was not managing
the sector well. This belief prevailed despite the fact that energy was heavily subsidized. In many of these
countries, well-designed communications campaigns facilitated a shift in public opinion toward support
of subsidy reform. The campaigns were based on high-level government commitment, public opinion
research, stakeholder mapping, and political economy analyses. The opposite approach — a rushed effort
to reform subsidies without a well-prepared communications campaign — often backfired during the
reform implementation, as was the case in Tunisia.
95. Tariff reform is essential for sector recovery in Sudan, and the reform needs to be carefully and
strategically communicated to the public. The GoS’s communications or public relations teams in the
electricity sector can play a key role in the information campaign. A shared vision of the communications
program and its implementation among all communications/public relations teams in the power sector
and other associated sectors must be in place to avoid duplication or contradictory messages. The
communications campaign can raise awareness about the current magnitude of the subsidy and the
consequences of allowing the status quo to persist, including lost opportunities to use resources to
improve other key public services such as health, education, transport, and water supply. It can showcase
the roles that sector authorities are playing to keep electricity affordable (for example, development of
domestic renewable electricity and power trading) and improve the reliability and quality of the electricity
supply. Such a campaign can also educate the public about reducing electricity consumption through
energy-efficient behaviors that could lower their monthly bill.
96. The communications campaign should be underpinned by solid research and supported by a
specialized firm. The GoS would need to form a sector-wide communications team to prepare a
communications strategy, engage a specialized communications firm to assist in this effort, conduct a
public opinion survey and stakeholder mapping exercise to inform the strategy, prepare the strategy and
necessary materials, and launch the communications campaign.
Improving Institutional Arrangements
97. The GoS should also clearly delineate the roles and responsibilities for policy-making, regulation,
and operational management to facilitate implementation of reforms. There are currently large
numbers of institutions involved in the operation of the electricity sector, leading to numerous interface
problems (increased operational and transaction costs) and various complexities in terms of
47
administration, coordination, and management. The sector has five companies — thermal, hydro and
renewable, transmission, distribution, and holding. There are overlapping responsibilities among
MoWRIE, ERA, DIU, and SEHC. Clarifying the roles and responsibilities of sector companies and oversight
institutions will improve the efficiency of sector operation and decision-making.
98. The electricity sector needs commercialization and corporatization of its utilities to achieve
increased autonomy for companies in their financial and operational decision-making. The current
arrangement, in which all budgetary appropriations and sales revenue are pooled into SEHC for
redistribution to the sector companies complicates sector financial flows and may contribute to
operational inefficiencies. The arrangement provides limited incentives for prudent cost control and
revenue-enhancement measures. The commercialization of sector companies should include (a)
commercial and contractual transactions between the value chains of generation, transmission, and
distribution under the negotiated tariff; (b) delegation of investment decisions to sector companies; and
(c) external auditing of financial statements of sector companies following international accounting best
practice.
99. The role of the ERA needs to be more clearly defined and strengthened, particularly with regard
to tariff-setting. In the current institutional context of the sector, the ERA’s role is to recommend tariffs
to MoWRIE in consultation with the sector companies. However, the ERA has been unable to complete a
tariff study initiated in 2015 due to a shortage of technical capacity and financial resources. Consequently,
the sector has been unable to implement adequate tariff schedules that are based on sector technical,
economic, and distributional analyses. The ERA’s capacity needs to be strengthened if it is to properly
review and recommend tariffs and monitor the sector’s technical and financial performance.
48
Annexes
Annex 1: List of Current and Prospective Generation Assets in Sudan
Installed
Name Year Type Technology Fuel
Capacity (MW)
On-Grid
Merowe 2009 Hydro — — 1,250.0
Kosti 2008 Thermal Steam turbine Crude oil 500.0
Garri 1 and 2 2002 Thermal Combined cycle gas turbine LDO/HCGO 469.0
Garri 4 2006 Thermal Steam turbine SC 110.0
Mahmoud Sharif 1985 Thermal Steam turbine HFO/HCGO 380.0
Mahmoud Sharif 2016 Thermal Gas turbine LDO/HCGO 150.0
Roseires 1971 Hydro — — 280.0
Port Sudan 1983 Thermal Diesel engine DO/LDO 40.0
Jabal Awlia 2005 Hydro — — 30.4
Sinnar 1962 Hydro — — 15.0
Khashm El Girba 1965 Hydro — — 17.8
E Obied 1987 Thermal Diesel engine DO/LDO 12.7
Seitat and Upper Atbara 2018 Hydro — — 320.0
Off-Grid
Al-Fasir 2002 Thermal Diesel engine LDO/DO 31.0
Nyala 1985 Thermal Diesel engine HFO/DO/LDO 32.0
El-Ginena 1989 Thermal Diesel engine DO/LDO 10.0
Kadogli 2004 Thermal Diesel engine DP/LDO 8.0
El-Nohod 2004 Thermal Diesel engine DP/LDO 8.4
El-Diain 2004 Thermal Diesel engine DO/LDO 7.5
Zalingei 2015 Thermal Diesel engine LDO 2.6
In Pipeline
Garri 3 2019 Thermal Gas turbine HFO 561.0
Port Sudan 2019 Thermal Gas turbine HFO 376.0
Al-Fasir 2019 Solar PV (hybrid with diesel) 5.0
El Dein 2019 Solar PV (hybrid with diesel) 5.0
Darfur 2019 Thermal Diesel engine HFO + LDO 150.0
Garri 3 upgrade 2021 Thermal Combined cycle gas turbine Exhaust flue gas 240.0
Port Sudan upgrade 2021 Thermal Combined cycle gas turbine Exhaust flue gas 1175.0
Al-Bagir 2021 Thermal Combined cycle gas turbine HFO 350.0
Al-Fulah 2021 Thermal Gas turbine Gas 450.0
Dongola 2021 Wind — — 1.0
Red Sea 2022 Thermal Steam turbine Coal 1,000.0
Elshaheed 2022 Thermal Gas turbine HFO and LDO 350.0
Note: DO: Diesel Oil (70 percent LDO + 30 percent HFO).
49
Annex 2: Sudan’s Electricity Tariff Structure
US$/kWh
No. Sector/Consumption kWh SDG/kWh (2018)
(US$1 = SDG 47.6)
1 Domestic tariff
From 1 to 200 0.15 0.003
From 201 to 400 0.26 0.005
From 401 to 600 0.32 0.007
From 601 to 800 0.52 0.011
From 801 to 1,500 0.85 0.018
Above 1,500 1.60 0.034
2 Agricultural tariff
Up to 50 HP, National and Research and
Training Projects 0.16 0.003
More than 50 HP 1.60 0.034
3 Industrial tariff
Medicine industries 0.18 0.004
Other industries 1.60 0.034
Cold stores and ice
• From 1 to 400 0.34 0.007
• More than 400 0.85 0.018
4 Commercial tariff
From 0 to 200 0.34 0.007
From 201 to 300 0.85 0.018
From 301 to 400 1.00 0.021
More than 400 1.60 0.034
5 Service tariff
Water works and holy places 0.33 0.007
6 Schools
Government schools 0.33 0.007
Private student hostels 0.33 0.007
7 Private hospitals and universities 0.75 0.016
8 Government
Government departments 0.70 0.016
9 Tourism (hotels) 0.85 0.018
10 Communications companies, embassies, and
organizations 1.60 0.034
50
Annex 3: Electricity User Profile in Sudan
Sales (MWh) 2015 2016 2017
Residential 5,973,123 6,693,310 7,352,511
Industrial 1,512,258 1,794,317 2,003,377
Commercial 1,378,184 1,473,870 1,568,314
Agricultural 650,664 718,924 873,881
Government 1,034,352 1,087,877 1,163,088
Company facilities 32,033 27,232 25,445
Total 10,580,614 11,795,530 12,986,616
Revenue (SDG, millions)
Residential 1,212,059 1,422,690 2,145,636
Industrial 257,911 305,799 429,186
Commercial 468,680 570,926 1,059,828
Agricultural 104,196 115,039 152,358
Government 588,577 610,293 658,389
Total 2,631,423 3,024,747 4,445,397
Number of customers
Residential 2,020,878 2,096,756 2,218,516
Industrial 1,852 2,006 2,216
Commercial 217,565 227,591 235,989
Agricultural 17,772 19,422 21,486
Government 44,734 46,025 50,256
Internal consumption 257 265 266
Total 2,303,058 2,392,065 2,528,729
51
Annex 4: Power System Map of Sudan
Power System Map of Sudan
52
Annex 5: Description of Key Sector Entities
1. MoWRIE was created in 2012. It supervises all electricity sector companies, appointing key staff,
allocating vital financial support to SEHC, and controlling investment decisions through the direct
management of financing of all capital investment. MoWRIE also supervises ERA. Other key
responsibilities of MoWRIE include:
• Approving general policies and rules for power generation, transmission, and distribution;
• Negotiating and concluding any agreement related to power imports and exports;
• Approving sector technical specifications;
• Setting electricity tariffs upon recommendation of ERA; and
• Supervising the activity of sector institutions (particularly DIU and SEHC), a function not
listed in the 2001 act.
MoWRIE has limited planning and implementation capacity. It has to make investment decisions based
on the availability of financing, with little consideration for the sector development plan. MoWRIE is
making efforts to improve its capacity to organize and develop renewable energy projects to be funded
by the private sector; this work is taking place in consultation with the MoFEP and the Ministry of
Investments.
2. SEHC was created in 2016 and is fully government controlled. It delegates operational
responsibilities to its subsidiaries but retains a major role in allocating to subsidiaries revenues collected
by the SEDC (topped up by the GoS budget allocation) and in investment decisions and financing. The
SEHC also negotiates transfer prices between power sector entities, which are its subsidiaries, and is
responsible for power dispatch.
3. SHGC is responsible for the O&M of all hydro plants and dams. It has no authority over investment
decisions, which in principle are made at the SEHC level, based on the MoWRIE development plan for
hydro. In practice, investment decisions are made by DIU, which is also responsible for implementation.
(For minor investments not handled by DIU, procurement is overseen by the SEHC and implemented
under its supervision.) Like all subsidiaries of the SEHC, the SHGC is not responsible for its finances, apart
from implementing its annual budget, nor does it supervise construction. The SHGC supplies the electricity
it produces to SETCO at the transfer price set by the SEHC and MoWRIE in consultation with ERA. Created
in 2016, the SHGC plants generated 8,052,178 MWh in 2017.
4. STPG is the subsidiary of the SEHC responsible for managing the construction of thermal plants
and their operation, as well as the supervision of investments, which are decided at SEHC level. Created
in 2016, the STPG’s function is essentially technical, as investment financing and procurement are handled
by the SEHC. The STPG supplies the electricity it produces to SETCO at the transfer price set by the SEHC
and MoWRIE in consultation with ERA. Presently, the transfer price to SETCO is SDG 0.0783 per kWh and
does not include the fuel cost, which is paid directly to fuel suppliers by the government. In 2017, the
volume of energy sold by the STPG was 6,193.70 GWh.
5. SETCO is responsible for the management, maintenance, and operation of the power transmission
system and for supervising the construction of transmission infrastructure. Like the STPG, SETCO was
created in 2016, and its role is mainly technical. It is not the power dispatcher. SETCO purchases electricity
produced from grid-connected thermal and hydropower plants, acting in practice as a single buyer rather
53
than as a transmission service provider; it sells at a uniform price to the SEDC with a markup of SDG 0.0124
per kWh to cover transmission costs. The volume of electricity SETCO transmitted in 2017 was 14,638.83
GWh.
6. SEDC is the SEHC subsidiary in charge of power distribution, managing the national distribution
grid and also some isolated grid systems. In practice, it is the sole distributor in Sudan, though its
monopoly is not enshrined in law. Created in 2016, the SEDC had a total of 2.5 million clients as of 2017;
all but 5,000 of those had prepayment meters. The SEDC collects electricity bills from all clients and remits
the proceeds to the SEHC after deduction of its own cost of distribution. Sales in 2017 were 12,986 GWh,
and distribution losses were estimated at about 15 percent, of which 6 percent were technical losses.
Distribution system extensions in isolated grid or grid-connected networks are requested by the states
and financed by the GoS and consumers. The connection fee is SDG 7,000-15,000 for households. Most
isolated grids are financially autonomous and are managed by states or local communities.
7. DIU was created in 1999 to develop, construct, and supervise the Merowe dam. Its role was
extended in 2005 to cover the development and supervision of construction of all hydropower plants.
Capitalizing on its experience in complex infrastructure projects, DIU is now extending outside of the
electricity sector to major infrastructure projects. After completion of construction, infrastructure is
transferred for operation and management to technical ministries and entities. DIU has become a
powerful and highly competent unit in charge of pre-feasibility and feasibility studies, irrigation schemes,
water harvesting, transport infrastructure (bridges), some housing development, financing of
infrastructure (from Islamic Development Bank and Arab Funds through the MoFEP), and contracts
tendering. DIU is accountable directly to MoWRIE and has the status of a corporation, with a state minister
in MoWRIE appointed as its chief executive officer.
8. ERA is the sector regulator. Created by the Electricity Act of 2001, ERA is directly under the
authority of MoWRIE and is fully funded by an annual budgetary allocation from MoWRIE; it has limited
independence. ERA is currently chairing the drafting committees for the preparation of the Renewable
Energy and Energy Efficiency Acts. The responsibilities of ERA include:
• Preparing electricity policy for approval by MoWRIE;
• Supervising generation, transmission, and distribution activities in accordance with sector
policies and strategies set by MoWRIE;
• Acting as technical adviser to the GoS;
• Supporting potential investors in the power sector;
• Making recommendations to MoWRIE concerning electricity tariffs;
• Setting technical specifications applicable to the power sector (including power utilities and
consumer electronics);
• Issuing licenses for power sector operators; and
• Supporting the implementation of environmental regulations applicable to the power sector.
54
Annex 6: Least-cost Analysis for Sudan’s Electricity Generation
A comparison of the least-cost and government generation expansion plans in the near term (2019–
2023) reveals that the former can defer US$1.65 billion of capital expenses and save US$536 million of
fuel costs over the four-year period. The LCP defers liquid fuel based capacity and instead brings in
additional wind and solar capacity.
1. The analysis compares an LCP optimized over 2019–2030 with the Government Plan (Gov Plan).
In particular, we focus on 2019–2023 to look at the difference in CAPEX and fuel cost differences, as
summarized in Table A0.1 below. There is a significant amount of CAPEX (US$1.65 billion) that could be
deferred over this period. The fuel cost savings are significant: US$536 million over five years. Note that
the CAPEX difference over 2019–2023 should not be added to the fuel cost difference. The CAPEX plans
should be compared over a longer period for long-lived assets. The CAPEX difference over 2019–2023
simply indicates that some CAPEX during the early years could be postponed.14 The net present value (NPV)
of annualized capital cost difference over 2019–2023 is a more modest US$175.27 million if we assume
that all of the generation assets have a life of 30 years and the cost of capital is 10 percent. This savings
of US$175.27 million can be added to the fuel cost savings of US$536 million to yield a total savings of
US$710.80 million. The average generation cost in the LCP over 2019–2023 is US¢ 0.8 per kWh lower (or
9 percent) relative to the Gov Plan.
Table A0.1: Summary of Cost Savings (NPV 2019–2023 at 10 percent in US$, millions)
LCP Gov plan Difference
CAPEX 5,211 6,863 32%
Fuel 5,103 5,638 10%
2. In the long run (by 2030), the total CAPEX in the LCP (US$12.4 billion) and Gov Plan (US$12.7
billion) are quite close to each other, suggesting that most of the capacity included in the Gov Plan is
eventually needed but can be postponed, as has been accomplished in the LCP.
14
It is worth noting, however, that the capital deferral will not necessarily occur every year and the LCP in fact has
slightly more CAPEX in 2020 and 2023 compared to the Gov Plan. The key is that the LCP optimizes capacity and fuel
costs together over 2019–2030 and, although it defers capital costs as much as possible, there will be a need to bring
in some of the cheaper capacity early on to save fuel costs.
55
Figure A0.1: Comparison of Cumulative Generation CAPEX (US$, millions)
14,000.0
12,000.0
US$, millions 10,000.0
8,000.0
6,000.0
4,000.0
2,000.0
-
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
LCP Gov Plan
Source: World Bank staff calculation
3. Finally, a comparison of the detailed capacity and generation in 2023 reveals that:
• Around 860 MW of capacity can be saved, primarily in the form of deferring/avoiding
expensive HFO (1,230 MW) and LFO (450 MW) based capacity;
• There is more solar (150 MW) and wind (560 MW) capacity in the LCP;
• There is significantly lower HFO-based generation (1,298 GWh) although some of the LFO
capacity needs to be run harder to produce 537 GWh additional generation;
• There is additional 285 GWh of solar and 886 GWh of wind in the LCP; and
• Total generation remains the same across the LCP and Gov Plan.
Table A0.2: Comparison of Capacity (MW) and Generation (GWh) in 2023
Capacity (MW) Generation (GWh)
LCP Gov Plan Difference LCP Gov Plan Difference
COAL 600 600 0 4,468 4,730 −263
Import 500 390 110 2,799 2,946 −147
Coke 110 110 0 819 819 0
Diesel 99 99 0 0 0 0
Gas 0 0 0 0 0 0
HFO 2,438 3,668 −1,230 4,725 6,023 −1,298
LFO 580 1,030 −450 938 401 537
Water 1,974 1,974 0 11,412 11,412 0
Solar 810 660 150 1,539 1,254 285
WIND 800 240 560 1,265 380 886
TOTAL 7,911 8,771 −860 27,965 27,965 0
56
Annex 7: Sector Capacity Building and Technical Assistance Needs
Tariff Tariff reform planning: Detailed tariff reform, including the setting of interim
target, timeframe and adjustment of lifeline tariff, will need analytical
support.
Public communication support: Specialized consultant can help carry out
public opinion survey and develop communication strategy to enhance public
acceptance for tariff reform.
Planning In-house capacity for least-cost planning. Such planning capability will allow
frequent revision of sector investment plan and ensure that available
financing is used for maximum benefit.
Renewables Training for public-private partnership. Given Sudan’s limited exposure to
private investment in the sector, a fundamental training on public-private
partnership, including technical, financial and legal aspects, will be useful.
Transaction advisory. A qualified firm for transaction advisory service can
work to sound out the market to assess interest in private investment in the
power sector in Sudan and potentially design a competitive bidding.
Energy Supply-side energy audit can identify low-cost distribution loss-reduction
Efficiency opportunities.
Demand-side energy audit can assess electricity consumption profile in
various user types and identify low-cost measures to curb demand.
Electrification GIS-based planning. With adequate support, GoS can develop a least-cost
electrification plan to enhance electricity access.
Off-grid market development support. GoS can learn from other neighboring
countries how to scale up high-quality off-grid solutions.
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References
Araar, Abdelkrim, and Paolo Verme. “SUBSIM: A User Guide.”
Kojima, Masami, and Chris Trimble. 2016. Making Power Affordable for Africa and Viable for Its Utilities.
World Bank, Washington, DC. https://openknowledge.worldbank.org/handle/10986/25091
License: CC BY 3.0 IGO.
Trimble, et al. 2016. “Financial Viability of Electricity Sectors in Sub-Saharan Africa: Quasi-Fiscal Deficits
and Hidden Costs.” https://openknowledge.worldbank.org/handle/10986/24869
World Bank and International Energy Agency (IEA). 2015. Progress toward Sustainable Energy: Global
Tracking Framework. Washington, DC: The World Bank.
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