Mineral Resource based Growth Pole Industrialisation

Transcription

Mineral Resource based Growth Pole
Industrialisation - Coal, Gas and Oil
C.C. Callaghan
Revamping the Regional Railway Systems in
Eastern and Southern Africa
Mark Pearson and Bo Giersing
Regional Integration Research Network Discussion Paper (RIRN/DP/12/01)
Regional Integration Research Network
Open Dialogues for Regional Innovation
Mineral Resource Based Growth Pole Industrialisation – Oil, Gas and Coal Report
Preface
Since its establishment in 2009, Trade Mark Southern Africa (TMSA) has supported the
Tripartite of the Common Market of Eastern and Southern Africa (COMESA), the Southern
African Development Community (SADC) and the East African Community (EAC), in
developing and implementing its regional integration agenda.
This involves supporting the
design and planned implementation of the Tripartite Free Trade Area (FTA), improving the
economic competitiveness of the region and reducing costs of cross-border transactions
through a transport corridor approach addressing both trade facilitation issues and
infrastructure constraints.
Focused industrial development is essential in the COMESA-EAC-SADC Tripartite region to
fundamentally change the economy and to promote high yield sectors. Such development
brings not only an improvement in the GDP and job provision, but promotes knowledge
accumulation and technological sophistication that have far reaching benefits for the
economy.
This research was conducted under the topic “Tripartite ‘Growth Pole’ Diagnostic
Reports: Analysis of Potentials and Prospects for Minerals-Based Industrialisation.”
The research is packaged in four (4) Sub-Sector Reports on hydrocarbons, ferrous metals,
base metals and phosphates and a Consolidated ‘Growth Poles’ Report. The reports profile
and prioritise a number of potential regional ‘growth poles’ throughout eastern and southern
Africa. In the ‘first sort’ each known minerals deposit was analysed through three (3) filters
as follows:
1. By size of deposit (size of known indicated resource);
2. By status of deposit (levels of investment in developing the deposit); and,
3. By ‘expert group’ assessment (market conditions and supporting infrastructure).
The research reviewed available information on mineral deposits and the status of their
development and analysed the extent to which realisable mining and mineral development
opportunities can contribute to and enhance regional development. Data constraints limited
the research to the Eastern and Southern Africa region and defined a limited number of
plausible ‘growth poles’, which could provide a platform to accelerate industrialisation in the
region.
The results from these three filters were then combined through a ‘second sort’, which
enhanced the analysis by clustering minerals within a defined locality into potential ‘growthpole’ value chains. In line with ‘growth pole’ theory the basis for any prioritisation was
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whether the initial ‘critical mass’ of investment had been achieved. The minimum critical level
of investment is considered to be achieved when five key pre-conditions have been met,
namely:
1. A recognised global multi-national corporation (MNC) has made a significant
investment in developing a mineral deposit or a cluster of mineral deposits;
2. Such an investment commitment reflects that the regulatory environment for trade
and investment in sufficiently robust to support large-scale projects;
3. Similarly, this size of investment in developing a world-class resource confirms that
the long term global market outlook for the target commodity is equally robust;
4. It also acknowledges that any supply-side infrastructure constraints can be overcome
by the projects cash-flows and that infrastructure development itself represents an
opportunity for the lead developer, in the transport and energy sectors for example;
and,
5. Finally, the participation of a strong ‘anchor’ investor substantially strengthens the
prospects for developing upstream linkages to local suppliers and new downstream
industries as a result of the presence of and initial investment by the global mining
company.
In addition to these pre-conditions the research also considers two additional criteria to
prioritize ‘growth-pole’ potential. The first was the extent to which the value-chain could be
developed given prevailing market conditions, and the second was whether value-chain
linkages straddle national borders to assume a regional posture.
Based on these considerations the following seven (7) regional growth poles were prioritised
in order of potential:
1. Tete, Mozambique – Southern Malawi (Hydrocarbons, Ferrous Metals and
Phosphates);
2. Copperbelt, Zambia – Copperbelt, DRC (Base Metals);
3. Cabinda, Angola – Bas Congo, DRC – Soyo, Angola (Hydrocarbons and
Phosphates);
4. Rovuma Basin, Mozambique – Ruvuma and Songo-Songo Basins, Tanzania
(Hydrocarbons);
5. Lephalale, South Africa – Morepule, Botswana (Hydrocarbons);
6. Kabanga, Tanzania – Musongati, Burundi (Base Metals); and,
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7. Central Zimbabwe – Central Mozambique (Hydrocarbons and Ferrous Metals).
An initial scoping study is currently being conducted to develop a fuller picture of the Tete,
Mozambique – Southern Malawi ‘Growth Pole’, which has been expanded to include
Eastern, Zambia, in collaboration with the World Bank and the governments of Malawi,
Mozambique and Zambia.
TMSA, under its Regional Integration Research Network initiative, commissioned Chris
Callaghan to conduct the research. Chris Callaghan is an independent consultant whose
career includes stints as a Mining Sector Specialist at the Development Bank of Southern
Africa (DBSA) and a Senior Manager at MINTEK South Africa, the state-run Mining
Technology Research Institute. The TMSA lead was Graham Smith, TMSA Programme
Manager - Corridors.
The study benefited particularly from guidance and inputs by Dr.
Judith Fessehaie, TMSA Industrial Development Expert and Mr. Bo Giersing, TMSA Ports
and Railway Specialist, Mr. Jurgens Van Zyl, an independent Mining and Development
Finance Specialist, currently under contact to Business Leadership South Africa (BLSA) and
Dr. Paulo Fernandes, a Logistics Specialist at Mott MacDonald/PDNA South Africa. These
individuals ‘peer reviewed’ the prioritisation methodology, which underpinned the selection of
the Growth-Poles. Other TMSA colleagues provided some early inputs into the terms of
reference for the study.
More Information
The
reports
can
be
downloaded
on
the
TMSA
website
at
www.trademarksa.org/publications/mineral-resource-based-growth-pole-industrialisation
Reports include the Consolidated Growth Poles and Value-Chains Report and four (4) SubSector Minerals Reports on Hydrocarbons (Coal, Oil and Gas), Ferrous Metals (Iron and
Steel), Base Metals (Chrome, Manganese, Nickel, Vanadium, Copper, Zinc and Lead) and
Phosphates report.
Page iii
Table of abbreviations
American Petroleum Institute
Billion Barrels
Billion cubic metres
Barrels
Coal Bed Methane
Deadweight tons
Gigajoules
Exajoule
Mozambican Mining & Exploration Company
Thousand cubic metres
Liquefied natural gas
Liquid Petroleum Gas
Million barrels
Million barrels per day
Million Cubic metres
Megajoules per kilogram (an expression of calorific value)
Reasonably Assured Resources
Tonnes
Organisation of the Petroleum exporting countries
International Energy Agency
Tonne of coal equivalent
Trillion cubic metres
Tonnes per annum
Zambia Electricity Supply corporation
API
bbls
bcm
bls
CBM
dwt
GJ
EJ
EMEM
kcm
LNG
LPG
Mbls
Mblpd
Mcm
MJ/kg
RAR
t, ton
OPEC
IEA
tce
tcm
tpa
ZESCO
Table of Definitions
Calorific value
Refinery
processing gain
Maceral
tce
Kerosene
Exajoule (EJ)
Simply stated the calorific value is the amount of heat energy released when the substance undergoes complete
combustion under standard conditions. It may be measured in kcal/kg or MJ/kg or Btu/lb. See Appendix III for
conversions.
The amount by which total volume of products output is greater than the volume of crude oil and other feed stocks.
This “gain’ is due to the processing of crude oil into products that, overall, have lower specific gravity than the crude
oil being processed.
A maceral is the basic organic building block of coal, and consists of the dehydrogenated plant material. There are
three groups of macerals, the vitrinite group derived from coalified woody tissue, the liptinite group derived from
the resinous and waxy parts of plants and the inertinite group derived from charred and biochemically altered plant
cell wall material. Each is further divided into more specific macerals types
The tonne of coal equivalent is a unit representing the energy generated by burning one tonne of coal, equivalent to
the energy obtained from burning 5.2 barrels (700 kilograms) of oil or 890 cubic meters of natural gas. It represents
29.39 gigajoules (GJ) and is the equivalent of burning one tonne of coal with a calorific value of 29.39 MJ/kg
A term used in the United States and Canada equivalent to “Paraffin”. Besides being widely used in Africa for
cooking and lighting, it is a major component of some jet fuels.
An exajoule is 1018 Joules or 109 gigajoules
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Table of Contents
1
Introduction .......................................................................................................... 1
2
Coal ....................................................................................................................... 6
2.1
Introduction ............................................................................................................... 6
2.1.1 Power energy deficit .............................................................................................. 6
2.2
Fundamental concepts ............................................................................................. 6
2.2.1 Formation and quality ............................................................................................ 6
2.2.2 Mining .................................................................................................................... 7
2.2.3 Beneficiation .......................................................................................................... 8
2.3
Market ......................................................................................................................... 9
2.3.1 Uses ...................................................................................................................... 9
2.3.2 Production ............................................................................................................. 9
2.3.3 Demand ............................................................................................................... 10
2.3.4 Supply ................................................................................................................. 12
2.3.5 Trade ................................................................................................................... 14
2.3.6 Price .................................................................................................................... 15
2.3.7 Cost of production ............................................................................................... 15
2.3.8 Value added products and substitution ............................................................... 16
3
Oil ........................................................................................................................ 17
3.1
Introduction ............................................................................................................. 17
3.2
Fundamental concepts ........................................................................................... 17
3.2.1 Types of crude oil ................................................................................................ 17
3.2.2 South Atlantic Geology ........................................................................................ 18
3.2.3 Relationship of geological history to Crude oil quality ......................................... 20
3.2.4 Organisation of Petroleum Producing Countries (OPEC .................................... 20
3.3
Market ....................................................................................................................... 20
3.3.1 Uses .................................................................................................................... 21
3.3.2 Production ........................................................................................................... 21
3.3.3 Demand ............................................................................................................... 24
3.3.4 Supply ................................................................................................................. 25
3.3.5 R/P Ratio ............................................................................................................. 25
3.3.6 Trade ................................................................................................................... 26
3.3.7 Price .................................................................................................................... 26
4
Gas ...................................................................................................................... 28
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4.1
Introduction ............................................................................................................. 28
4.2
Market ....................................................................................................................... 28
4.2.1 Uses .................................................................................................................... 28
4.2.2 Production ........................................................................................................... 29
4.2.3 Demand ............................................................................................................... 29
4.2.4 Supply ................................................................................................................. 31
4.2.5 Trade ................................................................................................................... 31
4.2.6 Price .................................................................................................................... 33
5
Angola................................................................................................................. 34
5.1
Coal .......................................................................................................................... 34
5.2
Oil ............................................................................................................................. 34
5.2.1 Exploration .......................................................................................................... 34
5.2.2 Resources and reserves ..................................................................................... 38
5.2.3 Production ........................................................................................................... 38
5.2.4 Beneficiation ........................................................................................................ 39
5.2.5 Exports ................................................................................................................ 39
5.3
Gas ........................................................................................................................... 40
5.3.1 Exploration and production ................................................................................. 40
5.4
6
Electricity ................................................................................................................. 41
Botswana ............................................................................................................ 42
6.1
Coal .......................................................................................................................... 42
6.1.1 Reserves and resources ..................................................................................... 42
6.1.2 Deposits .............................................................................................................. 42
6.1.3 Logistics .............................................................................................................. 49
6.2
Coal bed methane (CBM) ........................................................................................ 50
6.2.1 Energy Botswana Ltd. ......................................................................................... 50
6.2.2 Saber Gas project ............................................................................................... 50
6.3
7
8
Oil and Gas .............................................................................................................. 50
Burundi ............................................................................................................... 51
7.1
Coal .......................................................................................................................... 51
7.2
Oil ............................................................................................................................. 51
7.3
Gas ........................................................................................................................... 51
Comoros ............................................................................................................. 52
8.1
Coal .......................................................................................................................... 52
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8.2
Oil ............................................................................................................................. 52
8.3
Gas ........................................................................................................................... 52
9
DRC ..................................................................................................................... 53
9.1
Coal .......................................................................................................................... 53
9.1.1 Lukuga ................................................................................................................ 53
9.1.2 Luena .................................................................................................................. 53
9.1.3 Coal Production ................................................................................................... 54
9.2
Oil ............................................................................................................................. 54
9.2.1 Bas Congo .......................................................................................................... 54
9.2.2 Albertine Graben ................................................................................................. 55
9.2.3 Oil Shale .............................................................................................................. 57
9.3
10
Gas ........................................................................................................................... 57
Djibouti ............................................................................................................. 58
10.1
Coal ........................................................................................................................ 58
10.2
Oil ........................................................................................................................... 58
10.3
Gas ......................................................................................................................... 58
11
Egypt ................................................................................................................. 59
11.1
Coal ........................................................................................................................ 59
11.1.1 El Maghara Coal Mine ....................................................................................... 59
11.2
Oil ........................................................................................................................... 59
11.2.1 National Oil Company ....................................................................................... 60
11.2.2 Reserves and resources ................................................................................... 60
11.2.3 Exploration and Production ............................................................................... 60
11.2.4 Exports .............................................................................................................. 62
11.2.5 Company News ................................................................................................. 62
11.3
Gas ......................................................................................................................... 64
11.3.2 Exploration and production ............................................................................... 64
11.3.3 Consumption ..................................................................................................... 65
11.3.4 Exports .............................................................................................................. 65
11.3.5 Company News ................................................................................................. 67
11.3.6 Primary Energy Consumption ........................................................................... 67
12
Eritrea ............................................................................................................... 68
12.1
Coal ........................................................................................................................ 68
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12.2
Oil ........................................................................................................................... 68
12.3
Gas ......................................................................................................................... 68
13
Ethiopia ............................................................................................................ 69
13.1
Coal ........................................................................................................................ 69
13.1.1 Delbi-Moye basin coal & oil shale deposits ....................................................... 69
13.1.2 Geba basin coal deposit ................................................................................... 69
13.1.3 Chilga Basin /Chilga and Delgi localities/ coal deposits .................................... 70
13.1.4 Coal and oil shale deposits in Lalo-Sapo Basin ................................................ 70
13.1.5 Import ................................................................................................................ 70
13.2
Oil and Gas ............................................................................................................ 70
13.2.3 Trade ................................................................................................................. 73
13.2.4 Company News ................................................................................................. 74
14
Kenya ................................................................................................................ 75
14.1
Coal ........................................................................................................................ 75
14.1.1 Mui Basin Coal .................................................................................................. 75
14.2
Oil ........................................................................................................................... 75
14.2.3 Company News ................................................................................................. 77
14.3
15
Infrastructure ......................................................................................................... 78
Lesotho ............................................................................................................. 81
15.1
Coal ........................................................................................................................ 81
15.2
Oil ........................................................................................................................... 81
15.3
Gas ......................................................................................................................... 81
16
Libya ................................................................................................................. 82
16.1
Coal ........................................................................................................................ 82
16.2
Oil ........................................................................................................................... 82
16.2.3 Local consumption and Exports ........................................................................ 84
16.3
Gas ......................................................................................................................... 87
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16.3.3 Local consumption and export .......................................................................... 87
17
Madagascar ...................................................................................................... 88
17.1
Coal ........................................................................................................................ 88
17.2
Oil ........................................................................................................................... 88
17.2.2 Exploration ........................................................................................................ 88
17.2.3 Production ......................................................................................................... 89
17.2.4 Regulation ......................................................................................................... 90
18
Malawi ............................................................................................................... 91
18.1
Coal ........................................................................................................................ 91
18.1.3 Consumption ..................................................................................................... 92
18.1.4 Company News ................................................................................................. 92
18.1.5 Planned transmission upgrade and power station ............................................ 93
18.2
Oil and Gas ............................................................................................................ 93
18.2.1 Border dispute ................................................................................................... 94
18.2.2 Company News ................................................................................................. 94
19
Mauritius ........................................................................................................... 95
19.1
Coal ........................................................................................................................ 95
19.2
Oil and Gas ............................................................................................................ 95
20
Mozambique ..................................................................................................... 96
20.1
Introduction ........................................................................................................... 96
20.2
Coal ........................................................................................................................ 96
20.2.2
Deposits ............................................................................................................ 97
20.2.3 Production ....................................................................................................... 101
20.2.4 Logistics .......................................................................................................... 103
20.2.5 Challenges ...................................................................................................... 103
20.3
Oil ......................................................................................................................... 104
20.4
Gas ....................................................................................................................... 104
20.4.1 Reserves and resources ................................................................................. 104
20.4.2 Exploration ...................................................................................................... 104
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20.4.3 Production ....................................................................................................... 108
20.4.4 Trade ............................................................................................................... 109
21
Namibia ........................................................................................................... 110
21.1
Coal ...................................................................................................................... 110
21.2
Oil and Gas .......................................................................................................... 110
21.2.1 Value addition ................................................................................................. 110
22
Rwanda ........................................................................................................... 112
22.1
Coal ...................................................................................................................... 112
22.2
Oil ......................................................................................................................... 112
23
Seychelles ...................................................................................................... 113
23.1
Coal ...................................................................................................................... 113
23.2
Oil and Gas .......................................................................................................... 113
23.2.1 Afren ................................................................................................................ 113
24
South Africa ................................................................................................... 115
24.1
Introduction ......................................................................................................... 115
24.2
Coal ...................................................................................................................... 116
24.2.1 Reserves and Resources ................................................................................ 117
24.2.2 Production ....................................................................................................... 118
24.2.3 Consumption ................................................................................................... 119
24.2.4 Coalfields and deposits ................................................................................... 119
24.2.5 Beneficiation .................................................................................................... 124
24.2.6 Challenges ...................................................................................................... 126
24.3
Oil ......................................................................................................................... 128
24.3.1 Imports ............................................................................................................ 128
24.3.2 Value addition ................................................................................................. 129
24.4
Gas ....................................................................................................................... 130
24.4.1 Shale Gas ....................................................................................................... 131
24.4.2 Value addition ................................................................................................. 131
25
South Sudan .................................................................................................. 133
25.1
Introduction ......................................................................................................... 133
25.2
Coal ...................................................................................................................... 133
25.3
Oil and gas ........................................................................................................... 133
25.3.2 Exploration and production ............................................................................. 134
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25.3.3 Exports ............................................................................................................ 138
25.3.4 Value addition ................................................................................................. 138
26
Sudan .............................................................................................................. 139
26.1
Introduction ......................................................................................................... 139
26.2
Coal ...................................................................................................................... 139
26.3
Oil ......................................................................................................................... 139
26.3.3 Exports ............................................................................................................ 140
26.3.4 Value addition ................................................................................................. 140
26.3.5 Consumption ................................................................................................... 141
27
Swaziland ....................................................................................................... 142
27.1
Coal ...................................................................................................................... 142
27.1.2 Exploration and Production ............................................................................. 142
27.2
28
Oil and Gas .......................................................................................................... 143
Tanzania ......................................................................................................... 144
28.1
Coal ...................................................................................................................... 144
28.1.2 Production ....................................................................................................... 144
28.1.3 Consumption ................................................................................................... 145
28.1.4 Coalfields ........................................................................................................ 145
28.1.5 Beneficiation .................................................................................................... 147
28.2
Oil ......................................................................................................................... 147
28.3
Gas ....................................................................................................................... 147
28.3.2 Production ....................................................................................................... 148
28.3.3 Challenges ...................................................................................................... 149
28.4
29
Electricity Generation ......................................................................................... 149
Uganda ........................................................................................................... 150
29.1
Coal ...................................................................................................................... 150
29.2
Oil ......................................................................................................................... 150
29.2.1 Production ....................................................................................................... 150
29.2.2 Legislation ....................................................................................................... 150
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29.2.3 Challenges ...................................................................................................... 151
29.3
30
Gas ....................................................................................................................... 151
Zambia ............................................................................................................ 152
30.1
Coal ...................................................................................................................... 152
30.1.3 Mines ............................................................................................................... 154
30.1.4 Consumption ................................................................................................... 155
30.1.5 Export .............................................................................................................. 155
30.2
Oil ......................................................................................................................... 155
30.3
Gas ....................................................................................................................... 155
31
Zimbabwe ....................................................................................................... 156
31.1
Coal ...................................................................................................................... 157
31.1.2 Deposits .......................................................................................................... 157
31.2
Oil ......................................................................................................................... 161
31.3
Coal Bed Methane ............................................................................................... 162
31.3.1 Tinker Mining ................................................................................................... 162
31.3.2 Zambezi Gas ................................................................................................... 162
Appendix I. Deposit size categories (kt)............................................................ 179
Appendix II. Listing of deposits ......................................................................... 180
Appendix III. Conversions .................................................................................. 183
List of Figures
Figure 1: Historical and possible future energy consumption .................................................. 2 Figure 2: Graphical Presentation of World Energy non-renewable reserves ........................... 3 Figure 3: Graphical Presentation of current non-renewable Energy Production ..................... 4 Figure 4: Graphical Presentation of World non-renewable resources ..................................... 4 Figure 5: Total Potential energy resources 2011 ..................................................................... 5 Figure 6: Types and uses of coal ............................................................................................. 7 Figure 7: World Coal Production 2011 ................................................................................... 10 Page xii
Figure 8: Top Steam coal importers 2011 ............................................................................. 11 Figure 9: Top Coking coal importers 2011 ............................................................................. 11 Figure 10: World Coal reserves ............................................................................................. 12 Figure 11: World hard Coal potential ..................................................................................... 12 Figure 12: African Coal reserve 2011 .................................................................................... 13 Figure 13: African Coal Total Resource 2011 ........................................................................ 14 Figure 14: Top Steam Coal Exporters 2011 .......................................................................... 15 Figure 15: Coal Production costs ........................................................................................... 16 Figure 16: Major products from Crude oil .............................................................................. 21 Figure 17: Cartoon of a crude oil distillation tower ................................................................. 22 Figure 18: Projected 2013 and 2014 Oil demand by region .................................................. 24 Figure 19: Forecast year on year change in demand for refinery products ........................... 25 Figure 20: African Oil Reserves ............................................................................................. 26 Figure 21: US weekly commercial crude oil stocks ............................................................... 27 Figure 22: Crude oil price February-July 2013 ...................................................................... 27 Figure 23: Natural gas potential (872 tcm) ............................................................................ 28 Figure 24: Natural gas use (US - 2012) ................................................................................. 29 Figure 25: Natural gas consumption 1965-2012 .................................................................... 30 Figure 26: Natural gas reserves (190 tcm) ............................................................................ 31 Figure 27: African Natural Gas Reserves .............................................................................. 32 Figure 28: Natural gas trade in 2012 ..................................................................................... 32 Figure 29: U.U. Gas costs ..................................................................................................... 33 Figure 30: Oil Concessions off the Angolan coast ................................................................. 35 Figure 31: Lianzi field ............................................................................................................. 37 Figure 32: Simplified cross section of the Atlantic between Brazil and Angola ..................... 37 Figure 33: Ultradeep discoveries ........................................................................................... 38 Figure 34: Angolan Oil exports by destination, 2011 ............................................................. 40 Figure 35: Morupule Coal mine ............................................................................................. 43 Figure 36: Serowe and Kweneng Projects ............................................................................ 44 Figure 37: Masama Project .................................................................................................... 45 Figure 38: Bolau and Mea Project Project ............................................................................. 46 Figure 39: Dukwe, Lechana and Mmamabula projects ......................................................... 48 Figure 40: Bas Congo Oilfield ................................................................................................ 55 Figure 41: Rift Valley Blocks .................................................................................................. 56 Figure 42: Block III locality Map, Albertine Graben ................................................................ 56 Figure 43: Northern Portion of Egypt Concession map ......................................................... 61 Page xiii
Figure 44: Egypt: Total Oil production and consumption 1990-2011 ..................................... 62 Figure 45: Egypt: Destination of Crude oil exports, 2011 ...................................................... 63 Figure 46: Egypt: Total Gas production and consumption 1990-2011 .................................. 65 Figure 47: Egypt: Natural Gas Vehicles sold 2004-2010 ....................................................... 66 Figure 48: Egypt: LNG Exports, 2010 .................................................................................... 66 Figure 49: Locality of the Sabisa – 1 well .............................................................................. 72 Figure 50: Kenyan Basins ...................................................................................................... 76 Figure 51: Schematic cross section at Ngamia 1 Well .......................................................... 76 Figure 52: Kenyan Oil exploration Blocks .............................................................................. 78 Figure 53: Oil product output at Mombasa refinery 2011 ...................................................... 80 Figure 54: Libyan Basins ....................................................................................................... 83 Figure 55: Foreign companies in Libya .................................................................................. 84 Figure 56: Libyan Oil production 2000-2012 .......................................................................... 85 Figure 57: Libyan Oil export destinations, 2010 .................................................................... 85 Figure 58: Possible impact of coal and oil on Mozambique economy ................................... 96 Figure 59: Ncondezi Project locality map ............................................................................ 100 Figure 60: Ncondezi electricity project ................................................................................. 102 Figure 61: Mozambique offshore Rovuma Basin discoveries .............................................. 105 Figure 62: Mozambique Rovuma Basin Area 1 ................................................................... 106 Figure 63: Mozambique Gas field map ................................................................................ 107 Figure 64: Mozambique natural gas production 2000-2011 ................................................ 108 Figure 65: Namibian oil and gas fields ................................................................................. 111 Figure 66: Schematic diagram of the lake Kivu graben ....................................................... 112 Figure 67: Seychelles: Areas A and B ................................................................................. 114 Figure 68: SA Primary Energy Supply ................................................................................. 115 Figure 69: South Africa: Planned Energy Scenario: 2030 ................................................... 116 Figure 70: Distribution of South African coalfields ............................................................... 120 Figure 71: Grootegeluk Mine and Waterberg Power Stations ............................................ 122 Figure 72: Estimated use of coal in South Africa ................................................................. 125 Figure 73: Estimated use of coal in South Africa ................................................................. 128 Figure 74: South African Crude oil imports, 2011. ............................................................... 129 Figure 75: SA natural gas production and consumption ...................................................... 130 Figure 76: Oil fields and pipelines of South Sudan and Sudan ........................................... 134 Figure 77: Potential Pipeline routes ..................................................................................... 135 Figure 78: Producing blocks ................................................................................................ 136 Figure 79: Map of South Sudan oil rights holders ................................................................ 137 Page xiv
Figure 80: Sudan and South Sudan: Historical Oil production by block .............................. 137 Figure 81: Sudan, pipelines refineries and 2010 exports .................................................... 140 Figure 82: Malome Colliery .................................................................................................. 143 Figure 83: Tanzania coal production ................................................................................... 145 Figure 84: Tanzania Natural gas localities ........................................................................... 149 Figure 85: Uganda oil and gas localities .............................................................................. 151 Figure 86: Zambia: Karoo Basins ........................................................................................ 152 Figure 87: Zambia: Coal Production .................................................................................... 153 Figure 88: Cross Section through the Zimbabwe Mid Zambesi Basin ................................. 156 Figure 89: Hwange Main seam quality variation .................................................................. 158 Figure 90: Hwange Raw Coal production 1980-2011 .......................................................... 159 Figure 91: Makomo Opencast mine ..................................................................................... 160 List of Tables
Table 1: World Reserves and resources of non-renewable fuels ............................................ 3 Table 2: Angolan new oil projects .......................................................................................... 39 Table 3: DRC Coal Quality .................................................................................................... 53 Table 4: Malawi reserves and resources 1999 ...................................................................... 91 Table 5: Tete coal resources ................................................................................................. 98 Table 6: Tete production estimates ..................................................................................... 103 Table 7: Remaining recoverable “reserves” ......................................................................... 118 Table 8: Eskom’s current and planned coal fired power stations ........................................ 126 Table 9: Estimated commercial reserves as at 31 December 2006 .................................... 135 Table 10: Coal resources of Tanzania ................................................................................. 144 Table 11: Zimbabwe coal resources .................................................................................... 157 Page xv
1 INTRODUCTION
Coal, oil and gas are not minerals per se but rather mineraloids (“mineral-like substances”)
and therefore usually dealt with separately from the other mineral commodities, as they are
in this report. In the overall project however they are vital to the opportunity for industrialising
Africa since they form a very close relationship with the direct opportunities for value addition
of the mineral commodities. So, in the final report the relationship will be more evident as
value chains are dealt with.
There is much argument worldwide about how long our energy resources based on nonrenewable mineral commodities will last. Let it be clear that all mineral commodities are
finite, and this is true of the fossil fuels, uranium and thorium, as well as the metals and
minerals required to gather the so-called “green energy” available from the seemingly infinite
power of wind, waves and sun. Besides regulating the population of the earth there is no
long term solution, and even in the shorter term it will take many years for the world to
develop and put into place the innovative changes that are required to move away from its
current fossil fuel dependence to a more varied basket of fuel resources (see Figure 1).
The total amount of non-renewable energy resources has most recently been estimated by
Andruleit and others (2012), and a summary of their findings is tabulated in Table 1. They
show that the total energy available from mineral commodities is 571,549 EJ. Note that there
are three areas that is it possible that this number may be an underestimation. They are
aquifer gas and gas hydrates, because it is unlikely that they can be accessed and produced
even in the long term, as well as thorium, because the resource information and technology
is not fully in place. However, the report by Andruleit and others (2012) does give the best
available information on the energy resource from non-renewables that is available. It is
clear from Table 1 and from Figure 2 and Figure 4 that coal is the real store of energy into
the near to medium term future, notwithstanding all the hype about other forms of fossil fuels
and renewables.
Page 1
5 Growth Poles Coal, Oil & Gas
Figure 1: Historical and possible future energy consumption
Source: Andruleit et al (2012)
A comparison of the data for energy usage versus non-renewable reserves and resources
shows that the available energy reserve is about 80 times the current usage whilst the
resources on top of that represents more than 1,000 times the current usage. Africa, which
has some 5.6% of the reserve and 1.3% of the resource according to Andruleit and others
(2012), is currently producing some 7.4% of the annual production, although it is consuming
only 3.1% of the production.
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Table 1: World Reserves and resources of non-renewable fuels
Fuel
Conventional Crude oil
Conventional natural gas
Oil Sands
Extra Heavy oil
Tight/shale oil
Oil Shale
Tight Gas
Shale Gas
Coalbed Methane
Aquifer Gas
Gas Hydrates
Hard Coal
Lignite
UraniumA
ThoriumD
Total
Units
Gt
Tcm
Gt
Gt
Gt
Gt
Tcm
Tcm
Tcm
Tcm
Tcm
Gtce
Gtce
Mt
Mt
Reserves
168
191
27
21
<0.5
EJ
7,014
7,240
1,120
886
11
E2.8
E105
1.8
70
638
111
B2.1
18,692
3,260
B1,061
39,459
Resources F
159
307
63
61
87
97
63
157
50
24
184
14,486
1,684
C13
5.2
EJ
6,637
11,671
2,613
2,541
3,636
4,068
2,397
5,984
1,886
912
6,992
424,553
49,340
C6,254
2,606
532,090
Source: Andruleit et al, 2012.
Notes:
A: 1 t U = 14 000 – 23 000 tce, lower value used or 1 t U = 0.5 x 1015 J
B: RAR recoverable up to $80/kg U
C: Total RAR exploitable $80-260/kg U, and inferred and undiscovered resources <$260/kg U
D: 1 t Thorium assumed to have the same tce-value as for 1 t U
E: Only US as at 2010
F: Excluding reserves
Figure 2: Graphical Presentation of World Energy non-renewable reserves
Source: Andruleit et al, 2012
Page 3
Figure 3: Graphical Presentation of current non-renewable Energy Production
Figure 4: Graphical Presentation of World non-renewable resources
It is clear from Figure 5 that Africa has produced a considerable amount of its total
“allocation” of energy resources in the past, and since it has a small endowment relative to
its land size and population, special care should be taken to ensure that any non-renewable
energy resources are used to promote local development and industrialisation.
Page 4
Figure 5: Total Potential energy resources 2011
Source: Andruleit et al. 2012
Page 5
2 COAL
2.1 Introduction
The formational history of coal is critical to the current condition of that coal. Hence the coal
deposits in southern and eastern Africa are of an entirely different nature for example to
those of Europe and America. In southern Africa there are no workable deposits of brown
coal (Plumstead, 1957). The major coal deposits of Southern Africa are of semi-bituminous
or bituminous coal and are carboniferous to Permian in age and occur within the Ecca Group
(or equivalent). Coal seams are also encountered in the Beaufort Group and in the Molteno
Formation.
2.1.1 Power energy deficit
A serious power deficit exists and could become worse in South Africa with a potential
capacity shortfall of up to 32,000 MW by 2030. Eskom struggles to meet current demand
and end users are now seeking alternative suppliers outside of Eskom.
In SADC, Namibia and Zimbabwe remain in power deficit and both are likely to remain net
importers of power until at least 2019. Zambia may run short of power as its mining sector
grows. A power deficit of up to 4,000 MW by 2030 is seen as likely (Mining Insight, 2013).
Eskom’s average tariff adjustments have meant a 150% price increase in the last 4 years
and there is a 100% price increase planned over the coming 5 years.
Across the Tripartite the deficit of electrical energy is one of the greatest brakes on the quick
development required to allow it to catch up with the more developed nations of the world.
Much is planned to eliminate the problem but there are many hurdles along the way to
making the vision real – one of the first and most serious is the ability to fund the urgently
needed development.
2.2 Fundamental concepts
2.2.1 Formation and quality
Coal is a rock that consists of macerals, minerals and water. It is formed primarily from dead
plant material that is processed over time through various stages from peat which is buried
and with heat and pressure forms into brown coal, bituminous coal and eventually given the
correct conditions to anthracite. During this process the material looses carbon dioxide and
methane and increases in carbon percentage. This carbon percentage is only about 60% in
peat but more than 90% in bituminous coal. At the same time the calorific value of the
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material increases from around 15 MJ/kg in peat to 35 MJ/kg or more in bituminous coal. As
the material moves from peat to anthracite it is said that its “rank” increases. As coal
increases in rank, moisture and volatiles decrease and fixed carbon increases. As a result,
coal is one of the most complex mineral commodities since it exists in a wide range of forms
and qualities each with its own optimum use profile. A simplified diagram to illustrate this is
given in Figure 6.
Figure 6: Types and uses of coal
Moisture content
Carbon (energy) content
Low Rank Coals
47%
Lignite 17%
Hard Coal 53%
Sub-bituminous
30%
Bituminous
52%
Thermal
Steam coal
Anthracite
1%
Metallurgical
Coking coal
Domestic/
industrial,
smokeless coal
Power
generation
Power Generation,
Cement Manufacture,
Industrial uses
Manufacture of
iron and steel
Power Generation,
Cement Manufacture,
Industrial uses
Modified from World Coal
Institute, 2005
Source: World Coal Institute, 2005
2.2.2 Mining
Coal layers are called “seams” and they may vary from a few millimetres to more than 10 m
in thickness. In general they have a tabular or lenticular shape and may continue over many
kilometres.
Depending on the overburden to coal-seam thickness coal may be mined as opencast mines
or underground. When mined underground it is usually mined either by the longwall mining
method (where mined out areas are allowed to undergo controlled collapse) or by room and
pillar mining, where the pillars provide support to the mined out areas.
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Where opencast mines reach maximum depth or possibly where coal is exposed on a steep
slope, the highwall or auguring methodology may be used to excavate slots of coal from the
highwall.
2.2.2.1 Alternative technologies - Coal Bed M ethane
Methane is adsorbed onto the internal free surfaces of coal and held within the coal cleats
(fractures). Theoretically coal can hold as much as 24 m3 of methane per tonne (in saturated
anthracitic coal). The methane in itself is a resource that may be tapped.
Methane in unworked seams is known as Coal Bed Methane (CBM) and it can be recovered
by means of wells to enter the seam and then using water pressure to fracture the coal. The
bed is then pumped to lower the pressure and release the methane.
2.2.3 Beneficiation
Once mined, coal usually requires some crushing and processing before sale. Usually
referred to simply as “washing”, this involves a series of steps to separate out the coal from
rock fragments and to size and sort the coal for its final usage. This washing process will
depend very much on both the quality of the deposit and the end use of the coal.
Coal is categorised by its rank, chemistry and physical properties as “steam coal” or “thermal
coal” or as “coking coal” or “metallurgical coal”. “Steam coal” or “thermal coal” refer to coal
which is to be used to burn in power stations or for other industrial or domestic use. In the
case of steam coal the most important criteria is the net calorific value which determines the
amount of heat it will produce on combustion. In many cases a power plant may be built to
use a particular grade of coal available locally. “Metallurgical” or “coking coal” is used
primarily as a reductant in the metallurgical industry.
The higher the moisture and ash (mineral constituents) in the coal the lower will be the fixed
carbon content (and calorific value). To add to this high mineral content can lead to slagging
problems in boilers. Coal generally has some organic sulphur and pyrite content which can
lead to environmental problems when it is burned and the sulphur is released into the
atmosphere. Nitrogen content is also a problem for the same reason. Chlorine content may
be a problem in steam coals since it can cause corrosion in boilers. Phosphorous is a
problem in coking coal since it is detrimental to the steel making process.
Coke is manufactured from coking coal. Coking coal should have low sulphur and
phosphorous. Coking coal liquefies when heated in the absence of oxygen to give off its
volatiles and to re-solidify as a hard, porous, permeable high carbon material called coke.
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The volatiles given off may be very valuable and include gas, tar and several other chemical
compounds.
Coal may be converted into liquid fuels by one of two processes. Valuable by-products of the
conversion include various chemical compounds, waxes and lubricants. The methods used
are (BGS, 2010):
 Direct liquefaction: The coal is dissolved in solvents at high temperature and pressure.
The liquid fuel produced by this method requires further refining.
 Indirect liquefaction: the goal is gasified and then condensed over a catalyst (the
Fisher-Tropsh process). The Sasol process is the only proven commercial indirect
liquefaction process in the world at present
2.3 Market
Coal is the second largest supplier of primary energy in the world at 32.8% of total world
energy supply in 2011 (30.3 % of consumption). In the 2011 year coal also generated 42%
of the world electricity (Andruleit et al, 2012, Worldcoal, 2013). Certain coal qualities are
scarce and therefore very much in demand and one of these is coking coal.
2.3.1 Uses
The uses of coal are many but they can be summarised into three broad areas. Firstly the
majority of the world’s coal is used to provide heat either to run steam turbines for electricity
production or for industrial and domestic heating. A second major use of coal is as a
reductant to reduce oxygen rich ores, whilst the third use is for liquefaction to provide gases
and liquids to be used as fuel. This last is also the source of a major chemicals industry built
on by-products of the process. Each of these uses will have specific qualities of coal that will
be preferred for the process.
Coal based power stations provide 42% of world electricity. In 2008, China produced 93% of
its electricity from coal, and South Africa produced 79% of its electricity from coal (WCA,
2012). Coal is also a fundamental resource for the production of the steel and concrete on
which all modern infrastructure is reliant.
2.3.2 Production
Australasia is by far the largest producer of coal at this stage (see Figure 7) producing 71%
of the coal in 2011. Of this, China produced 3,383.7 Mt and it was followed by India with
539.9 Mt, Australia with 345.2 Mt and Indonesia with 324.9 Mt. In Africa, only South Africa
was a major producer in 2011 with 253.1 Mt of production (Andruleit et al 2012).
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Figure 7: World Coal Production 2011
2.3.3 Demand
China, still a net exporter of coal in in 2008, became the world’s top coal importer in 2011.
China is now by far the world’s largest producer and consumer of coal, and accounts for
more than 45% of both (IEA, 2012). China’s coal imports rose to 289 Mt in 2012 –
accounting for some 23% of global imports. Major importers of coal are shown in Figure 8
and Figure 9. India has the fastest growing coal demand and several commentators
including IEA (2012) believe that India will be the second largest coal consumer by 2017 and
probably the largest seaborne coal importer by 2016. Coal demand grew by 4.3% from 7,080
Mt in 2010 to 7,384 Mt in 2011 (IEA, 2012).
Overall global demand is expected to grow at a rate of 2-4% per annum with new supply
expected to come chiefly from Australia and Mozambique. Chopra and others (2011)
reported in January that most steel producers had an approximate 40-60 day coking coal
inventory. Due to the general tightness in the market, but especially due to the Australian
floods, coking coal moved from about $225 per tonne at the end of December 2010 to $260/t
by mid-January 2011 (Chopra et al. 2011). This can be compared to the benchmark price of
Page 10
$115-125 agreed to between BHP Billiton and Nippon Steel in March of 2009. The strong
insurgence of the US into the export market has since dropped prices considerably.
Figure 8: Top Steam coal importers 2011
Source: Worldcoal 2013
Figure 9: Top Coking coal importers 2011
Page 11
2.3.4 Supply
World hard coal reserves at the end of 2011 totalled 754 bt. Africa has some 36 bt of coal
reserves (see Figure 10, Figure 11) and whilst this presents a good total in comparison to
local coal usage it still represents a relatively small percentage of global reserves in relation
to relative population. The three largest hard coal producers in 2011 were China (51 % 3,384 Mt), the United States (13.9 %) and India (8.1 %) (Andruleit et al 2012).
Figure 10: World Coal reserves
Figure 11: World hard Coal potential
Page 12
South Africa has by far the largest coal reserves in Africa with more than 93% of the total
(see Figure 12). However as the resources in the rest of Africa are brought to reserve status,
this is expected to show appreciable change (see Figure 13). Also South Africa now has little
of the very important coking coal which is present in especially Mozambique and Zimbabwe.
It is of particular importance when dealing with Africa that in some cases the figures given in
international reports differ greatly from local documents. A case in point is the total coal
resource. In Figure 13 the total coal resource of Africa is given as 117.8 bt of which
Botswana with 17% contributes 21.2 bt. However, Grynberg (2012) indicates a resource in
the order of 212 bt for Botswana (albeit mostly in the hypothetical and speculative category),
only time and further research will clarify the reasonable resource that can be expected to be
mined in the future.
Figure 12: African Coal reserve 2011
The strong re-entry of the US into the steam coal export market over the past two years
removed the shortfall of coal on the global market. For this reason, despite a 12% growth in
imports in 2012, the global market has rapidly moved from tightness to oversupply (CornotGandolphe, 2013).
Page 13
Figure 13: African Coal Total Resource 2011
Source: Andruleit et al, 2012.
2.3.5 Trade
The major coal exports in 2011 were from Indonesia, Australia, Russia, USA, Colombia and
South Africa (see Figure 14) which together account for 84% of exports, whilst the major
importers were China, Japan, South Korea and India. Most of the world trade was in hard
coal of which some two thirds was steam coal and the balance coking coal.
Because the quality of coal can be so variable the price is complex and will depend on the
type of coal, its calorific value and the ash and impurities in the coal, as well as transport
costs.
In 2011 China supplanted Japan as the biggest importer of coal whilst Indonesia moved
ahead of Australia as the largest exporter. In the 2011 year both Japan (earthquake and
tsunami) and Australia (Queensland floods) experienced major natural disasters that
hampered their trade.
Despite strong growth, total international trade in coal represents a small share of coal
production. Only 17% of hard coal production is traded internationally. The global coal
market remains a thin market dominated by few players. The steam coal market has seen
major changes in the past few years especially where South Africa is concerned. In 2007
South Africa exported 80% of its coal to Europe, but now more than 50% is exported to Asia
(mainly India and China).
Page 14
Figure 14: Top Steam Coal Exporters 2011
2.3.6 Price
Northwest European spot prices for steam coal rose by 33.3% to $142.81/tce in 2011,
largely influenced by the strong increase in coal imported by China and India. Prices have
dropped considerably since then due to an oversupply of coal on the world market for both
steam coal as well as coking coal (Andruleit et al 2012). As a consequence of the natural
gas abundance being experienced in the US, large quantities of US coal were exported to
the European market. This led to an oversupply in Europe, which caused coal prices to
plummet to $85/t in May 2012. The low coal prices resulted in a significant gas-to-coal switch
in Europe (IEA, 2012).
2.3.7 Cost of production
The cost of production depends on many factors and in coal mining it depends on the quality
(CV, chemistry, etc.), aspect (dip, structural issues) as well as roof and floor conditions and
thickness of the coal seam, the size of the deposit, stripping ratio, distance to port and
access to and quality of infrastructure, local costs of labour, taxation etc. Meister (undated)
gives a breakdown which shows the relative values of these costs in various localities
around the world (see Figure 15).
Page 15
Figure 15: Coal Production costs
Source: Meister, undated
2.3.8 Value added products and substitution
Electricity is the major value added product from coal. Other products include coke, liquid
fuels, and a vast range of chemical products.
Coal can be indirectly substituted for to some extent by other hydrocarbons or by biomass in
many of its uses. In the production of electricity it can also be indirectly substituted for by
uranium and thorium (by building nuclear power stations instead of thermal power stations),
or by renewable means of generating electricity.
Page 16
3 OIL
3.1 Introduction
If one looks at the position of the earth before oil production we see that the world has
already used some 167 bt of oil and that about 235.8 bt remain today as reserves meaning
that 41% of the total has now been used. However reserves and resources are still expected
to rise due to new discovery, particularly in Africa, as well as the potential of “nonconventional” sources (Andruleit et al, 2012).
Recent oil finds in Kenya and Uganda as well as gas finds offshore of Tanzania and
Mozambique, indicates the huge potential that East Africa has for oil and gas production in
the short to medium term.
3.2 Fundamental concepts
3.2.1 Types of crude oil
Crude oil is a mixture of a range of hydrocarbons which exists as a liquid. Petroleum is
sometimes used as an equivalent to crude oil, but is sometimes seen in a broader light
inclusive of crude oil, natural gas, solid hydrocarbon mixtures like tar and bitumen.
Petroleum may contain impurities such as water, sulphur compounds, nitrogen, oxygen,
carbon dioxide and trace elements.
Crude oil quality has two major quality parameters, namely its density (light or heavy) and
sulphur content (sweet or sour).
Density is classified by the American Petroleum Institute (API). The API gravity is an inverse
measure which is defined based on oil density at a temperature of 15.6ºC. The formula used
is [141.5 ÷ relative density of the crude (at 15.5°C) - 131.5] (Businessdictionary, 2013).
Light crude oil generally has an API gravity of 38° (some references use 30°) or more, whilst
heavy crude an API gravity of 22° or less. Crude oil with an API gravity of 22-38° (22-30°)
degrees is generally referred as medium crude (Nesteoil, 2013). Asphalt has an API of
around 8°
If crude oil has a sulphur content of less than 0.5% it is classified as ‘sweet’, while sour
crude has a sulphur content of greater than 0.5%.
The quality of crude oil influences the level of processing and conversion necessary to
achieve an optimal products mix. Thus light, sweet crude oil is more expensive than heavier,
sour crude because it requires less processing (Nesteoil, 2013).
Page 17
3.2.1.1 Brent Blend
Brent Blend is a light, sweet North Sea crude oil with an API gravity of 35.5-38 and a sulphur
content of approximately 0.4%. Brent Blend is used for pricing around two-thirds of the crude
traded internationally (Nesteoil, 2013).
3.2.1.2 Russian Export Blend
Russian Export Blend, the Russian benchmark crude, is a mixture of several crude grades
used domestically or for export. Russian Export Blend is a medium, sour crude oil with an
API gravity of about 32 and a sulphur content of approximately 1.2%. Its spot price is
reported at Augusta, Italy, and Rotterdam, the Netherlands, which act as the two primary
delivery points (Nesteoil, 2013).
3.2.1.3 W est Texas Interm ediate
West Texas Intermediate, is the US benchmark crude oil. It is a light, sweet crude oil with an
API gravity of about 40 and a sulphur content of approximately 0.3%. The spot price of West
Texas Intermediate is reported at Cushing, Oklahoma (Nesteoil, 2013).
3.2.2 South Atlantic Geology
The South Atlantic Ocean evolved as a rupture of the pre-existing landmass consisting of
cratons and late Proterozoic fold belts over a period of time (Mohriak et al, 2008). Rifting was
initiated in the south during the Jurassic and progressed northwards. The São Francisco–
Congo craton resisted rifting and, as a result, developed narrow basins (grabens), whilst
areas influenced by the weaker fold belts developed wide basins. Within these early basins
thick sequences of lacustrine sediments would have formed with clastic and biogenic
material being flushed into the lakes. This sequence of events is likely to lead to excellent
hydrocarbon source rocks.
Mello and others, (2012) point out that the lacustrine source rocks which appear to be
responsible for 90% of the oil produced in Brazil and Angola were deposited 130-115 My
ago when depositional conditions across the south Atlantic were similar. As time went on
there appears to have been a period of “sag” between the drifting continents allowing the
incursion of shallow seawater, and in a series of repeated cycles of marine incursion and
dessication thick evaporate (salt) accumulations were built up, sealing the carbon bearing
materials in the sediments below.
Unternehr and others 2010, point out that the discovery of giant hydrocarbon reservoirs in
the southern Atlantic deep water Brazilian rifted margin, together with the high quality
Page 18
reflection and refraction seismic surveys now available have reopened the discussion of the
formational history of these basins.
The new datasets allow clearer description of the pre-salt structures. It appears that deepwater rifted margins are quite different from predictions of classical models. New data
suggest the existence of a ‘sag basin’ lying on hyper-extended crust with little indication for
brittle high-angle faulting, and an area of transition between continental and oceanic crust
which shows characteristics different to continental or oceanic crust. These observations call
to question the classical concepts explaining seafloor spreading (Unternehr et al 2010).
Worldwide, the relationship between oil and salt (evaporite) deposits is important. The salt
deposits may act as a seal or may provide tectonic control for the formation of hydrocarbon
traps (Mohriak et al, 2012). The big hydrocarbon discoveries between 1999 and 2008 (with
reserves > 3 bls of oil equivalent, were all located either in the Middle East/Asia or along the
Brazilian continental margin.
Early Cretaceous evaporates, related to the opening and closing of oceans formed along the
Brazilian and West African margins. There is, in general, a close relationship between the
presence of evaporates and hydrocarbons in the stratigraphic sequence. So much so, that
although salt accumulations are not required for hydrocarbon deposits they are certainly
seen as a favourable element (Mohriak et al, 2012).
Nonetheless, as can be seen from exploratory drilling in the Gulf of Mexico most holes
stopped when penetrating the shallower allochthonous salt layer, since there was a
pessimistic attitude in regard to finding siliciclastic or carbonate reservoirs below the salt
layer. However some researchers believed that there was merit in looking at the sub-salt
sediment and, in 1993, the first commercial discovery (Mahogany field), based on this idea,
was made known (Mohriak et al, 2012).
The search for oil fields associated with autochthonous salt in the south Atlantic continental
margins has been successful, with oil fields related to post-salt reservoirs (the Campos
Basin in Brazil and the Cabinda Basin in Angola) or to pre-salt reservoirs (in Gabon and in
the Santos Basin) available to prove this. There is considerable evidence that oil will be
discovered in subsalt reservoirs in the deeper areas along the continental margin, but many
prospective areas may remain undrilled for some time to come due to technological and
economic risks (Mohriak et al, 2012).
However the very significant finds in Brazilian waters where deepwater pre-salt carbonate
reservoirs are sealed by massive stratified evaporites may be an analogue for other basins
Page 19
with massive salt sealing pre-salt rocks such as on the west coast of Africa (Mohriak et al,
2012).
3.2.3 Relationship of geological history to Crude oil quality
Crude oil and gas are the result of the decomposition of ancient plants and animals. Organic
material that accumulated and was buried was the source of the oil and gas that we are now
using. When this material was buried it gradually changes and “matures” as it was subjected
to higher pressures and temperatures in the sediment, which became the “source rock”. In
time, through a series of chemical processes, it may have turned into petroleum.
Due to the geothermal gradient, temperature increases downwards in the earth’s crust. In
relatively shallow source rocks, where temperatures ranged from about 60 - 80°C the
organic matter was converted into heavy oil. Where it was buried to a depth in which the
source rocks experienced temperatures of about 80°C - 175°C, these heavier, long-chain
organic molecules tended to break up into shorter molecules and form medium and light oil.
Where burial temperatures exceeded 175°C, further reaction caused the molecules to
become smaller and lighter, and as the source rock temperature approached 315°C, the
hydrocarbons where entirely converted to dry gas (methane).
3.2.4 Organisation of Petroleum Producing Countries (OPEC
The Organization of the Petroleum Exporting Countries (OPEC) was founded in Baghdad,
Iraq, with the signing of an agreement in September 1960 by five countries, the Islamic
Republic of Iran, Iraq, Kuwait, Saudi Arabia and Venezuela. Other countries that joined later
are Qatar (1961), Indonesia (1962), Libya (1962), the United Arab Emirates (1967), Algeria
(1969), Nigeria (1971), Ecuador (1973), Gabon (1975) and Angola (2007). Gabon terminated
its membership in 1995 and Indonesia has suspended its membership from January 2009.
OPEC’s mission is to “coordinate and unify the petroleum policies of its member countries
and ensure the stabilization of oil markets in order to secure an efficient, economic and
regular supply of petroleum to consumers, a steady income to producers and a fair return on
capital for those investing in the petroleum industry.” (OPEC, 2013)
3.3 Market
Oil remains the most important fuel in the world with its use representing 34% of the world
primary energy consumption (Andruleit et al, 2012).
Page 20
3.3.1 Uses
Besides the obvious uses of oil in the production of petroleum, diesel jet fuel (about 90% of
all transportation fuels are based on oil) and industrial lubricants, the products from oil and
the petrochemical industry are vast and varied and touch every part of the modern life. Uses
include plastics, deodorants, shampoos, synthetic fibres used in clothing, various cosmetics,
and pharmaceuticals such as aspirin. Oil, gas and coal are an important starting point in the
production of nitrogen based fertilisers.
About 45% of crude oil is manufactured into petrol (gasoline) and about 40% into diesel,
paraffin (kerosene) and jet fuels (see Figure 16). Only about 5% of crude oil is used in the
production of the wide range of plastics, elastomers, coatings and fibres that are produced
as value added products.
Figure 16: Major products from Crude oil
Source: Various
3.3.2 Production
Once an oil well is in production the oil is pumped to the surface and transported to a
gathering centre for removal of gross impurities such as water, sand, salt and gas. From
here it is sent to a refinery where essentially three basic steps are undertaken. However, it is
important to understand that although there will be some space to manoeuvre, refineries will
generally be set up with a specific input in mind as well as a specific range of products, and
as a result the range of processes at refineries will differ somewhat.
Page 21
3.3.2.1 Separation
Crude oil is separated into its component parts by heating and fractional distillation (in
principle the longer the carbon chain the higher the temperature required to boil the
hydrocarbon).
Liquid Petroleum Gas (LPG) being the lightest fraction is the first to distil off and is collected
towards the top of the distillation tower. Next would be the basic components of petrol
(gasoline), followed by medium fractions which include paraffin (kerosene), naptha and the
basic components of jet fuels and diesel; lower in the distillation tower heating oil then
lubricating oils are tapped, whilst the residual (heavy) oils and bitumen (asphalt) remain at
the bottom of the distillation tower (see Figure 17).
Because the demand for petrol outstrips the availability of petrol from the distillation process
(only about 40%), some of the heavier fractions are sent to a cracking unit for conversion to
petrol. Naptha which is extracted from the light and middle distillate groupings is used chiefly
as a feedstock for the petrochemical industry. Similarly, dependent on market demand
lighter fractions may be chemically reformed to petrol.
Heavy oils are vacuum distilled to produce a final range of light and medium products and
bitumen.
Figure 17: Cartoon of a crude oil distillation tower
Source: http://www.elmhurst.edu/
Page 22
3.3.2.2 Conversion
Since petrol is very much in demand various hydrocarbons must be converted to produce
more petrol. This is done by different processes in which longer or shorter chain
hydrocarbons are converted into hydrocarbons of a suitable carbon chain length.
3.3.2.3 Cracking
“Gas oil”, a distillate stream heavier than diesel but lighter than heavy fuel oil, is broken
down into lighter hydrocarbons (particularly petrol) using catalysts, high temperature and/or
pressure. The process is not totally controllable and a range of hydrocarbons is produced.
Those lighter than petrol will be fed into the catalytic reforming process.
Cracking is
accomplished by heating the oil to enhance decomposition into octane or by introducing a
catalyst such as silica or alumina (to accomplish the cracking at a lower temperature).
Dependent on the conditions and catalysts used in the cracking process there is a good
degree of control (though not absolute) that can be exercised over the product. For example
where the product is to be used as petrol it is desirable to ensure that the cracked molecules
are largely saturated hydrocarbons. Conversely if the end point is to provide inputs into the
manufacturing industry (monomers and drugs) it is important to produce unsaturated
hydrocarbons.
3.3.2.4 Catalytic Reform ing
Catalytic reforming is a process where short chain hydrocarbons (naphtha) are reformed into
aromatic hydrocarbons with a high percentage of octane. In the process hydrogen atoms are
released and significant amounts of byproduct hydrogen gas is produced. Other byproducts
include small amounts of methane, ethane, propane, and butane.
3.3.2.5 Treatm ent
“Cracking” produces oil of various carbon chain lengths, and like crude oil, this can be
separated and blended to produce oils with specific properties. Certain oil component’s (for
example heptane) handle compression poorly and ignite spontaneously under a little
compression. Octane on the other hand deals very well with compression. The higher the
octane rating of petrol the more compression it can take before self-igniting (93 octane
contains 93% octane). It was discovered about a 100 years ago (during World War I) that
adding tetraethyl lead to petrol and makes it react as if it has a higher percentage of octane.
Lead is toxic and has been banned in most fuels around the world, although some jet fuel
still uses lead.
Page 23
Sulphur, nitrogen and aromatics are removed (reduced) from refinery products with a
process known as hydrotreating. The process exposes oil to hydrogen in the presence of a
catalyst, generally at high temperature and pressure. Hydrotreating essentially “cleans” the
fuel and also enhances the cetane number (a measure of the fuels ignition delay – the
higher the cetane number the shorter the ignition delay period), density and smoke point of
diesel fuel. The improvement of diesel engines has resulted in a shift toward diesel and as a
result hydrotreating has become more important in recent years.
There is a wide range of treatments to provide for the product and environmental demands
on the industry.
3.3.3 Demand
The current world demand for oil is about 89.7 million barrels per day (Mblpd). World oil
demand growth for 2013 now stands at around 0.8 Mblpd. In 2014, world oil demand is
projected to grow at a higher rate of 1.0 Mblpd to 90.7 Mblpd with an increase in demand in
most areas outside of Europe and Asia Pacific (see Figure 18). OECD consumption is seen
continuing to decline but at a lower rate, contracting by 0.2 Mblpd (OPEC, 2013a).
The demand for petroleum products differs quite markedly from one product to the next and
equally the change in demand differs across products. It can be seen in Figure 19, that the
demand for motor vehicle fuels and light heating oils (petrol - gas/diesel) is the highest. It is
also interesting to see the minimal growth expected for paraffin and jet fuels.
Figure 18: Projected 2013 and 2014 Oil demand by region
Source: OPEC, 2013a
Page 24
Figure 19: Forecast year on year change in demand for refinery products
Source: OPEC, 2013a
3.3.4 Supply
In 2012, 86.152 Mbls of oil was produced per day on average. Of this 37.405 Mblpd was
from OPEC countries, 35.088 Mblpd from non OPEC countries (excluding the former Soviet
Union), and 13.659 Mblpd from the former Soviet Union.
Non-OPEC oil supply is expected to increase by 1.0 Mblpd in 2013, supported by anticipated
growth from OECD countries, the Americas, the former Soviet Union and China. In 2014 the
non–OPEC supply is expected to grow by a further 1.2 Mblpd with the US, Canada, Brazil,
South Sudan and Sudan, Kazakhstan, and Australia increasing supply, while Norway, Syria,
Mexico, and the UK will probably have large declines (OPEC, 2013a).
Africa has a considerable (and growing) oil reserve and as time goes on is likely to make up
a greater portion of overall supply (see Figure 20). At the current reserve level Africa could
fulfil the entire world demand for about 3.76 years. Africa’s oil production is expected to
average 2.40 Mblpd in 2013 (OPEC, 2013a) and will probably exceed 2.5 Mblpd in 2014.
3.3.5 R/P Ratio
The R/P Ratio used in the oil industry (and usable across the extractive industries) is simply
the ratio of reserves to current production and gives the number of years of production (at
the current rate of extraction) that the current reserve will source – essentially the number of
years of resource left.
Page 25
Figure 20: African Oil Reserves
3.3.6 Trade
About 60% of oil produced is traded internationally (Cornot-Gandolphe, 2013). In the last few
months the imports of Crude oil to the US have increased, whilst crude oil exports have
decreased. This may be an indication than local demand has shifted and that the US
economy is improving. At the same time US crude oil stocks which have been very high in
the first six months of the year have shown a sharp dip in week 25.
3.3.7 Price
The OPEC “Reference Basket” (a benchmark for crude oil prices based on a weighted
average of prices for petroleum blends produced by OPEC countries), averaged $101.03/bl
in June 2013 (OPEC, 2013a). Although this price is up on the previous month, the average
price for the first 6 months of the year is about 6% down on the previous period. Around the
world economic growth expectations have been revised downward for 2013, but much better
growth is expected in 2014, so whilst the price may remain under pressure this year, the
outlook for 2014 looks better (see Figure 22).
In 2013 naphtha-rich oil grades such as Saharan Blend continued to suffer from the weak
European naphtha market, despite improving petrol and distillate cracks (OPEC, 2013a).
Page 26
Figure 21: US weekly commercial crude oil stocks
Source: OPEC, 2013a
Figure 22: Crude oil price February-July 2013
Source: OPEC, 2013a
Page 27
4 GAS
4.1 Introduction
Natural gas was the third largest non-renewable fuel in use in 2011, and because of its
ready availability and relatively lower emissions, it is likely to have a strong growth potential.
Natural gas reserves were estimated at 195 tcm at the end of 2011. Consumption was
3.3 tcm with the US being the major producer with 630 bcm produced of which about 30%
was from shale gas (Andruleit et al, 2012).
Figure 23: Natural gas potential (872 tcm)
Source: Andruleit, 2012
4.2 Market
4.2.1 Uses
Like oil the uses of gas are many and varied, although the major uses are for heating, the
manufacture of electricity and increasingly as a fuel for vehicles. Because of its clean
burning nature natural gas has become an important fuel for the generation of electricity.
Industrial uses of gas include the production of plastics, fertiliser, paint, antifreeze, dyes,
medicines and explosives.
Page 28
For many years most iron has been processed in blast furnaces using coke as a reductant.
However the relatively low prices of gas which are expected to continue for some years into
the future may mean that the production of directly reduced iron using gas may become the
method of choice to deal with iron ore into the future.
Figure 24: Natural gas use (US - 2012)
Source: Insidenergy.com
4.2.2 Production
As in the case of a crude oil, refinery plant configuration will depend somewhat on the feed
as well as the final product mix required. In general the raw gas will first require removal of
water and condensates (which will go to a refinery). The gas then needs to be treated for
the removal of potentially acid forming gases such as H2S, SO2 and CO2. The gas must then
be stripped of any further H2O, as well as nitrogen and mercury (using molecular sieves).
Any further natural gas liquids must be recovered before the gas is fractionated for final
usage into its component parts.
4.2.3 Demand
There is considerable uncertainty at the moment about the future demand for liquefied
natural gas (LNG). Some analysts indicate that there will be an oversupply by 2020 whilst
others indicate an undersupply by 2025. In the authors’ view it is likely that these analyses
have not taken full consideration of African developments, and that the best use of much of
the natural gas produced in Africa may be to use it as an input into African industrial
development – thus circumventing to some extent global demand issues for the gas itself
whilst improving the general economy of the African countries by diversifying production
Page 29
based on the natural resource. The Mozambican gas draft master plan already identifies
potential domestic industries that could use natural gas, outside of LNG and power
generation, which would offer Mozambique opportunities to start domestic value-added
industries. These might include methanol and fertiliser production, or the setting up of a gas
to liquids (GTL) plant aided possibly by Sasol (EIA, 2013). Meanwhile where long term
contracts can be secured that are favourable to east Africa, these should be confirmed.
Some of the factors currently leading to the uncertainty about future demand for LNG
include: shale gas supply growth in North America and China, growth in liquefaction capacity
in various regions (particularly in North America, Australia, the Middle East, and East Africa),
regional LNG demand growth, the expansion of LNG in transportation sectors in various
countries, fuel price differentials, the expansion of technologies and infrastructure, etc. (EIA,
2013).
The United States remained the world’s leading consumer of natural gas, However it can be
seen in Figure 25 that with the rapid rise of Asia Pacific this scenario may change in the next
5-10 years. Notice also that the use of gas in Africa is insignificant in the world view.
Figure 25: Natural gas consumption 1965-2012
Page 30
4.2.4 Supply
The gas reserves in the world are plentiful for 50 years or more into the future and new
supplies are being discovered often. Mozambique has recently moved into the top 20 on the
reserves list with a series of significant discoveries (Figure 26). In the expanded view of
African gas reserves (Figure 27) it can be clearly see that Mozambique is now in third
position behind Nigeria and Algeria. Libya is in fifth position with Angola in sixth. It should be
expected that there may still be quite a lot of movement in the position and overall reserve
situation in African countries and exploration increases in future.
Figure 26: Natural gas reserves (190 tcm)
4.2.5 Trade
About 33% natural gas production is traded internationally (Cornot-Gandolphe, 2013).
BP (2013) show gross trading data for gas around the world. They caution that the diagram
in Figure 28 is based on contracts and may not correspond to actual physical movement of
gas. Global natural gas trade was weak in 2012, growing by just 0.1%. Pipeline shipments
grew by 0.5%, whilst global LNG trade fell for the first time on record (-0.9%).
Page 31
Figure 27: African Natural Gas Reserves
Figure 28: Natural gas trade in 2012
Page 32
4.2.6 Price
While energy prices have been relatively flat in June 2013 on an average price level, natural
gas has again declined for the second consecutive month, falling by 5.4% month on month
to $12.96/MWh (OPEC, 2013a). In the U.S. the price of gas to the residential consumer is
about three times the wellhead price due to chiefly transmission and distribution costs (see
Figure 29).
Figure 29: U.U. Gas costs
Source: Insidenergy.com
Page 33
5 ANGOLA
5.1 Coal
Tertiary lignite has been identified in Angola near the headwaters of the Lungue-Bungo
River (up to 2.5m thick) and near Luanda in coastal sediments.
5.2 Oil
Angola became a member of the Organization of the Petroleum Exporting Countries (OPEC)
in 1997. Today, Angola's economy is almost entirely dependent on oil production. Oil
accounted for about 98% of government revenues in 2011 according to the International
Monetary Fund.
With a GDP of over $104 billion in 2011 on the strength of its oil exports, Angola has the
third-largest economy in Africa. The International Monetary Fund estimates Angola's GDP
per capita in 2011 was approximately $5,900.
According to BP (2013) proved reserves at the end of 2012 are 12,700 Mbls or 0.8% of the
world total, and with an R/P Ratio of 19.4.
5.2.1 Exploration
Angola's offshore assets are divided into 41 blocks and separated into three bands:
 Band A (shallow water blocks 0-13),
 Band B (deepwater blocks 14-30), and
 Band C ultra-deepwater blocks 31-40).
There is also limited on-shore exploration (EIA, 2013b).
5.2.1.1 Block 0
Located off the Cabinda coast, block 0 liquid production averaged 340,000 blpd in 2011.
Some of the fields in Block 0 are beginning to experience natural decline rates, but drilling
and exploration continue and production gains are expected over the next few years. In
particular, the Mafumeira Sul development is expected to boost crude oil production by
110 kblpd as from 2015 (EIA, 2013b).
5.2.1.2 Block 14
Block 14 is also located off the coast (see Figure 30), only some areas in this block are
currently producing. The Kuito area is significant because it was Angola's first deepwater
oilfield, and because it is a zero-flare development (EIA, 2013b).
Page 34
Figure 30: Oil Concessions off the Angolan coast
Source: http://www.offshore-mag.com/
5.2.1.3 Block 15
Oil was discovered in Block 15 in 1998, and production first began at the Xikomba field in
2003. Further discoveries came online in later years, and production reached more than
650,000 blpd in 2011. The Kizomba Satellite developments should boost production by
another 100,000 blpd in the near future. Cumulative production from the block reached
1 billion barrels in 2009, and remaining recoverable reserves are estimated to be between
2 and 2.5 billion barrels of oil (EIA, 2013b).
Eni announced another new discovery in its Block 15/06 at its Vandumbu-1 well offshore
Angola in April 2013. The well was drilled at a water depth of 976 meters, reaching a total
depth of 4,107 meters. Eni estimates the well has a production capacity of over 5,000 bpd
(Oilprice, 2013)
5.2.1.4 Block 17
Production in Block 17 began in 2001 at the Girassol field, and has been boosted by
developments at the Jasimin (2003), Dalia (2006), and Rosa (2007) fields. Production in
2011 was greater than 460,000 blpd. In August 2011, the Pazflor field began operations and
output is expected to average 220,000 blpd. Further development at the Cravo, Lirio,
Page 35
Orquidea, and Violeta (CLOV) fields is expected to boost Block 17 production by an
additional 160,000 blpd beginning in 2014 (EIA, 2013b).
5.2.1.5 Block 18
BP is the operator of the deepwater Block 18. The Greater Plutonio development of Block 18
came online in 2007 at approximately 100,000 blpd. Although peak production totals were
expected to hit 200,000 blpd by 2011, technical problems with the water injection system
limited production to 100,000 blpd (EIA, 2013b).
5.2.1.6 Block 31
Angola's first ultra-deepwater discoveries came in 2002, when BP drilled successful wells in
Block 31. BP was given permission to move ahead on the country's first ultra-deepwater
development centred on the Plutão, Saturno, Venus, and Marte (PSVM) fields in 2008.
PSVM production was scheduled to begin in 2012 (EIA, 2013b).
BP Plc has said that the PSVM project will reach peak production of 150,000 barrels of oil a
day in December 2013 (Soque, 2013). It was announced in June 2013 that Sinopec, through
its joint venture company ‘Sonangol Sinopec International Ltd.’ had purchased the 10%
holding of Marathon oil Corporation in block 31 for $1.52 b – raising its own stake in the
block to 15% (Rigzone, 2013).
5.2.1.7 Block 32
The AB32 Southeast Hub development in Block 32 is expected to have production capacity
of more than 200,000 blpd.
5.2.1.8 Lianzi field
The Lianzi field straddles the Angola-Republic of the Congo (Brazzaville) border (see Figure
31). The field is estimated to contain some 70 million barrels and revenues will be split 50-50
between Angola and the Republic of the Congo.
5.2.1.9 Pre-salt exploration
There are strong similarities between the pre-salt geology in Angola (see Figure 32), and
that of Brazil (which hosts > 50 bbls of oil equivalent). Hydrocarbons have now been
discovered by Cobalt in block 21 and by Maersk in block 23 (see Figure 33). Although both
companies are having technical difficulties this is definitely an area to watch (EIA, 2013b).
Page 36
Figure 31: Lianzi field
Source: http://sweetcrudereports.com/
Figure 32: Simplified cross section of the Atlantic between Brazil and Angola
Source: EIA, 2013a
Page 37
5.2.1.10
Onshore
Early in 2012, Sonangol P&P announced that it intended to begin onshore exploration in the
Cabinda Norte Block. However, the security environment is a problem since the Front for the
Liberation of the Enclave of Cabinda remains active in the region. Angola is expected to hold
a licensing round for onshore blocks some time in 2013.
Figure 33: Ultradeep discoveries
Source: EIA, 2013a
5.2.2 Resources and reserves
According to Oil & Gas Journal estimates for the end of 2011, Angola had proved reserves
of 9.5 bbls of crude oil. Angola's crude oil is light and sweet, making it ideal for export to
major world markets. A report on 10 July 2013 mentions that reserves may now be as high
as 12.777 billion barrels (Soque, 2013a). This is after a recent statement by Minister Botelho
de Vasconcelos in April 2013 in which he is quoted as saying that the proven and probable
oil reserves in Angola are now estimated to total 12.667 billion barrels (Macuahub, 2013)
5.2.3 Production
Angola’s oil production increased from 896,000 blpd in 2002 to more than 2 million blpd
2008, this has since slipped to 1.84 million blpd in 2011. Angola's government is targeting a
return to the 2 Mblpd by 2014. There are a series of new projects in the wings and these are
summarised in Table 2.
Page 38
5.2.4 Beneficiation
Angola has one refinery which was built in 1955 and has a 39,000 blpd capacity. The new
Sonaref refinery in Lobito is scheduled to begin operations in 2016 and produce
120,000 blpd initially, ramping up to 200,000 blpd capacity. It will be able to process heavy
and acidic crudes, drawn from fields like Dalia and others like it.
While the new refinery will help to meet domestic demand for refined products, Angola will
most likely remain heavily dependent on imports for the foreseeable future.
In 2011, total consumption of oil products in Angola was about 88,000 blpd.
Table 2: Angolan new oil projects
Project
Kizomba Satellites*
PSVM
Palas, Ceres, Juno, Astrea, Hebe, Urano, Titania
Platino, Chimbo, Cesio
Sangos/N'goma
SE PAJ
AB 32 Southeast Hub CNPC/PetroChina
Pengzhou
CLOV
Cabaca Norte-1
Terra Miranda, Cordelia, Porti
Mafumeira Sul
Negage
Lucapa
Output
(kblpd)
140+
150
150
150
85
150
210
200
160
40-200
150
110
50+
100
Startup
Block
Operator
2012
2012
2012-2013
2013
2013
2013-2014
2013-2014
2014
2014
2014
2014
2015
2014+
2014+
15
31
31
18W
15
31
32
ExxonMobil
BP
BP
BP
ExxonMobil
BP
Total
17
15
31
0
14
14
Total
ExxonMobil
BP
Chevron
Chevron
Chevron
Source: EIA, 2013a
5.2.5 Exports
Angolan crude oil is largely medium to light (30-40° API) with low sulphur (0.12-0.14%),
making it ideal for export. In 2011, Angola exported about 1.53 million blpd, mainly to China
(38%) and the United States (14%). In 2011, Angola was the second largest supplier of oil to
China (after Saudi Arabia) and the 10th largest supplier to the United States.
Angola has several export terminals, including large floating production, storage, and
offloading (FPSO) vessels like the Sanha LPG FPSO and the Kizomba A FPSO. The Sanha
vessel was the first to combine all the LPG processing and export functions on the same
vessel; it is also the largest of its kind. The Kizomba A has a storage capacity of 2.2 million
barrels of oil.
Angola and Zambia have signed a $2.5 billion MoU to construct a 1400 km pipeline from
Lobito to Lusaka in Zambia, to send refined products (including gasoline, diesel, and jet fuel)
to Zambia. The project is scheduled to begin in 2013, and will be operational in 2016.
Page 39
Figure 34: Angolan Oil exports by destination, 2011
Source: EIA, 2013a
5.3 Gas
Angola had proved reserves of 0.31 tcm at the end of 2011. Angola’s first LNG terminal at
Soyo will begin operating in 2013.
5.3.1 Exploration and production
Most Angolan natural gas is re-injected into oil fields to assist recovery, or it is flared off. In
2011, re-injection and flaring accounted for 91% of all the natural gas, but the completion of
the Soyo LNG facility could raise the incentives for natural gas production in the country.
Chevron's $1.9 billion Sanha project (located offshore near Soyo) began operations in 2005,
and is able to process 100,000 blpd of oil, condensate, and liquefied petroleum gas (LPG).
The project significantly reduced the need for gas-flaring in Areas A, B, and C in Block 0
since the roughly 14.16 Mcmpd of dry gas remaining after the raw product is stripped of
condensate and LPG, will be reinjected into the Sanha reservoir to help with oil recovery
operations.
Page 40
As offshore oil exploration continues, Angola needs to ensure that it can process large
volumes of associated gas that its oil operations will inevitably produce. The Soyo LNG
facility will be able to produce 28.3 Mcmpd of natural gas for domestic and international
markets. Plans call for the gas to be sourced from Blocks 0, 1, 2, 14, 15, 17 and 18.
In June 2013 Chevron announced that its subsidiary Cabinda Gulf Oil Company Limited
began initial production of LNG at the Angola LNG project. The first cargo was sold to
Angola's state oil & gas company Sonangol and is being shipped to Brazil by one of the
seven 160,000 m3 LNG vessels under long-term charter to the Angola LNG project
(seekingalpha, 2013).
5.4 Electricity
Angola has recently unveiled its electrification action plan which calls for electrical energy
production to increase from the current rate of 1 GW to 9 GW per annum by 2025. Cuban
experts were reported to be in Angola in July 2013 to train Angolan technicians in regions
where thermal power stations will be located. The aim is to ensure that by 2025 at least 50%
of the population will have access to electricity (AfriqueJet, 2013).
Page 41
6 BOTSWANA
6.1 Coal
In Botswana, bituminous coal with a high ash and high sulphur content is located mainly on
the eastern edge of the Central Kalahari Karoo Basin at Morupule, Mmamabula, Sese and
Mmamantswe. It has a calorific value of 22-26 MJ/Kg and an ash content of about 18-22 %.
In general it contains a high degree of moisture. At Morupule three coal seams of up to
9.5 m, 4.5 m and 2.0 m in thickness are present, whilst at Mmamabula three seams average
2.8, 5.4 and 2.0 m in thickness (Dept. Energy, 2013, Thomas, 2002, Grynberg, 2012).
Over the years the names of coalfields have changed which complicates research.
6.1.1 Reserves and resources
Coal resources estimated at 212 bt with only of this 45 bt classified as measured. These
coal resources are available in the eleven coalfields situated mostly on the eastern part of
the country (Dept. Energy, 2013). Recently Peet Meyer insisted that the more correct figure
for a resource would be 33 bt, whilst Alan Golding regards 60 bt to be more correct
Grynberg, 2013). In reality not sufficient work is yet done to establish what the resource is.
6.1.2 Deposits
6.1.2.1 M orupule coal m ine
Morupule Colliery Ltd., near Palapye some 265 km NNE of Gaborone, is the only operating
coal mine in Botswana. The Morupule main seam is 6.5-9.5 m thick over most of the mine
area but thins towards the northern and southern limits to about 1 m in thickness (Spalding,
1999). Towards the east the coal sub-outcrops at about 40 m from the surface and has been
weathered, towards the west it dips to a depth of more than 300 m. A poor quality seam lies
some 7-10 m above the main seam. The Lotsana seam occurs some 30-60 m above the
Morupule main seam. It is 0.6-4.5m thick and the coal quality varies considerably. Some 50
m higher in the sequence is the high sulphur, Serowe Bright Seam, which occurs at the top
of the Serowe Formation and averages 1.8 m thick (Spalding, 1999).
The Morupule colliery has recently expanded output from 1 to 3.2 Mtpa. It supplies the
adjacent Morupule A (when in use) and B power stations, its other clients include Botash
and the BCL copper-nickel smelter. The colliery also started to export Grade A coal to South
Africa and Namibia in 2012. The Morupule mining lease was extended for a further 25 years
in 2001.
Page 42
There have been severe delays in the completion of the extension project of the Morupule B
600 MW power station and is now only expected to be fully operational commercially by
August 2013. A further extension, Morupule B generator 5 and 6 are planned to go live by
2016, providing an additional 132 MW. Morupule A is currently on care and maintenance
and should return to service by winter 2014.
The Debswana website quotes a reserve figure of 2.9 bt within the #01 and #02 seams with
a resource of 12 bt over the entire property.
Figure 35: Morupule Coal mine
6.1.2.2 M oijabana Coalfield
Spalding (1999) mentions this coalfield with a resource of 1.295 bt in three coal seams.
However, due to the inferior quality of the coal he considers that the coal is of doubtful
economic significance.
6.1.2.3 Serowe Project
Continental Coal is conducting an exploration program on this project. A drilling program
completed totalling 21 cored boreholes on license areas PL339/2008 and PL340/2008 (see
Figure 36) was completed and 13 of these intersected coal. The remainder were drilled into
pre-Karoo basement.
Page 43
An exploration target of 3.9 bt has been set for the project (2 bt for PL339/2008 and 1.9 bt
for PL340/2008). The drilling has shown that shallow coal seams (the Morupule main seam
has an average depth of 88 m) suitable for opencast mining exist. At this stage washability
tests show only a poor (27.9%) yield to attain a product with CV = 20 MJ/kg (Turvey, 2012)
6.1.2.4 Kweneng Coal Project
Continental coal has declared a maiden JORC-Compliant Inferred Resource of 2.159 bt on
the Kweneng Coal Project (PL341/2008 – see Figure 36). Added to this is a further
exploration target of 5 bt for the retained portion of the exploration project. Washability tests
confirm excellent yields to produce steam coal with a CV of 20 MJ/kg that is suitable for the
Southern African power generation market. A 23 MJ/kg product suitable for export to Asian
steam coal markets can also be produced at a lower yield rate of between 25 and 74%
(Turvey, 2012).
Figure 36: Serowe and Kweneng Projects
Source: Turvey, 2012
Page 44
6.1.2.5 M asam a Project
Minergy has announced a maiden JORC-compliant inferred coal resource of 2.8 bt at the
Masama project (see Figure 37), and there is a remaining exploration target of 4 bt.
Botswana’s north-south rail, road, electricity and water pipeline corridor traverses
Botswana’s Mmamabula coalfield and the Masama project.
The coal sub-outcrops at 120-150 m depth, and has a shallow 0.5-3.5° dip. The coal seams
are up to 19 m thick and the area is relatively uncomplicated with regard to structure. A
decision needs to be made on how best to mine the deposit; both opencast and shallow
underground are possible. The strip ratio for an opencast mine would be 1:1.5. Some 1.2 bt
of the coal is above a CV of 25 MJ/kg which is the grade that is considered suitable for
export. Currently the view is for large scale production of 15 Mtpa in the longer term but in
the near term a 2-3 Mtpa export operation is planned.
Figure 37: Masama Project
Source: talonmetals.com
6.1.2.6 Bolau
This is a new discovery for which A-Cap Resources Limited has been granted coal rights.
The steam coal at Bolau is interpreted to be the extension of the adjacent Sese Coal Project
A-Cap now has another major coal project next to its Letlhakane Uranium Project. The Bolau
Discovery Licences PL138/2005 and PL125/2009 (see Figure 38) have been renewed and
amended to include the rights to coal as well as uranium rights already held by A-Cap.
Page 45
Figure 38: Bolau and Mea Project Project
Source: A-Cap, 2013
6.1.2.7 M ea
A relatively new discovery made by A-cap north east of Letlhakane. A total of 44 drill holes
over a 10 km x 12 km area have intersected the coal in the southern portion of PL134/2005.
A-Cap has announced a maiden JORC compliant resource within a portion of Mea of 335 Mt
of coal in multiple seams. Recent test work on selected high-quality float fractions have
revealed potential for higher value products such as PCI (Pulverised Coal Injection) coal at
Mea. There is at least 95 Mt of export quality coal after washing with calorific values of
26.4 MJ/kg. The coal is suitable for domestic power station feed without beneficiation (ACap, 2013)
Page 46
Coal seams occur from the surface to a depth of about 180 m. The coal is in close proximity
to road, rail, power and no settlements occur within the resource area (A-Cap, 2013).
6.1.2.8 M m am abula Prospect
The prospect area occurs some 80 km north of Gaberone, in the Kweneng district and
extending to the South African border. Although the area covered by this prospect is
complicated by faulting, three seams (K Seam, A Seam, and E Seam) are developed to
economic thickness. In parts of this prospect the A seam attains a thickness of 4 m whilst the
K seam can be up to 5 m thick. The Karoo sediments are cut by several faults in this area
and the coalfield is defined by the ENE-trending Zoetfontein fault which has a downthrow to
the north of 250 m (Spalding, 1999).
Mmamabula coal field has a measured and indicated mineral resource estimate of 2.397 bt.
The coal is largely steam coal with raw CV of 20.3 MJ/kg for the D1 seam and 22.6 MJ/kg for
the M2 seam (Jindalafrica, 2013). Jindal will focus on developing a 1200 MW power plant
and export coal mine project with the intention of producing 24 Mtpa over 35 years (Capital
resources 2013).
6.1.2.9 Anglo coal Botswana
Anglo American plc acquired Mmamabula central and south coal fields with an estimated
700 Mt in November 2012 adjacent to the Jindal Mmamabula east coalfields.
6.1.2.10
Lechana – Tshim oyapula
These prospecting areas cover a combined 516 km2 in the Central district about 45 km north
of Palapye (see Figure 39). The coal zone has up to 100 m of interbedded carbonaceous
fine clastic material interbedded with the coal seams. The Karoo strata sub-outcrop below
about 30 m of Kalahari Sands. The Morupule Formation holds the coal bearing sediments.
The Upper Coal Zone in the Lechana basin may be of interest in the eastern part of the
licence area where it is more than 1.0 m thick and seemingly of good quality. The
Tshimoyapula Basin, to the north of the Lechana Basin, contains the Lower Coal Zone. The
economic coal seams occur at an average depth of 134 m below surface for Taukome
Seam, 103 m for the Morupule Seam in the Lechana basin, whilst in the Tshimoyapula basin
the Taukome Seam averages 166 m and the Morupule Seam 220 m in depth. Some 1.3 bt
of coal occurs here (Capital Resources, 2013).
6.1.2.11
Dukwe Prospect
This project occurs to the southeast of the Sua pan covering an area of 212 km2. The town
of Sowa is included in the project area.
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Figure 39: Dukwe, Lechana and Mmamabula projects
Source: Aquilaresources.com
The coal seams occurring here are a part of the Tlapana Formation; they are of variable
thicknesses and are interbanded with carbonaceous mudstones.
The upper seams are
mixed dull and bright coal and are thinly banded and sulphide rich. The Basal Seam consists
of a dull coal with minor thin bright stringers, it has minor interbanding and is clearly
delineated above and below by clastic sedimentary rocks. The seam occurs at about 145 m
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below surface and averages at 5.5 m thick with a minimum of 0.55 m and a maximum of
12.5 m. Capital Resources (2013) indicates that there is a resource of some 1.3 bt at Dukwe.
6.1.2.12
Sese Project
This African Energy project has an estimated 2.47 bt of coal and is situated within 25 km of
the rail which can provide access to east coast ports. At Sese there is a 650 Mt measured
resource, the strip ratio will be less than 2:1 and this will make the mine very competitive –
with ROM cost amongst the lowest in Africa. A prefeasibility is completed and an EIA
underway for two 300 MW Coal fired power stations at Sese – each will be matched with a
1.5 Mtpa “captive” coal mine. If all goes well first power will be produced in 2016 (African
Energy, 2013).
6.1.2.13
M m am anstwe project
An African Energy project that has an estimated 1.296 bt including a 895 Mt probable
reserve of coal within 20 km of the South African border. The acquisition is expected to be
finalised in July 2013. Scoping studies for two 500 MW and two 750 MW power stations and
associated transmission lines have been completed. Sufficient water has been located and a
full EIA approved (African Energy, 2013).
6.1.2.14
Sechaba Project
The Sechaba Thermal Coal Project, owned by Shumba coal mines, has about a 1 bt JORC
compliant resource. A positive scoping study has been completed confirming the potential to
produce coal by early 2016 to supply a nearby or on site power station, a full preliminary
feasibility study is in process (Mininginsight, 2013).
6.1.3 Logistics
Probably the biggest problem with developing the coalfields in Botswana is that of
transporting the product.
The South African coal line between Richards Bay and the Waterberg Coalfield will include a
Botswana link by 2020 according to Siyabonga Gama, the Transnet Freight Rail CEO.
Railing coal from Botswana via Durban had already begun on a moderate scale (Creamer,
2013a).
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6.2 Coal bed methane (CBM)
6.2.1 Energy Botswana Ltd.
Magnum Gas & Power, through its wholly owned subsidiary Energy Botswana Ltd, has
prospecting licences for CBM in two prospective basins in Botswana, in the Nata region over
the “Ngwasha” Basin and in the Central area being over the “Mmashoro” Basin (Magnumgpl,
2013).
6.2.2 Saber Gas project
Saber was a CBM and shale gas project. Its licence areas contained an estimated
contingent gas resource of 0.63 trillion cubic metres (tcm) on a best estimate basis based on
a Canadian National Instrument 51-101 compliant resource report completed in September
2009. Tlou Energy had a farm-in agreement with Sabre and merged with Talon Metals Corp.
in 2010.
Tlou energy recently declared a resource of 65.136 bcm of coal bed methane (Mguni, 2013)
from their Karoo central permits. The Karoo Central and Karoo West CBM permits cover
about 7,000 km2; they relinquished other Botswana property (Masama and Kite Flyer) in
2012 due to poor CBM potential. Tlou is currently running a drilling campaign comprising 6
wells which are scheduled to be completed in the third quarter of 2013. Testing operations
will start in the fourth quarter.
6.3 Oil and Gas
There is no oil known to occur in Botswana. However, African oil and gas company SacOil
has given the right to explore for oil in Botswana. Its Botswana subsidiary Transfer Holdings,
has been granted three exploration licenses by the Botswana Department of Mines.
Magnum Gas & Power has also been awarded a Petroleum Exploration Licence (No.
154/2012) granting it the right to explore for Natural Gas and Petroleum over approximately
23,700 km2 in the Ngamiland and Central districts of Botswana.
Page 50
7 BURUNDI
7.1 Coal
There are no significant coal deposits in Burundi, although there are important peat deposits.
The principal peat deposits lie beneath the 123 km2 Akanyaru swamp complex in northern
Burundi and contain about 1.42 bcm of peat. The proved reserve (expressed as recoverable
dry peat) was reported in 1992 to be 56 Mt (peatsociety, 2013).
7.2 Oil
Recent seismic and magnetic surveys indicated possibilities of oil under Lake Tanganyika
and the Rusizi basin (Kigozi, undated). Surestream Petroleum obtained a licence to explore
for oil in Burundi in 2009 and initiated an EIA in 2010 but there appears to have been no
further work done. The President of the Republic of Burundi signed a Presidential Decree
(n°100/187) on 6 November 2009 to endorse the (October 2009) granting of the exploration
rights to the company on the Block B acreage. The permit is valid for 3 years and is
renewable twice for the same period (Surestream, 2013).
7.3 Gas
There is no record of significant gas fields in Burundi.
Page 51
8 COMOROS
8.1 Coal
There are no significant coal deposits in Comoros.
8.2 Oil
Comoros has one exploration block located over an extension of the Rovuma Delta Fan
The Comoros Islands planned to have a Petroleum Code in place by 2013 that would govern
all aspects of petroleum exploration and production.
In March 2012 Comoros was reported to have awarded an oil exploration and production
licence to a Kenya-based exploration company, Bahari Resources Ltd for an offshore region
bounded by latitudes 10° and 13° South, the western boundary of the Comoros, and 43°
East (Reuters, 2012). However, later that year there were several reports that Boulle Mining
was the only holder of rights, and in October 2012, the government issued a statement that
only one company, Mozambique Channel Discovery Ltd. (MCD), a subsidiary of Boulle
Mining Group, has oil and gas exploration and production rights throughout the territorial
waters of the Comoros. The state-owned oil company, Societe Comorienne des
Hydrocarbures (SCH), known as Comor Hydrocarbures, is responsible for marketing and
distributing imported fuel products (Rach, 2013).
8.3 Gas
No significant gas occurrences have been reported for the Comoros Islands.
Page 52
9 DRC
9.1 Coal
9.1.1 Lukuga
In the DRC the Karoo consists of the Lukuga Formation and the overlying Upper Lueki
Formation. The Lukuga Formation is preserved in grabens in the Lukuga basin along the
border of Lake Tanganyika near Kalemie, in the Luena basin in the Upemba depression of
Central Katanga, in U-shaped glacial valleys on the eastern margin of the Congo Basin, and
in the Dekese sub-basin of the Congo Basin. At its base typical diamictites and varveclaystone relates it to the Dwyka Tillite, whilst the upper parts with arenites and lutites as
well as coal can be correlated to the Ecca Group of South Africa. The Upper Lueki
Formation, which is present along the eastern margin of the Congo Basin, unconformably
overlying the Lukuga Formation is most likely a correlate of the South African Beaufort
Group (Kadima et al, 2011).
An underground mine was operated in this area in the 1920’s by Gecamines, and the coal
used for electricity generation, cement plants and for steam engines (Andrews et al, 2008).
Spalding (1999) mentions that in situ reserves at Lukuga have been estimated at 1 bt but
that economically recoverable reserves of only 600 Mt have been claimed. At Lukuga there
are 5 coal seams with a total thickness of 2.75-6.5 m and with seam 1 being the most
consistent at 1.25-2.4 m thick. The area is block faulted and this makes exploitation difficult.
A summary of the coal quality is given in Table 3.
Table 3: DRC Coal Quality
Characteristic
Moisture
Ash
Volatiles
Calorific Value
%
%
%
MJ/kg
Lukuga
5-7
15-20
31-32
21-25
Luena
5.5
15-21
30-34
25
Source: Spalding, 1999
9.1.2 Luena
At Luena, southeast of Kamina and about 120 km north of Tenke, coal was produced at a
rate of 110 ktpa. The washed Luena coal had an ash content of about 15% and a calorific
value of 24.69 MJ/kg. It has a relatively high volatile content of 35% and is not suitable for
coking. Luena mine started in 1920 as an open-pit. Four seams, varying in thickness from
Page 53
0.5 to 5 m and interbedded in shale, were mined. Reserves were about 20 Mt (Andrews et
al, 2008).
The Luena deposit is also affected by block faulting and as a result there are only four
relatively small areas available with 2-4 seams of up to 5 m thick (Spalding, 1999).
9.1.3 Coal Production
Coal output in the 1950’s was apparently in the order of 300 ktpa, but by 1999 it was only
100 ktpa, mostly from Lukuga (Spalding, 1999).
The present author was told in 2012 by a member of the Gecamines group that the mines
were still producing.
9.2 Oil
The DRC has an Agreement of Cooperation for the Exploration of Hydrocarbons and
Exploitation of Common Fields with Uganda that was signed in June 1990.
9.2.1 Bas Congo
Perenco is currently the DRC's sole oil producer with production both offshore of its short
coastline and onshore in the Bas Congo region (see Figure 40).
9.2.1.1 Offshore
Since 2000 Perenco has been operating offshore of Bas Congo. Crude oil produced is
stored on board the Kalamu floating terminal, which can store up to one million barrels of oil.
The offshore fields are mature with the remaining reserves at the end of 2008 representing
less than 10% of the initial reserves. Perenco's offshore focus has been on a selection of
key fields with the greatest reserves: Tshiala, Mibale, Motoba (Perenco, 2013).
Offshore, Perenco has halted natural decline with new producing wells drilled in 2012.
Production is expected to increase significantly thanks to an additional eight month drilling
campaign.
9.2.1.2 Onshore
Perenco's onshore drilling program started in 2002, shortly after Perenco took over the DRC
operation from Fina. The five oil fields in production are mature and have already produced
almost two thirds of their initial reserves. There are also marginal fields whose further
exploitation requires significant technical know-how. In 2012, onshore production exceeded
expectations, at an average 11 kbpd (Perenco, 2013).
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Figure 40: Bas Congo Oilfield
Source: Perenco, 2013
9.2.2 Albertine Graben
There are 5 blocks available for exploration in the rift valley (see Figure 41). The Albertine
Graben forms part of the western branch of the East African Rift System. In 2006 the first
modern discovery was made in Uganda. The Albertine Graben has 1,200 MMbls of oil
resources but there have been no discoveries in the DRC to date (SacOil, 2013).
9.2.2.1 Blocks I and II
SacOil, has recently been undertaking a two-dimensional (2D) seismic survey over Blocks 1
and 2 on the DRC side of Lake Albert while based in Uganda. The company established its
base in Ntoroko district in order to safely conduct the survey (Redpepper, 2013).
9.2.2.2 Block III
The Block III exploration property rights (3,177 km2) are located in the Lake Albert area close
to the Uganda border and in line with a trend of oil and gas discoveries made recently on the
Ugandan side of Lake Albert (see Figure 42). Block III is currently 66.66% owned by Total
E&P RDC (the operator), 18.34% by Semliki Energy SPRL, with the remaining 15.00%
belonging to La Congolaise Des Hydrocarbures (Cohydro). Kibuku oil seeps suggest that oil
is likely to be found in the northern part of the block.
Page 55
Figure 41: Rift Valley Blocks
Source: Lay and Minio-Paluello (2010)
Figure 42: Block III locality Map, Albertine Graben
Source: SacOil, 2013
Page 56
9.2.2.3 Block V
Apparently the DRC requested the Ugandan government some months ago to allow SOCOExploration and Production, a licensee of Block 5 in DRC, to undertake an airborne gravity
and magnetic survey in the Block while based at Kihiihi in Kanungu District (Redpepper,
2013).
9.2.3 Oil Shale
Some oil shale has been discovered in the Congo Basin (Andrews et al, 2008), but it
appears that it has not been followed through with an exploration effort.
9.3 Gas
Besides gas that is related to the oilfields there is no significant primary gas deposit reported
for the DRC.
Page 57
10 DJIBOUTI
10.1
Coal
There are no significant coal deposits known in Djibouti.
10.2
Oil
Although there is no known oil production or exploration activity in Djibouti, the downstream
oil sector is an important part of the economy. Djibouti is a significant regional bunkering and
refuelling facility. ExxonMobil, Shell and Total handle refuelling at Djibouti's port. Along with
ChevronTexaco, they also distribute and market petroleum products in the country. Storage
capacity at the port facility is 1.26 million barrels (Mbendi, 2013).
10.3
Gas
There is no significant Natural Gas known in Djibouti.
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11 EGYPT
11.1
Coal
Coal in Egypt was estimated as being some 100 Mt in 1990, of which only 20 Mt is
considered to be mineable (Uneca, 1990). The coal was to be found at El Maghara (Sinai
Peninsula), Wadi Thora (east of Abu Zenima) and Ayun Musa (south-east of Suez). The coal
has a poor quality with low CV and high sulphur
11.1.1
El Maghara Coal Mine
This small underground coal mine on the Sinai Peninsula opened in 1989 and was
scheduled to produce at 600 ktpa (Uneca, 1990) however it apparently has produced only
around 360 ktpa, about a quarter of Egypt’s hard coal demand. The demand in Egypt is
primarily for the Helwan steel works. The production from this mine has in the past been
blended with imported coal. Recent figures for Egyptian coal production appear to be well
below the 360 ktpa and Realclearworld (2013) figures indicate a production of 26,000 short
tons per annum from 2006 to 2010.
Notwithstanding the paucity of coal in Egypt, it is considering building a coal fired power
plant. Electricity and energy minister Mahmoud Balbaa is reported to have reviewed
alternatives to secure fuel to provide for a 1950 MW plant at Safaga on the Red Sea (PEI,
2013). Although this has been welcomed in business circles there has been considerable
strong opposition amongst “rights” organisations (Talaat, 2013). A production figure of 17.64
M short tons for recoverable coal is given for 2008 (Egypt, 2013).
11.2
Oil
Egypt holds the third largest liquid hydrocarbon reserves in North Africa. It has been actively
explored since 1860 and has been producing oil since 1910. A number of oil and gas
pipelines are in place serving the Gulf of Suez, Nile Delta/Cairo, and Western Desert regions
and there are nine refineries with a total capacity of around 680 kblpd (Vegas, 2013).
The petroleum industry accounted for 10% of government income and 38% of the country’s
export revenue in 2011. The political unrest in 2011 did not significantly affect foreign
investment in the petroleum industry or disrupt production, and Egypt's revolution has not yet
resulted in regulatory changes.
Page 59
11.2.1
National Oil Company
The National oil or gas company (EGPC or EGAS) is a party to all concession agreements
entered into. EGPC or EGAS is entitled to a share of production. On commercial discovery,
the contractor together with EGPC or EGAS, must establish an operating company that will
operate on a 50:50 deadlocked basis. If a commercial discovery is not made or a
development lease is not granted, the National Company has rights to develop the relevant
part of the contract area on a sole risk basis (Freshfields, 2013). The full set of regulations
pertaining to Egyptian oil and gas is clearly summarised on the Freshfields (2013) website.
11.2.2
Reserves and resources
The Sinai Peninsula is the source of some 80% of the oil production in Egypt (Mekkawi et al,
undated). At the end of 2012 Egypt had proved reserves of 4.3 bbls of oil, representing 0.3%
of the global total and with an R/P ratio of 16.1.
11.2.3
Exploration and Production
Egypt is the largest non-OPEC oil producer in Africa, with crude oil production at 711,500
barrels a day in 2011 (Revenuewatch, 2013), of this, approximately 560,000 blpd was crude
oil including condensates and the remainder natural gas liquids (Freshfields, 2013).
Egyptian oil production comes from five main areas: the Gulf of Suez and the Nile Delta, and
also the Western Desert, the Eastern Desert, and the Mediterranean Sea. Most Egyptian
production is derived from mature, relatively small fields that are connected to larger regional
production systems. Overall production is in decline, particularly from the older fields in the
Gulf of Suez. However, some declines have been offset by small yet commercially viable
discoveries in all producing areas, and to Enhanced Oil Recovery (EOR) techniques used in
mature fields. Since 2000, oil output in the Western Desert area has doubled, and it now
accounts for 28 – 30% of total oil production (EIA, 2013c).
To date, Egypt has entered into some 151 concession agreements for the exploration and
production of oil and gas in three main geographical areas: the Western Desert (with some
36% of the agreements); the Gulf of Suez (with 24% of the agreements); and the
Mediterranean Sea (with 20% of the agreements). Over 50 international oil and gas
companies are engaged in the upstream oil and gas sector in Egypt, including major IOCs
such as BP, Total and Shell as well as large and small independents and national oil
companies (see Figure 43).
Page 60
Figure 43: Northern Portion of Egypt Concession map
Source: http://www.egyptoil-gas.com/concession_map.php
The most recent bidding round for oil and gas by EGPC took place in 2011 and included 15
exploration blocks in the Gulf of Suez, Eastern Desert, Western Desert and Sinai
Sedimentary Basins. In late 2012, it was reported that the bidding round resulted in the
award of 11 concessions (Freshfields, 2013).
The State Egyptian Natural Gas Holding Company has awarded eight new oil and gas
prospecting projects in the Mediterranean Sea in 2013 to BP PLC, Ireland's Petroceltic
International PLC, Italy's Eni SpA, Edison and IEOC, a subsidiary of Eni group, Canada's
Sea Dragon Energy, United Arab Emirates' Dana Gas PJSC and Australia's Pura Vida
Energy NL for an overall minimum investment of $1.2 b. The companies will drill a minimum
of 18 wells and will pay $73.2 million for the licenses (Dow Jones, 2013).
A problem for Egypt is that, notwithstanding the fact that they are a major producer of oil,
their consumption has increased to surpass their production (see Figure 44). In 2012 Egypt
produced 728 kblpd (BP, 2013).
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11.2.4
Exports
Egypt's benchmark oil blend is Suez, which is usually sold at a discount to the Brent contract
because of its relatively high sulphur content (EIA, 2013). Crude oil exports increased by just
over 15% from 95 kblpd to 114 kblpd in 2011. But refined petroleum exports have been
declining. The future trends in both crude and product exports mainly depend on the
government's ability to curtail domestic demand of oil, along with the potential to increase
production through new finds and at existing fields (EIA, 2013). Exports are primarily to India
and Italy which make up 76% of the total (see Figure 45).
Figure 44: Egypt: Total Oil production and consumption 1990-2011
Source: EIA, 2013c
11.2.5
Company News
11.2.5.1
Dana Gas
Dana Gas was awarded 100% working interest in the North El Arish Offshore (Block 6)
concession area located offshore Nile Delta, in the eastern part of the Mediterranean Sea, in
water depths of up to 1,000 m and covering an area of 2,980 km2. The concession has an
eight year exploration period comprising three phases starting with an initial four year
exploration period and two additional two year extension periods. A 20 year development
lease period will be granted based on approved commercial discovery.
Page 62
Figure 45: Egypt: Destination of Crude oil exports, 2011
Source: EIA, 2013c
11.2.5.2
Eni
On the 6th February 2013, Eni announced that it had made a new oil discovery from the
NFW well “Rosa North 1X”, located in the Meleiha Concession, in the Western Desert of
Egypt. The well encountered a total oil pay of around 80 m in multiple sandstones. The well
had been successfully tested with 43°-48° API oil at very good flow rates (Eni, 2013)
The development of the discovery foresees the drilling of at least two development wells in
2013. Production for each well is estimated at 2,000 barrels of oil per day. The production of
Rosa North Field is expected to reach 5,000 bpd in the first 12 months. The oil will be
delivered to the nearby processing facilities of Meleiha field (Eni, 2013)
The Rosa North 1X discovery follows the discovery of the Emry Deep field in May 2012,
which is now producing at a rate of 18,000 barrels of oil equivalent per day after just 7
months. This result confirms that the Meleiha Concession still holds significant untapped
deep exploration potential that has been enhanced by the recently acquired 3D seismic
survey and new geological models which derived from it (Eni, 2013).
11.2.5.3
Apache
Apache has made three discoveries in three separate basins. The NRQ 3151-1X, an
Alamein Basin discovery located in the North Ras Qattara Concession, test-flowed at a
Page 63
combined rate of 1,625 barrels of oil and 529.6 kcm of natural gas per day from two intervals
in the Jurassic Lower Safa Formation. Appraisal drilling is planned for later in 2013.
SIWA L-1X, located in the Siwa Concession within the Faghur Basin, tested at a rate of
2,041 blpd day, the discovery well encountered 385 m of hydrocarbon pay. Production is
expected to commence following government approval of a development lease. In addition
to extending the productive fairway of the Faghur Basin, this discovery also sets up a
number of analogous prospects for drilling later in 2013.
NTRK-G-1X, an exploratory well located in the North Tarek Concession within the Matruh
Basin, encountered 18 m of Upper Safa hydrocarbon pay and tested at 419 kcm of natural
gas and 1,522 barrels of condensate per day. A gas gathering system is currently being
installed in this area by Khalda Petroleum Company, the joint venture operating company
owned by Apache and the Egyptian General Petroleum Corp., and is expected to be
completed in the third quarter.
11.3
Gas
Egypt is Africa’s second biggest producer of natural gas (after Algeria), supplying 62.3 bcm
in 2010 (Revenuewatch 2013), and 60.9 bcm in 2012 (BP, 2013).
11.3.1
Following major recent discoveries, natural gas is likely to be the primary engine for growth
of Egypt’s energy sector for the foreseeable future. In 2011, Egypt’s proven gas reserves
were 2.18 tcm, producing an average of 172.75 Mcmpd (Freshfields, 2013). BP (2013) gives
the reserve at the end of 2012 as 2.0 tcm, the third highest in Africa after Nigeria and Algeria
and representing 1.1% of the world total. The R/P ratio is given as 33.5.
11.3.2
Exploration and production
Egypt's natural gas sector has been expanding rapidly, production has more than tripled
from 18.29 bcm in 2000 to 62.3 bcm in 2010 (EIA, 2013c). Over 80% of Egypt's natural gas
reserves and 70% of its production is located in the Mediterranean and Nile Delta (EIA,
2013c).
In 2012, Egypt produced roughly 60.9 bcm and consumed 52.6 bcm of dry natural gas (BP,
2013). Gas production is expected to continue to grow to satisfy rising domestic demand, as
well as export commitments through the Arab Gas Pipeline, and LNG exports (see Figure
46). Thus, Egypt is expected to continue to be an important natural gas supplier to Europe
Page 64
and the Mediterranean region, although exports are competing with rising domestic demand,
particularly in Egypt's power generation sector (EIA, 2013c).
Figure 46: Egypt: Total Gas production and consumption 1990-2011
Source: EIA, 2013c
11.3.3
Consumption
In 2009, the electricity sector accounted for 54% of natural gas consumption, followed by the
industrial sector (29%). The government is encouraging households, businesses and the
industrial sector to use gas instead of petroleum and coal (EIA, 2013).
Natural gas consumed in the transportation sector has been rising since the development of
compressed natural gas (CNG) infrastructure and vehicles (EIA, 2013c, see Figure 47).
11.3.4
Exports
Dry natural gas exports began in 2003 and have been rising rapidly (see Figure 46) with the
completion of the Arab Gas Pipeline in 2004 and the start of the three LNG trains at
Damietta in 2005 (EIA, 2013c). After 2006 exports began to level off and in 2010 natural gas
exports dropped by nearly 20%. Around 70% of total natural gas exports are as LNG, and
the remainder is exported via pipelines.
In 2010 half of Egypt's LNG was shipped to Europe, which imported about 5.1 bcm, with
over half of that destined for Spain (3.1 bcm). Major importers of Egyptian LNG are shown in
Figure 48.
Page 65
Figure 47: Egypt: Natural Gas Vehicles sold 2004-2010
Source: EIA, 2013c
Figure 48: Egypt: LNG Exports, 2010
Source: EIA, 2013c
Page 66
11.3.5
Company News
11.3.5.1
Dana Gas
On 30 June a significant gas discovery in Egypt’s Nile Delta was announced. Dana Gas’s
Begonia-1 well produced 266.2 kcmpd of gas, along with light oil condensate. The Begonia-1
well is in the Lower Abu Madi Formation. Total evaluated resources for the Lower Abu Madi
zone are between 198-425 Mcm, along with around 100,000 barrels of condensate.
11.3.6
Primary Energy Consumption
In 2009, 48% of Egypt's energy consumption was met by natural gas and 47% by oil. Oil's
share of the energy consumption mix is mostly in the transportation sector, but with the
development of compressed natural gas (CNG) infrastructure and vehicles, the share of
natural gas in the transportation sector is likely to continue to grow.
The government has been pushing to reduce domestic petroleum consumption by
attempting to reduce subsidies and promote the use of natural gas. However, subsidy
reduction is a politically sensitive issue that has proven difficult to fully implement.
Page 67
12 ERITREA
12.1
Coal
There are no significant Coal deposits known in Eritrea. Pateman (1998) refers to some
lignite occurrences.
12.2
Oil
Due to the long struggle for independence there has been little exploration for oil in Eritrea.
Most commentators believe that it has a considerable potential for good oil reserves. It
appears to have all of the geological features for hydrocarbons to be present especially
offshore. The 125,000 km2 Eritrean Red Sea Basin has potential in the pre-rift (Mesozoic),
syn-rift (Miocene), and post-rift (Late Miocene to early Quaternary) sediments.
Pateman, (1998) in his book on Eritrea says that there is a good possibility that the Red Sea
off Massawa has deposits of petroleum and natural gas. Drilling on the Dahlak Islands was
carried out from 1938-1940 but drilling records have not survived. In 1969 Mobil oil drilled a
well that had gas and condensate was drilled.
The Assab refinery supplied refined product for consumption in Eritrea and Ethiopia until it
closed in 1997.
12.3
Gas
There is no record of significant natural gas deposits in Eritrea.
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13 ETHIOPIA
13.1
Coal
Tertiary Brown coals which have high ash and low sulphur content and that range from
lignite to subbituminous coal occur in Ethiopia in beds up to 15 m thick. The main localities
are at Chelga, Wuchalle and Dobre-Brehan.
Coal exploration in Ethiopia started in the 1940s and the Italians mined deposits between
1937 and 1940. Several coal deposits and occurrences have been identified by the
Geological Survey. Over 80% of the coal occurrences are centred in the southwest (e.g.,
Dilbi - Moye, Achibo - Sombo, Geba basin (Yayu area). However, Chilga and Delgi deposits
in the northwestern part are worthy of mention (GSE, 2013).
There is a total of about 600 Mt of coal resource in the country and a large proportion of this
is lignite - subbituminous coal (GSE, 2013).
Besides the deposits mentioned here there are several other small deposits that can
nevertheless be important for the local communities.
13.1.1
Delbi-Moye basin coal & oil shale deposits
Delbi-Moye basin is a small NNW-SSE trending graben preserving thick sedimentary
succession of Eocene to Miocene age. Much of the area is covered by the Ashangie group
volcanics. Coal and oil shale bearing strata are enclosed within the thick volcanic suite. At
Delbi there is 111 Mt of oil shale and 14 Mt of coal and at Moye there is 27.5 Mt of coal
(GSE, 2013). In 2011 Delbi was about to start producing at 30 ktpa and to increase
production up to 200 ktpa chiefly with the purpose of supplying cement producers
(Tekleberhan, 2011).
13.1.2
Geba basin coal deposit
In the Geba basin coal and oil shale are found intercalated within tertiary volcanic rocks. At
Achibo-Sombo there is 121.45 Mt and Yayu 396.7 Mt of coal (GSE, 2013). At Yayu there is
also a considerable deposit of oil shale. The lower bed reaching a maximum thickness of
15 m whilst the upper bed reaches 30 m in thickness. The resource is estimated at more
than 500 Mt (Ahmed, 2008).
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13.1.3
Chilga Basin /Chilga and Delgi localities/ coal deposits
Coal seams with subordinate oil shale are found intercalated within Tertiary volcanic
deposits in northern Ethiopia. At Chilga there are 19 Mt and at Delgi 60 Mt of coal (GSE,
2013).
13.1.4
Coal and oil shale deposits in Lalo-Sapo Basin
Oil shales are deposited in the Lalo-Sapo Basin in downthrown blocks and a resource of
more than 15 Mt has been estimated. Coal reaching a maximum of 2 m in thickness also
occurs and has a resource of some 7.5 Mt (Ahmed, 2008)
13.1.5
Import
The Ethiopian government and British supplier Hayton Inc. have agreed to extend the coal
supply agreement until December of 2013. The agreement is for the import 600 kt of coal for
the National, Derba MIDROC and Messobo cement factories. The factories should have
been purchasing the coal at 50 kt per month but have defaulted due to low cement demand
(Tekleberhan, 2013).
13.2
13.2.1
Oil and Gas
Ethiopia has a proved oil reserve of 430 Mbls (EIA, 2013).
13.2.2
Ethiopia has a good hydrocarbon potential but is underexplored. There are five distinct
sedimentary basins which are believed to have hydrocarbon potential. They are the Ogaden,
Gambella, Southern Rift, Abay and Mekele basins. Only 46 wells have been drilled so far in
the 350,000 km2 Ogaden Basin (UKTI, 2013).
Two discoveries in the Ogaden basin were at El Kuran in 1972 and the confirmation of the
size of natural gas reserve of 75.46 bcm in Calub and 36.82 bcm in Hilala gas condensate
fields (UKTI, 2013).
The Abay Basin covers an area of approximately 63,000 km2 in the central northwestern
plateau. A geochemical analysis of an oil seep from Wereilu locality in the northeastern
margin of the basin suggests the presence of mature oil source rock of marine origin (UKTI,
2013).
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In the southwestern Ethiopia, the Gambella Basin covers an area of some 17,500 km2. The
Gambella area is considered to be the southeastern extension of the Melut Basin where two
oil discoveries (Adar and Yale) are present (UKTI, 2013).
The 8,000 km2 Mekele Basin, occurs in the north, although there is not much information on
its prospectivity, some studies suggest that it may be of interest for oil.
The Southern Rift Basins (South Omo and Chew-Bahir Basins) lie within the rifted
zone of southern Ethiopia. Tullow Oil has drilled the Sabisa – 1 well in South
Omo (see
Figure 49) and though it was dry, it has encountered reservoir rock and source rock. This
block is considered an extension of Tullow’s Kenya concession.
Page 71
Figure 49: Locality of the Sabisa – 1 well
Page 72
Source: AfricaOil 2013.
13.2.3
Trade
Ethiopia imports some $2.5 billion (2012) worth of oil and therefore has a healthy local
demand for oil products. The size of the domestic market for lubricants is estimated at 48 m
litres per annum. (UKTI, 2013).
Page 73
13.2.4
Company News
New AGE Ethiopia is also planning to drill an appraisal well in June 2013 on the El Kuran
locality to establish commercial viability. South West Energy is expected to drill three wells
in 2013 and 2014 in its Ogaden Basin blocks on Ethiopia’s border with Somalia (UKTI,
2013).
Falcon Petroleum Ltd is currently undertaking seismic survey in the Wereilu locality of the
Basin (UKTI, 2013).
Page 74
14 KENYA
14.1
Coal
Kenya’s Energy Minister announced in September 2010 that large coal and iron ore deposits
had been discovered in the Tharaka-Nithi County – enough for 30 years of production
(Wanyoro, 2010). It is not totally clear, but this is probably the same deposit referred to as
the Mui Basin deposit that has become a political football in Kenya over the recent past. It is
being used in various arguments relating to the possible pollution caused by mining and in
the context of passing the new minerals bill.
14.1.1
Mui Basin Coal
Mwiluka, 2009 gives the average CV of the coals assessed in her study as 21.16 MJ/kg, with
a 52.16% fixed carbon and with 45.89% volatiles, 26.53% ash, 2.01% sulphur, 2.04% iron
and 2.04% moisture. 33% of the samples were anthracite, 20.3% bituminous coal, 11.4%
lignite. 63% of the samples where suitable for use as steam coal, 19% for domestic fuel and
18% for metallurgical coal.
It was reported in February of 2013 that Kenya was to create 31 coal exploration blocks to
be leased to prospective investors. Blocks C and D are already mapped and leased out, they
are thought to have more than 400 Mt of coal according to estimates from the Ministry of
Energy (Senelwa, 2013).
14.2
14.2.1
Oil
Kenya’s Petroleum potential lies in the 4 sedimentary basins: Anza, Mandera (Lokichar),
Tertiary Rift and Lamu (see Figure 50). Preliminary estimates by the Ministry of Energy
suggested that the Tertiary Rift Basin may contain 2 bbls of oil. Three other sedimentary
basins: Lamu, Mandera and Anza are also prospective (African Energy, 2012).
Kenya had no proved resources at the end of 2012.
Tullow Oil and Africa Oil made the first major oil discovery in Kenya, the Ngamia-1 well in
block 10BB, in March 2012 (see Figure 51). The Ngamia-1 well opened up a new oil basin in
Kenya which has the potential to be one of the largest in the world. Industry estimates of the
onshore potential of Kenya are as high as 20 bbls (taipanresources, 2013).
Page 75
Figure 50: Kenyan Basins
Source: taipanresources
Figure 51: Schematic cross section at Ngamia 1 Well
Source: AfricaOil, 2013
Page 76
Test results of the Ngamia-1 well show that the cumulative flow rate from six Drill Stem Tests
(DST's) was over 3200 barrels of oil per day constrained by completion techniques and
surface equipment. The zones all produced dry oil with no water and no pressure depletion.
The oil was high quality waxy sweet crude (25-35° API). Tullow Oil believes the Ngamia and
Twiga fields contain over 250 Mbls of recoverable oil.
Tullow has recently estimated that the Turkana exploration basin has in excess of 300 Mbl of
oil after it discovered up to 50 metres of fresh reserves in Etuko-1, which falls within the
same basin as Twiga South-1 and Ngamia-1 wells in which alone have a potential of
250 Mbl of oil. Tullow believes that, with the discoveries in Kenya and output from Uganda, a
pipeline delivering 500,000 barrels a day is needed by 2018 (Odhiambo and Omondi, 2013).
14.2.2
Tullow Oil was the only oil exploration company active in Kenya. It has increased its
resource estimate for the South Lokichar basin in Kenya after flow tests at its Ngamia and
Twiga South wells and a new discovery at the Etuko-1 well. Tullow believes there is a flow
rate potential of 5,000 barrels a day based on Ngamia-1 and Twiga-South-1, and estimates
there are 250 Mbls of oil in place (Reuters, 2013). The Ngamia-1 exploration well was drilled
to 2,340 meters and reported a significant light oil discovery with more than 100 m of net
light oil pay in the Upper Lokhone Sand section and an additional 43 m of potential oil pay in
the lower Lokhone Sandstone section (taipanresources, 2013).
Ian Springett, Tullow’s finance director, said that the positive well test results in Kenya had
"crystallised the thinking of all parties" around a pipeline route that would see Ugandan
production exported via Kenya - linking up with Kenya's own supplies and probably reaching
the coast between ports Mombasa and Lamu (Reuters, 2013).
Kenya has now licensed 45 of its 46 oil and gas exploration blocks (see Figure 52), with the
last one, L25, under negotiation with Statoil of Norway. There are 23 international oil
companies, plus National Oil Corporation of Kenya, which has licensed Block 14T, involved
in exploration.
14.2.3
Company News
Following Tullow Oil’s Ngamia well on Block 10BB, which discovered over 100 m of net pay
within a 1.1 km thick gross oil-bearing interval, the focus is turning to the offshore. Apache is
about to drill a well in water depths of 800 m to an expected total depth of 3,400 m on the
Mbawa prospect, Lamu basin Block L8. Apache estimates that Mbawa contains 289 Mbls of
Page 77
oil, and has mapped 2.8 bls in follow-on targets if the well is successful (African Energy,
2012).
Anadarko Petroleum Corporation has five blocks in the deep offshore and was due to drill on
L7 and L12 by January 2013 (African Energy, 2012).
BG has processed 1,500 km of 2D seismic and 2,500 km2 of 3D on blocks L10A and L10B
(African Energy, 2012).
Figure 52: Kenyan Oil exploration Blocks
Source: http://www.kincommunications.com/
14.3
Infrastructure
Currently crude oil is one of Mombasa Port's main imports; the port has two oil terminals and
a refinery to receive and process the crude. The Kipevu Oil Terminal is located in the Port
Reitz area and can accommodate crude oil tankers up to 100,000 dwt, while the Shimanzi
Oil Terminal can hold vessels up to 30,000 dwt. The Mombasa refinery is one of the largest
petroleum refineries in East Africa and has a nameplate capacity of 90,000 blpd, with a
Page 78
throughput of almost 35,000 blpd in 2011. The refinery processes heavy crude from Abu
Dhabi and other heavy Middle-Eastern crude grades. In 2011, Kenya imported around
35,000 blpd of crude oil entirely from the United Arab Emirates. About 75% is processed into
fuel oil, light diesel (gas oil), paraffin, and jet/turbo fuel. Kenya also imports refined oil
products. It imported around 56,000 blpd of refined oil products in 2011. Kenya has a
product pipeline system that transports petroleum products inland (EIA, 2013).
EIA (2013) reports that the new ‘Lamu Port and South Sudan Ethiopia Transport’
(LAPSSET) pipeline will be a reversible product pipeline and will replace the Mombasa to
Nairobi pipeline. Mombasa port will be upgraded to deal with the increased capacity. The
LAPSSET project involves the development of a new transport corridor from the new port of
Lamu through Garissa, Isiolo, Mararal, Lodwar and Lokichoggio to branch at Isiolo to
Ethiopia and Southern Sudan. The corridor will consist of a new road network, a railway
line, oil refinery at Lamu, oil pipeline, Isiolo and Lamu Airports and a free port at Lamu
(Manda Bay).
The LAPSSET project has already been launched on March 2, 2012.
Feasibility studies for corridor components and the design of three (3) berths and associated
facilities in Lamu are complete. The Kenya government has set aside Kshs.2 billion for the
construction of the three berths. Tendering process for the construction of the three berths is
ongoing. The Lamu Port headquarters is 80% complete and the due date was June 2013
(Vision2030, 2013).
Other proposed pipelines are the Nairobi-to-Arusha (Tanzania) pipeline which will supply oil
from Kenya's Turkana County, once commercial production begins, to Tanzania, and the
Lake Albert (Uganda)-to-Kenyan Coast pipeline (EIA, 2013)
Page 79
Figure 53: Oil product output at Mombasa refinery 2011
Source: Kenya Petroleum Refineries, shown in EIA 2013.
Kenya is putting several new infrastructural projects in place in order to serve the region and
extend its role as an oil transit hub (EIA, 2013).
In June 2013, Sunday Nation reporter Risdel Kasasira reported that Kenyan President Uhuru
Kenyatta and Rwandan counterpart Paul Kagame agreed with President Museveni to build
an oil pipeline from the East African coast at Lamu to Rwanda. It was agreed to build two oil
pipelines, the current line between Mombasa and Eldoret should be extended to Kampala
and Rwanda and upgraded to allow reverse trade. The second pipeline will be for the export
of crude oil from Uganda, South Sudan and Kenya, ending up at the port of Lamu.
The three countries have furthermore agreed to construct a railway line from Kenya through
Uganda to Rwanda (Kasasira, 2013).
Page 80
15 LESOTHO
15.1
Coal
Although there have been reports of small amounts of coal in Lesotho, there is no significant
deposit.
15.2
Oil
Lesotho has no known significant oil resources. There has been some oil exploration in the
Mahobong area, but this was not successful (Mbendi, 2013)
15.3
Gas
Lesotho has no known resources of natural gas.
Page 81
16 LIBYA
16.1
Coal
Libya has no known significant coal deposits. There are lenses of low grade lignite that are
found interbedded with carbonaceous clay and limestone. The Shek-Shuk seams
interbedded between layers of clay and dune sand can be up to 1m thick (Spalding, 1999).
16.2
Oil
Libya produced an estimated 1.65 Mblpd of mostly high-quality light, sweet crude oil prior to
the onset of unrest in February 2011. Oil production began properly again in September
2011, and was estimated to have recovered to at least 1.4 Mblpd by May 2012 (EIA, 2012).
According to the U.S. Department of State, oil accounted for approximately 95% of Libya's
export earnings, 75% of its government receipts, and 25% of its GDP prior to the political
upheaval of 2011 (EIA, 2012).
Prior to 2011, Libya's oil industry was run by the state-owned National Oil Corporation
(NOC), which was responsible for implementing Exploration and Production Sharing
Agreements with international oil companies, as well as its own field development and
downstream activities. Its subsidiaries include the Arabian Gulf Oil Company (AGOCO) and
the Sirte Oil Company.
The organization of Libya's oil sector is in flux and could change considerably depending
upon the outcomes of political processes. Meanwhile it is clear that the country’s oil and gas
sector has not yet (July 2013) recovered from the political disruptions that the country has
faced over the past couple of years. There are still disruptions at various oil fields and
harbours and according to the Chairman of the General National Congress’ Energy
Committee, Naji Al-Mukhtar, Libya is losing $50 million a day because of industrial action at
oil sites (Fornaji, 2013).
16.2.1
Libya, a member of the Organization of Petroleum Exporting Countries (OPEC), holds the
largest proven oil reserves in Africa and is an important contributor to the global supply of
light, sweet crude oil.
According to Oil and Gas Journal, Libya had total proven oil reserves of 47.1 bbls as of
January 2012. Close to 80% of Libya's proven oil reserves are located in the eastern Sirte
basin, which also accounts for most of the country's oil output. BP (2013) estimates that
Page 82
Libya has proved ore reserves of 48 bbls and equates this to 2.9% of the world total. The
R/P ratio is given ay 86.9, but it is unclear whether this is based on the current lower
production due to the political troubles in the country or is more directly related to the long
term trend (BP, 2013).
16.2.2
Oil and gas occur in four of the seven main sedimentary basins in Libya -- the Sirte,
Ghadames (Hamra), Murzuk (Murzuq, Muruzq) and Tripolitania. The Al Kufra Basin, in the
southeast, has minimal if any potential. The Cyrenaica Platform has some potential in
Palaeozoic strata (see Figure 54). About two-thirds of Libyan oil production comes from
fields in the eastern part of the country (Sirte Basin), followed by 25% in the southwest
(Murzuk Basin), and most of the remainder from the offshore Pelagian Shelf Basin near
Tripoli (there are also small fields in the western Ghadames basin).
Figure 54: Libyan Basins
The Sirte Basin, while the most mature of Libya's basins, remains an important exploration
region. The Sirte is a Cretaceous to Tertiary basin with a series of horst and graben
structures. Original recoverable reserves in the Sirte were about 29 bbls of oil (Shirley,
1999).
Page 83
Figure 55: Foreign companies in Libya
Source: Energyrealities.org from stratfor.com
Libya's oil sector suffered after civil unrest commenced in February 2011, and only began to
recover in September of that year (EIA, 2012 see Figure 56). Oil production was given as
1,509 kblpd which was well up from the 479 kblpd of 2011 but not yet up to the 1,659 kblpd
of 2010 and still far from the 2007 and 2008 peak of 1,820 kblpd (BP, 2013).
16.2.3
Local consumption and Exports
Domestic consumption estimated at 300 kblpd which represents about 15-20% of the long
term production – the remainder is exported, mainly to European countries especially Italy,
France, Germany, and Spain (EIA, 2012).
Page 84
Figure 56: Libyan Oil production 2000-2012
Source: EIA, 2012
Figure 57: Libyan Oil export destinations, 2010
Source: EIA, 2012
16.2.3.1
Com pany news
The Arabian Gulf Oil Company operates in the eastern region of Cyrenaica. Its most
significant fields, Sarir (~200 kblpd capacity) and Messla (~100 kblpd) are located in the
Page 85
Sirte basin. Related downstream infrastructure includes the Ras Lanuf refinery and Marsa alHariga (Tobruk) terminal (EIA, 2012).
Waha Oil Company has a total production capacity is more than 350 kblpd which is divided
among a number of loosely defined fields all located in the Sirte basin (EIA, 2012).
Repsol and Akakus Oil operations have a production capacity of about 350 kblpd. Repsol
fields are located in the Murzuk basin in Libya's southwest. Related downstream
infrastructure includes the Zawiyah refinery and export terminal near Tripoli (EIA, 2012).
Eni and Mellitah Oil & Gas: Eni's largest field, Elephant (El Feel), is in the Murzuk basin.
The Sirte Basin fields operated by Eni, which include Bu Attifel with crude grade exported
through the Zueitina terminal. Eni also operates the Bouri field and various condensate fields
in the offshore Pelagian basin. The Eni-operated NC-118 block in the Ghadames Basin has
a projected peak production capacity of only 10 kblpd. Eni's total oil production capacity in
Libya is just over 300 kblpd, of which nearly 50 kblpd is condensate and the remainder is
crude (EIA, 2012).
Wintershall: The German company has fields at As Sarah and Nakhla, which are also
referred to as the NC96 and NC97 fields, in the Sirte Basin. Crude oil production capacity is
just over 100 kblpd (EIA, 2012).
Suncor and Harouge Oil Operations: operate various fields in the Sirte basin, of which
Amal is the most significant. Current production is below 100 kblpd. Harouge production of
Sirtica-grade crude oil is exported through the Ras Lanuf terminal (EIA, 2012).
Sirte Oil Company: operates the Al-Ruqhubh and other fields, with a total production
capacity of at least 100 kblpd (EIA, 2012).
Total and Mabruk Oil Operations: The offshore Al Jurf field, which has a capacity of
45 kblpd, includes participation by Wintershall. The joint venture's total production capacity is
roughly 70 kblpd (EIA, 2012).
Occidental, OMV, and Zueitina: produces from the Sirte basin. Production capacity is
~60 kblpd, but output in 2012 was limited to approximately three-quarters of that due to
pipeline issues and a lack of gas for reinjection (EIA, 2012).
MedcoEnergi: This Indonesian firm is not currently producing in Libya. However, it is
partnering with the National Company as the operator of Area 47, one of the few significant
projects projected to come online over the next five years. Peak production capacity of Area
47 is supposed to be between 50 and 100 kblpd (EIA, 2012).
Page 86
16.3
16.3.1
Gas
At the end of 2012 Libya had a proved natural gas reserve of 1.5 tcm which represents some
0.8% of the world total.
16.3.2
Libya’s natural gas production has grown substantially in the last few years. A portion of the
natural gas produced is re-injected to enhance oil recovery and some is still vented or flared.
As with oil, Libyan natural gas production was almost entirely shut-in for sustained periods in
2011, but has since recovered quickly.
The Western Libya Gas Project, which is operated by Eni and NOC through the Mellitah Oil
& Gas joint venture, accounted for most of the Libyan natural gas production growth since
2003. The project includes the offshore Wafa and Bahr Es Salam fields (EIA, 2012).
16.3.3
Local consumption and export
In 2010, Libya consumed an estimated 6.85 bcm of dry natural gas which satisfied just over
25% of Libya’s energy consumption needs. Natural gas accounted for about 40% of Libya’s
generated electricity in 2009. This leaves about 60% of Libya’s dry natural gas supply for
export. Most of Libya’s natural gas exports are transported via pipeline to Europe (Italy), with
small volumes also shipped in the form of liquefied natural gas.
16.3.3.1
Greenstream
Libya’s capacity to export natural gas increased dramatically after October 2004, when the
595 km Greenstream pipeline came online. The pipeline starts in Mellitah, where natural gas
piped from the Wafa concession and offshore Bahr Es Salam fields is treated for export. It
then runs underwater to Gela, on Sicily, and onward to Italy. The pipeline has a capacity of
11 billion cubic metres per annum, since a capacity expansion in 2007 (EIA, 2012).
16.3.3.2
Liquefied Natural Gas (LNG)
In 1971, Libya became the second country in the world (after Algeria in 1964) to export LNG.
Libya's LNG exports have remained low, largely due to technical limitations. Its LNG plant
was built in the late 1960s at Marsa El Brega. It has been offline since February 2011 as a
result of damage sustained during the civil war (EIA, 2012).
Page 87
17 MADAGASCAR
17.1
Coal
Coal occurs in the Karoo sediments on the western side of Madagascar. Three coalfields
have been delineated. In the north the Imaloto coalfield has seams averaging 1 m in
thickness. South of that the Vohibory coalfield has seams up to 2.3 m whilst the Lanapera
coalfield has seams only up to 0.6 m, both Vohibory and Lanapera coalfields exhibit
structural complexity. The Sakoa Coalfield has coal that is high in volatiles and has high ash
and low sulphur and with seams up to 3 and 7 m thick. In the Sakamena coalfield the coal is
similar but in thinner seams (Thomas, 2002).
Tertiary lignite occurs in the Antanifotsy region (Thomas, 2002). Spalding (1999) mentions a
lignite occurrence in the area of Sambaina southwest of Tananarivo, where three seams,
one of which attains 0.7 m in thickness lie under a shallow cover.
17.2
Oil
Madagascar Oil is exploring for oil and gas deposits in five onshore blocks in Madagascar. In
the last five years two fields, Tsimiroro and Bemolanga, have been shown to have multibillion barrel resource volumes in place. Field tests indicate that a large portion of the
Company's Tsimiroro heavy oil assets have potential for economic development
(Madagascaroil, 2013) using the cyclic steam stimulation (CSS) process.
17.2.1
Notwithstanding the resources that are now (in 2013) better understood, at the end of 2012
there were no significant proved oil reserves in Madagascar. However there is a very good
resource (2.5 bbls) heavy oils sand deposit at Bemolonga as well as a probable 2.1 bbls
heavy oils resource at Tsimororo.
17.2.2
Exploration
17.2.2.1
Block 3104 Tsim iroro
Block 3104 is about 125 km from the west coast. When the Tsimiroro field was first drilled
14° API oil was discovered at a depth of 40-300 m. A number of wells drilled together with a
430 km Electrical Resistivity Tomography program, has demonstrated that Tsimiroro is a
significant heavy oil resource volume. The 2011 contingent best estimate is now 1.7 bls and
the prospective best estimate exceeds 2.1 bbls of Original-Oil-in-Place (Madagascaroil,
2013).
Page 88
The recovery factor estimate is 70% and the Best Estimate would result in a Contingent
Resource volume of 1.1 bbls. Steam tests indicate that the field can be successfully
developed utilizing a conventional vertical pattern steam flood (Madagascaroil, 2013).
Madagascar Oil is testing the viability of using a conventional pattern vertical multi-layer
steam flood in the Tsimiroro field. The project was expected to start production in late 2012
and to run approximately 18 months to acquire data that will resolve numerous reservoir
performance factors that are expected to de-risk the decision to proceed with a full scale
development of the field (Madagascaroil, 2013).
17.2.2.2
Block 3102 Bem olanga
Block 3102 is located about 170 km from the west coast of Madagascar. The field has had
over 400 boreholes drilled in the 0 to 200 meter depth in the Amboloando Formation prior to
Madagascar Oil operations, which have proven a bitumen deposit of 10 degree API oil is
present (Madagascaroil, 2013).
Madagascar Oil began further investigation in 2006 and Total E&P joined the project in 2008
as a 60% partner and become the operator. Laboratory testing has indicated favourable
results for extraction performance of 75% of the bitumen using the typical hot water
extraction process, but the low ore grade makes the project uneconomic at current prices
(Madagascaroil, 2013).
Exploration for deeper conventional oil is continuing (Madagascaroil, 2013).
17.2.2.3
Block 3113
In 2009, the Sino Union Energy Investment Group’s discovered oil in the SKL-2 well with
estimated resources of 2 bbls in Block 3113 onshore Madagascar (Taipanresources, 2013).
17.2.2.4
Other Blocks
Block 3105 Manambolo does have one area of interest whilst Block 3106 Morondava has
two areas and Block 3107 Manandaza has one large structure and three smaller structures.
A well with light oil has been drilled at Block 3107 Manandaza but there are negative aspects
relating to the quality and size of the reservoir and the possible effect of a fault. Additional
work needs to be done (Madagascaroil, 2013).
17.2.3
Production
Madagascar Oil hopes to start small-scale production at the Tsimiroro field in 2013 as part of
a steam flood pilot project. Heavy crude oil production from the pilot project is expected to
peak at 1,200 blpd by early 2014. The pilot project will test whether the steam-flood recovery
Page 89
will deliver the expected 70% recovery which is much higher than the CSS recovery factor of
around 16%. If successful, Madagascar Oil anticipates commercial oil production at
Tsimiroro will commence in 2019 and ramp up to 150,000-160,000 blpd. The company
estimates that the cost of fully developing the field will be $1.5 billion, which will include an
export terminal, a pipeline to transport the oil to the coast, a marine terminal, and an offshore
mooring facility.
17.2.4
Regulation
The Office of National Mines and Strategic Industries (OMNIS) is in charge of the upstream
hydrocarbon sector. It is a state-owned entity under the authority of the Prime Minister and
supervision of the Ministry of Energy and Mines. OMNIS grants exploration, production, and
transportation permits to foreign oil companies, which are subject to a royalty tax that could
range from 8- 20%, a direct hydrocarbon income tax, and other taxes.
In 2011, Madagascar Oil concluded a dispute with the Malagasy government over the
validity of the Tsimiroro field and the Manambolo, Morondava, and Manandaza exploration
licenses. The dispute has been resolved (EIA, 2012).
.
Page 90
18 MALAWI
18.1
Coal
The main coalfields situated in Karoo basins in the south and north of Malawi. They are:
 Ngana Coalfield: in a fault bounded trough in the Karonga district in northern Malawi
 Lufira Coalfield: in a small Karoo Basin northeast of Karonga Town (4-12 seams of
4mm – 2.45 m thick)
 Livingstonia Coalfield: Block faulted with seams of 0.3-2.7 m thick.
 North Rukuru: Occurs over 150 km2
 Mwabvi Coalfield: occurs within 140 km from Blantyre and is affected by complex
faulting. In 1999 only a small area of the coalfield had been investigated
 Lengwe Coalfield: Has been well investigated but the high ash content militates against
its commercial production
The Karoo sediments in Malawi unconformably overlie Precambrian crystalline basement
rocks and were deposited and preserved in graben-like structures. The coals are subbituminous to high volatile bituminous coals with a high ash and low sulphur content. The
Livingstonia coals with seams of up to 1 and 2 m thick are mined for local use (Thomas
2002).
18.1.1
In 1999 the proven resources over all coalfields totalled 22 Mt, whilst probable resources
added 81 Mt and possible resources added a further 195 Mt to give a total of all reserves
and resources at 298 Mt Coal. The 1999 reserves and resources by coalfield are
summarised in Table 4.
Table 4: Malawi reserves and resources 1999
Coalfield
Ngana
Lufira
Livingstonia
North Rukuru
Nthalire
Kibwe
Mwankenja
Mwabvi
Lengwe
Proven
resource
Probable
resource
15.0
0.6
1.4
50.0
2.0
5.0
5.0
15.0
3.0
1.0
5.0
Possible
resource
Moisture
%
Ash %
Volatiles
%
Fixed
Carbon %
Sulphur
%
20.0
150.0
4.5
6.6
1.1-18.0
4.2
30.2
35.0
17.0
32.4
24.9
25.9
5-37.3
23.7
32.8
31.8
5.6-64.2
40.6
2.2
0.77
0.06-0.9
0.6
Average
Calorific Value
KJ/kg
19.71
15.99
28.47
20.02
5.0
10.0
10.0
1.7
45.2
59.2
6.8
10.5
50.5
30.3
0.76
0.5
17.47
11.50
Source: Spalding, 1999
Page 91
18.1.2
In 1999 there was one operational mine in the Livingstonia coalfield at Mchenga in the
Rumphi district, operated by the Malawi Development Corporation and Inde Bank.
18.1.2.1
Eland Coal M ine.
The Eland Mine was established in 2006 at Karonga, Mwaulambo Area in the Northern
Region of Malawi with an exclusive prospecting area of 54 km².
Eland currently produces 42 ktpa with a potential to produce 60 ktpa, coal is washed and
exported (Eland, 2013).
18.1.2.2
Nkhachira M ine
Current plans are focused on the expansion of production and industrial coal sales, with
future plans to supply coal to either the Pamodzi power project in Tanzania, or a local power
plant. Drilling to date has identified three main seams in the Nkhachira deposit:
 the Upper Seam (with thickness of 0.8m),
 the Middle Seam (0.8-2.1m), and
 the Lower Seam (3.0m).
The seams dip at 10-12º where short term mining is planned (<2 years) but the dip increases
to 10-20º in areas considered in the longer term. Tests completed during due diligence
showed raw coal quality ranging between 23-30 MJ/kg and 12-28% ash.
18.1.3
Consumption
Until 1985 Malawi imported all of its coal, but in that year the Mining Investment and
Development Company opened a small mine at Kaziwiziwi in the Livingstonia coalfield, the
mine closed four years later, and a new mine was opened at Mchenga.
18.1.4
Company News
Intra Energy Corporation, through its subsidiary, Malcoal, plans to develop a 120 MW coalfired power plant in Malawi that will burn coal from its newly acquired Nkhachira mine
(Chimwala, 2013). Malawi’s demand for power is 300 MW, but only 160 MW of the installed
generation capacity is working effectively. This generation shortfall is projected to grow
rapidly and the Malawi Ministry of Energy estimates that the country will need 603 MW by
2015 and 829 MW by 2020 (Chimwala, 2013). Malawi currently derives 94% of its electricity
from hydropower plants located on the Shire River, while 6% is generated from a thermal
power plant at Wovwe.
Page 92
The coal resource still needs to be geologically mapped and drilled (Chimwala, 2013), but
the Nkhachira mine (Malcoal Mine) is operating. During the first quarter of 2013, 2.858 kt of
coal was mined at the Malcoal mine and stockpiled. The mine was previously worked by
artisanal miners and Malcoal have now commenced with pre-stripping and with a 50x100m
boxcut. Stripping has exposed a 3 m thick seam. It is understood that once the mine is fully
operational it will produce 15 ktpm (RFC Ambrian, 2013).
Exploration is continuing in northern Malawi with the aim of establishing a JORC compliant
resource by the end of 2013 (Intra Energy 2013).
18.1.5
Planned transmission upgrade and power station
Energy Minister Ibrahim Matola, has signed an agreement with Chinese firm TBEA to
construct new power transmission lines and upgrade existing ones. The lines to be upgraded
include the Phombeya-Salima-Nkho-Takota-Chatoloma line, which is to be upgraded to
220 kV at a cost of $222 M, the Nkhotakota–Chintheche–Luwinga–Bwengu line to 220 kV at
a cost of $139.9 M and the Lilongwe–Mchinji–Chipata line to 330 kV at a cost of $85 M. The
upgrades are required for the connection to the Southern Africa Power Pool (Chimwala,
2013a).
A coal-fired power plant is to be set up by China Gezhouba at Kam-mwamba, in the
southern Neno district. The plant will source coal from Moatize mine via the new rail link
being built by Vale. A spur from the railway line to the site of the new power plant has been
factored into the design for the railway line. The project, which is expected to be completed
in 24 months, will cost about $667 M (Chimwala. 2013a).
18.2
Oil and Gas
Malawi currently has no known oil or gas reserves; however, both Karroo aged rift systems
as well as the tertiary (Great Lakes) rift systems may be prospective for oil.
The search for oil around Lake Malawi could lead to a major international incident since
although Malawi claims jurisdiction over the entire lake based on the Helgoland treaty,
Tanzania claims 50% of the lake based on international law.
Malawi is according exploration blocks to companies to explore for oil. Surestream has
acquired blocks 2 and 3 from Karongo to Mkhotakota.
In August 2012, it was reported that Malawi had found evidence of oil and gas in Lake
Malawi as well as in the Shire Valley in the south. The research is ongoing but seismic
reflection data as well as cores gave indications of hydrocarbon potential (Mkula, 2013).
Page 93
18.2.1
Border dispute
The ongoing border dispute between Tanzania and Malawi over ownership of Lake Malawi
has not yet been solved, but a high level discussion between the countries and the African
Forum for Former heads of state has been having discussion this in July, 2013. The forum
hopes to broker a deal by September 2013 failing which the matter should go to the
international court of Justice.
18.2.2
Company News
18.2.2.1
SacOil
South African oil and gas company, SacOil, has won an exploration license in Malawi in
Block 1, an area spanning about 12,200 km2 in the northwest of the country (Burkhardt,
2012). A second licence was also awarded to SacOil over disputed territory with Tanzania in
Lake Malawi
18.2.2.2
Intra Energy
Intra Energy is working through NuEnergy Gas to develop opportunities to produce
unconventional gas (coal-bed methane and shale gas) in southern Malawi, where NuEnergy
Gas has an exploration licence (Chimwala, 2013).
Page 94
19 MAURITIUS
19.1
Coal
There are no significant coal deposits in Mauritius.
19.2
Oil and Gas
There are no known oil and gas reserves in Mauritius.
Page 95
20 MOZAMBIQUE
20.1
Introduction
Mozambique has abundant and yet largely unexplored natural resources. Four coalfields
occur in Mozambique of which the Moatize coalfield is the most important.
The Cahora Bassa hydroelectric project with 2,075 MW is one of the largest hydropower
installations in Africa. Several new hydro dams (Mphanda Nkuwa, Cahora Bassa North) are
planned or under construction.
Natural gas is found on-shore (in Pande, Temane and Buzi) and off-shore (Rovuma basin).
Several new power plants are planned or already under construction (Benga, Moatize,
Ncondezi, Moamba, Kuvaninga, Ressano Garcia).
The development of its natural gas and coal reserves, together with the huge potential for
steel, cement and fertilisers should take Mozambique into a much higher GDP within the
next 5-10 years (see Figure 58).
Figure 58: Possible impact of coal and oil on Mozambique economy
Source: World Bank and SPTEC Advisory estimates as shown in SPTEC, 2012
20.2
Coal
The Moatize basin forms part of Karoo Supergroup and the coal deposits probably formed
during Permian period. The basin has of 11 coal seams. At Moatize the coal seams range
from 0.4 to 4 m in thickness, and the coalfield is structurally complex. The coal is generally
Page 96
low in volatiles and bituminous with a high ash and low sulphur content. The other three
coalfields at MMambansavu, Chiome and Itule are less well known (Thomas, 2002) and
there appears to be no interest from exploration companies.
20.2.1
The Tete region has currently got a coal reserve of 1,340 Mt and this figure is expected to
increase as the level of confidence in more deposits is raised sufficiently through detailed
exploration and production drilling. The resource figure currently stands at 17,686 Mt (see
Table 5). The Mucanha – Vuzi basin located on the north shore of Lake Cahora Bassa has
an estimated 3,600 Mt of coal (Mining Journal, 2000).
20.2.2 Deposits
20.2.2.1
Benga
Riversdale was been operating in Mozambique since 2006. It had a 25 year mining lease
and has already had environmental approval (mining and power) and in April 2010 Benga
mine (owned by Riversdale - 65% and Tata Steel - 35%) was officially opened. Rio Tinto
took over the Riversdale holding in April 2011. The mine reached commercial production in
June 2012 when the first coking coal was exported (Sourcewatch, 2013), producing 460 kt.
Mallyon (2010) has compared the quality of the coking coal at Benga to that at Bowen Basin
in Australia, which is considered amongst the best in the world. The resource is given in
Table 5. Riverdale had a 40% life of mine (LOM) offtake agreement with Tata steel, and a
10% LOM offtake agreement pending with WISCO in 2010 (Mallyon, 2010) and therefore
this material is essentially sterilised to local beneficiation. Coal from the mine is transported
to Beira Port via the 660 km Sena railway.
On 17 January 2013 Rio Tinto announced that it had written off $3 b relating to Rio Tinto
Coal Mozambique investments. In a media release Rio Tinto stated that
"the development of infrastructure to support the coal assets is more challenging than Rio Tinto
originally anticipated. Rio Tinto sought to transport coal by barge along the Zambezi River, but
this option did not receive formal approvals.
These infrastructure constraints, combined with a downward revision to estimates of
recoverable coking coal volumes on the RTCM tenements, have led to a reassessment of the
overall scale and ramp up schedule of RTCM, and consequently to the impairment announced
today. Rio Tinto continues to engage with the Government of Mozambique on all transport
infrastructure options." (Rio Tinto, 2013).
Page 97
Table 5: Tete coal resources
Mine/prospect
Moatize Phase 1
Moatize Phase 2
Zambeze#
Benga@
Ncondezi
Revuboe
Minas Moatize
ENRC Estima
Jindal (Chirodzi)
Midwest Africa
Songo
Muturara
Tete West
Cambulatsitsi
Total
Company
Start
Date
Vale
Vale
Rio Tinto
Rio Tinto
Ncondezi
Anglo
Beacon Hill
ENRC
JSPL
Midwest Africa
2011
2015
2024
2012
2015
2015
2011
2013
2013
2019
Production1
Coking
Mtpa
8.58
8.58
13.5
6
0
5.1
0.72
6
3
1
Production1
Thermal
Mtpa
2.6
2.6
9
4
10.5a
3.4
1.64
4
2
6
“Target”
Mt
Estimated
resource
Mt
Reserve
Mt
2500
1400
9045J
825 J
4655J
1400J
86.8J
502
724
480
424
19236
2326
~1860
~2880
~200
4940
Source: Various sources
1
– Current or planned, Resenfeld 2012
a
– 50% or more for domestic power feedstock
J
– Jorc compliant
@
- Mallyon 2010 gives JORC compliant reserves as Proven: 346 Mt, Probable: 156 Mt, and resources as Measured:
710 Mt, Indicated: 362 Mt, Inferred 2,960 Mt
#
- Mallyon 2010 gives JORC compliant resources as Indicated: 2,365 Mt, Inferred: 6,680 Mt
20.2.2.2
Jindal (Chirodzi)
Jindal has a 25 year mining right for coal over an area of 16,700 ha. The mining right was
acquired in February 2011 and the estimated resource of the deposit is some 724 Mt. Jindal
estimated capital expenditure to be in the order of $200 M to bring the mine to operation.
20.2.2.3
Cam bulatsitsi
An Essar affiliated Company, Essar Recursos de Minerais de Mozambique Ltd, holds a coal
licence in the Cambulatsitsi area near Tete. Initial exploration of the area led to an
independent estimate of an approximate resource of 35 Mt. The Essar Group has entered
into a MOU with CCFB (consortium of CFM-RITESIRCON) for transporting the coal to Beira
port (Essar, 2010).
20.2.2.4
M oatize
The Moatize mine was officially inaugurated in May 2011, with an estimated life span of 35
years. In the first phase of the project the Vale plans to mine 11 Mtpa of coal (8.5 Mt
metallurgical coal and 2.5 Mt steam coal). A second phase was due to be completed at the
Page 98
end of 2014 to duplicate loading and double production. However, Vale is slowing down
Phase 2 of its Moatize mining project, to ensure that it comes into operation in at the same
time as the new Nacala Corridor rail route (Campbell, 2013).
When completed, the Nacala line and the port handling facilities will have the capacity to
transport 18 Mtpa of coal.
Meanwhile, Vale set a new record in June by extracting 509 kt of coal and by transporting
300 kt of coal on the Sena railway line. Vale plans to export 3 Mt this year (2013).
20.2.2.5
Zam beze
Riversdale’s Zambeze coal project lies adjacent to the Benga project which will allow
possible production and administration synergies. The Zambeze Project is similar in
structure to Benga with 22 coal seams outcropping over a strike length of 14 km across the
northern portion of the tenement (Sourcewatch 2013).
Riverdale had a 40% LOM offtake agreement pending with WISCO in 2010 (Mallyon, 2010).
The resource is given in Table 5. Like Benga the plan is to produce export quality coking and
thermal coal. The principal geologist is reported to have indicated in March, 2011 that there
were 26 geologists and a total exploration staff of 60 together with 10 drilling rigs on site and
that the feasibility study was expected to be completed in 2012 (MacDonald, 2011).
Zambeze is now held 100% by Rio Tinto coal Mozambique.
In August 2013 Rio Tinto obtained a 25 year mining concession for the $3.3 b project which
is expected to begin production in 2024. The Mozambique state will hold a 5% stake in the
mine, through the Mozambican Mining & Exploration Company (EMEM) (Dodson, 2013).
20.2.2.6
Ncondezi Coal Project
The Ncondezi Coal Company has a large prospect to the northeast of Tete. The Ncondezi
Coal Project covers an area of 38,700 ha in the coal bearing Zambezi Basin. It comprises
licences 804L and 805L (See Figure 59). A JORC compliant resource (Total tonnes in situ –
TTIS) of 4.655 bt has been identified. Of this resource 4.1 bt occurs within 250 m of the
surface and is potentially mineable by opencast methods, however only 2.6 bt of this will be
included in the DFS.
SRK have undertaken a scoping study in which they confirmed that the prospect has the
economic potential to produce 10 Mtpa of thermal from an open pit operation. At this stage
the company has not got a coking coal resource.
A definitive feasibility study (DFS) for a 1800 MW coal fired power station was completed in
2012, it will be developed in 300 MW units and ramped up over a 6 year period. It is
Page 99
expected to require 1.2 Mtpa per 300 MW unit so that once it is fully in place it will require
7.2 Mtpa of the Ncondezi output. Coal will be ring fenced at the mine to assure at least a
25 year supply for the power plant. Ncondezi announced in April 2013 that it had
successfully concluded a Power Framework Agreement with the Government of
Mozambique. Ncondezi hopes to supply power where needed to the power hungry areas in
southeast Africa.
Figure 59: Ncondezi Project locality map
Source: www.ncondezicoal.com
Currently it is planned to start mining in 2016 and for the first power plant (300 MW) to be
commissioned in 2017. It was announced in August 2013 that Ncondezi had received a
mining concession for its integrated mine and power plant, the concession allows for the
company to mine the deposit until 2038. The company has agreed to grant the government
of Mozambique a 5% interest in the project. The company has also agreed to spend a
minimum of $5 M on social development programmes (Mining Journal, 2013)
At the mine the coal occurs in zones of up to 80 m thick and dips from the surface at 15%.
There will be low strip ratios at the beginning of mining. The DFS for the mine was due
towards the end of 2012. First production is targeted for the second half of 2015, but the
export component of the mine will only be initiated once the infrastructure to export is fully in
place.
Page 100
20.2.2.7
Revuboè
Revuboè coal mine is located near Benga, Zambeze and Moatize mines. The mine is owned
by Talbot Group (58.9%), Nippon Steel & Sumitomo Metal Corporation (33.3%) and Posco
(7.8%). The licence, obtained in 2004, extends across 3,860 ha and that it has government
approval (April 2013) it will be developed as an open-cut mine with first production expected
in 2016. It will produce coking coal and thermal coal. The expected LOM is 25 years. The
mine will employ 300 employees during construction and 700 employees when operational.
The mine, which has a resource of 1.4 bt is expected to produce 5 Mtpa of coking coal and
3 Mt of steam coal after ramping up.
20.2.2.8
Zóbuè (M idwest Africa)
Midwest Africa has obtained a 25 year mining concession covering an area of 15,840 h.
some 50 km northeast Tete city. The project has a resource of 480 Mt of coal, of which
363 Mt is metallurgical coal. It is estimated that the company will invest $ 1.4 b in the project,
with production expected to begin in 2019. It is planned to build a 20 km section of road to
connect the project to the National road. The prospecting license area covered a total area
of 15,840 hectares, of which an area of 8,000 hectares contained at least 10 layers of coal
(Macuahub, 2013c). It is likely that production will be some 1 Mtpa metallurgical coal and
6 Mtpa thermal coal. It is expected that the mine will employ 1320 workers during production,
and providing the state with $ 35 Mpa in taxes. The Mozambique state will hold a 5% stake
in the mine, through EMEM (Dodson, 2013)
20.2.3
Production
Ncondezi coal mine plans to sell about 50% of its output to a power plant. A 300 MW power
plant is to be commissioned in 2017 (Figure 60). The power will be for the grid (23 MW) for
Ncondezi mine (40 MW and the rest will be consumed by the plant itself. Later in a phase 1B
a further 300 MW will be added and still later a phase 2 will bring on line another 1200 MW
(Ncondezi, 2012).
The Benga project is being developed in phases. The first phase will produce 5.3 Mtpa ROM
including 1.7 Mtpa of hard coking coal and 300 ktpa of thermal coal, for use in power
stations (see Table 6).
Table 6 is in broad agreement with the government of Mozambique. The Mozambican
Mining Resources Minister, Esperança Bias, said on the 14th March 2011 that Mozambique
expected to reach a coal production of 30 Mt by 2015; however it must be emphasised that
this production will only be possible if the export routes and other means of offtake are in
place, and that presents a huge challenge.
Page 101
In the longer term Benga plans to produce 10 Mtpa including 6 Mtpa of hard coking coal and
4 Mtpa of export thermal coal from the Benga project (Mallyon, 2010).
Riversdale is
investigating the possibility of the production of 90 Mtpa ROM from the Zambeze project in
the long term (Mallyon, 2010).
Figure 60: Ncondezi electricity project
Source: www.ncondezicoal.com
Page 102
Table 6: Tete production estimates
Mine/prospect
Moatize
Zambeze
Benga
Ncondezi
Minas Moatize
Total
2013
3,400
2,000
5,500
2014
6,400
2,000
5,500
2,000
20,500
2,000
23,500
Estimated production kt*
2015
2020
2025
9,200
11,000
22,000
8,000
15,000
15,000
10,000
10,000
10,000
2,500
10,000
10,000
2,000
2,000
2,000
33,500
48,000
48,000
2030
22,000
15,000
10,000
10,000
2,000
48,000
2035
6,000
15,000
10,000
10,000
2,000
43,000
Source: Macdonald, 2011; Macdonald, 2011a; Mallyon, 2010; Ncondezi, 2011 and own estimates
* Assuming Logistics issues can be dealt with.
20.2.4
Logistics
Vale intends upgrading the line from Moatize to Nacala and linking via Malawi to shorten the
route, Resenfeld (2012) suggests that the Nacala line may be operational in 2015, and have
a transport capacity of 25 Mtpa. The capacity of the port of Nacala is being expanded in
parallel. The Sena line may also be upgraded to allow 19 Mtpa to be transported by 2015 2016. Furthermore Resenfeld (2012) indicates that Rio Tinto, Ncondezi and Revuboè have
suggested third train line, linking Tete to a new deepwater port North of Quelimane, perhaps
by 2018-2020. In a recent report it was suggested that the Nacala line may already be
operational by September 2014 (Macuahub 2013b).
20.2.5
Challenges
Up to this point the lack of infrastructure has been the major challenge to developing the coal
wealth of Mozambique, however new challenges are now presenting themselves in terms of
worldwide economic conditions, militant politics, and social and labour issues.
In April 2013 a large group of local Mozambicans protested outside the Vale Mine gate at
having been poorly treated when resettled for the mine development. They said that they
were resettled about 60 kms from the Moatize site and had a lack of water, electricity and
fertile agricultural land at their resettlement area (Lopes, 2013).
In the face of flat trade Rio Tinto, which has been producing coal from the Benga mine in the
Moatize basin, has suspended using the rail line in June 2013 in the wake of threats made
by former rebels to sabotage the network. Rio has been transporting about 20 kt per week
via the rail to Beira.
The Sena rail is under pressure to deliver more coal to the coast. Rio Tinto has lost 1,386 t
of coal after the derailment of a train with 42 coal wagons along the Sena railway line on
15 July 2013. The accident took place at the Magagade in Caia district, in the province of
Sofala. Transport and Communications Minister Paulo Zucula was quoted in the daily paper
Page 103
Noticias as saying that derailments have reduced substantially since the line began
transporting coal due to safety systems put in place. These systems cut the number of such
incidents from an average of two to less than one per month. He blamed some of the
incidents on line defects, and said that repair work was underway and stressed the need for
train drivers to obey the speed limits. The line is handling a daily average of a dozen coal
trains as well as a daily service carrying sugar and molasses from Marromeu, limestone from
Muanza and wood from Doa. There is also a passenger service twice a week (Starafrica,
2013).
20.3
Oil
As at January 2013, Mozambique does not have any crude oil reserves (EIA, 2013d).
20.4
Gas
Mozambique has large onshore and offshore sedimentary basins that contain natural gas
resources, but much of it is unexploited (EIA, 2013d).
20.4.1
As at January 1, 2013, Mozambique holds 127.44 bcm of proven onshore natural gas
reserves (EIA, 2013d).
There are also significant offshore discoveries in the offshore Rovuma basin. EIA (2013)
records the offshore discoveries as 0.9-1.8 tcm as recoverable gas resources in area 1
(Andarko) and 2.12 tcm gas in place in area 4 (Eni) in March 2013.
20.4.2
Exploration
Since 2010, there have been a series of natural gas discoveries in the offshore Rovuma
Basin that are large enough to support liquefied natural gas (LNG) projects. The U.S.-based
Anadarko and Italy-based Eni have led exploration activities in the area. Mozambique
expects to begin exporting LNG to the global market in the next five to ten years.
20.4.2.1
Offshore Rovum a Basin
Large offshore discoveries in the Rovuma basin in Northern Mozambique, currently
estimated at close to 2.95 tcm, are likely to be exported as LNG and possibly used locally for
projects such as fertilizer manufacturing (Resenfeld, 2012).
ENI
On 26 March 2012, Eni (2012) announced a new giant natural gas discovery in Area 4,
offshore of Mozambique, at the Mamba North East 1 exploration prospect (see Figure 61).
Page 104
Mozambique’s national oil company, the 100% state owned Empresa Nacional de
Hidrocarbonetos (ENH), has a 15% stake in Area 1 and 10% stake in Area 4.
The results of the March 2012 discovery will increase the resource base of Area 4 by at least
0.319 tcm. This discovery means the potential of the Mamba complex in Area 4 is now
estimated to be at least 1.133 tcm.
Mamba North East 1 is located 50 km off the Cabo
Delgado coast in a water depth of 1,848 m and reaches a total depth of 4,560 m.
Eni has now elevated the gas potential of the Mamba Complex in Area 4 offshore
Mozambique to 2.12 tcm in place with drilling of the Coral-3 delineation well (Mamba
complex (1.76 tcm gas in place) and the Coral site (368 bcm gas in place)). The Eni group
drilled Coral-3 to 5,270 m in 2,035 m of water 5 km south of Coral-1, 15 km from Coral-2,
and 65 km off the Cabo Delgado coast. It is the eighth well drilled back to back in Area 4.
(Oil and Gas Journal, 2013)
Figure 61: Mozambique offshore Rovuma Basin discoveries
Source: EIA, 2013
Page 105
Eni plans to drill the Mamba South-3 delineation well in order to assess the full potential of
the Mamba Complex discoveries before moving back to exploratory drilling in the southern
part of Area 4 (Oil and Gas Journal, 2013).
Because the Prosperidade and Mamba Complexes straddle the boundaries of Area 1 and 4,
joint development of reserves that are under separate licenses (unitization), between the
overlapping areas is required under Mozambican law. In December 2012, the Anadarko and
Eni signed a Heads of Agreement in which the companies agreed to conduct a separate but
coordinated exploration program in the license areas. They also agreed to jointly construct
an onshore LNG facility at Afungi Park in the Cabo Delgado province of northern
Mozambique (see Figure 61), which could cost a total of $50 b (EIA, 2013). The first LNG is
expected to be delivered sometime between 2018 and 2020.
ANADARKO
The exploration activities in the offshore Area 1 have resulted in six of the world’s largest
discoveries in 2010, 2011 and 2012 at the Windjammer, Barquentine, Lagosta, Camarão,
Golfinho and Atum prospects. The natural gas accumulations are located in water depths of
about 1500m (Anadarko, 2013 - see Figure 62, Figure 63).
Figure 62: Mozambique Rovuma Basin Area 1
Source: Anadarko, 2013
Page 106
Gas discoveries in its Prosperidade field give a ~481-850 bcm recoverable resource and in
the Golfinho/Atum field there is a 425-991 bcm recoverable resource.
Anadarko has recently announced the discovery of a new natural gas accumulation
contained within the Offshore Area 1 of the Rovuma Basin of Mozambique. The Orca-1
discovery well is another large, distinct and separate natural gas accumulation in the
Offshore Area 1. A two-well appraisal program to define the areal extent of the Orca field,
will commence after drilling of the Linguado and Espadarte exploration wells (Oil and Gas
Journal 2013a).
Figure 63: Mozambique Gas field map
Source: INP, 2013
Page 107
20.4.2.2
Onshore M ozam bique Basin
Mozambique has four proved gas fields located onshore in the Mozambique basin. They are
Pande, Buzi, Temane, and Inhassoro. Total proved natural gas reserves in Mozambique
were 1274 bcm, as of January 1, 2013, according to the Oil & Gas Journal (OGJ).
Although natural gas was discovered in Buzi in the 1960's, the resource was considered too
small to be commercially viable. However in the coming months of 2013 further exploration
and testing will be carried out in the area. The publicly owned Mozambican Hydrocarbon
Company (ENH) has indicated that a second phase of acquiring seismic data is currently
underway in order to reinterpret that situation.
For the natural gas in Buzi to be economically viable there should be at least 42 bcm of gas
for domestic consumption and electricity generation (All Africa, 2013).
20.4.3
Production
Gas production has increased rapidly since the pipeline to South Africa was laid (see Figure
64). In 2011, Sasol produced 3.82 bcm of dry natural gas from the Pande and Temane
Fields (EIA, 2013). It is likely that Mozambique will be the first country in east Africa to
produce LNG, possibly followed by Tanzania (EIA, 2013)
Figure 64: Mozambique natural gas production 2000-2011
Source: EIA, 2013
Page 108
20.4.4
Trade
Most of the gas produced from the Pande and Temane Fields (3.31bcm) to South Africa via
the 860 km Sasol Petroleum International Gas Pipeline, and the remainder was domestically
consumed (0.51bcm) (EIA, 2013).
Mozambique signed an MOU with Japan in 2012 with the aim of supplying energy resources
to Japan in order to replace nuclear energy as its main power driver.
Page 109
21 NAMIBIA
21.1
Coal
Although Coal is not recorded in Namibia, Thomas (2002) points out that the eastern half of
the country is covered by post-Karoo sediments and that there remains a possibility that coal
may be present here.
21.2
Oil and Gas
The Kudu gas and condensate accumulation, located on the border between the Luderitz
and the Orange basins, constituted the most important discovery in Namibia (Mello et al.
2012) with proved reserves of around 36.81 bcm (Figure 65). Comparing geological history,
geochemistry and the reinterpretation of remote sensing data has lead Mello and others
(2012) to conclude that the Namibian offshore basins can be considered a new frontier for
exploration. The Namibian source rock systems appear similar to those that have sourced
more than 90% of the oil discovered in the Brazilian and Angolan marginal basins and might
be large enough to charge globally significant oil and gas accumulations.
Namibia’s energy ministry has approved a 1-year extension of the initial exploration period
on Walvis basin Blocks 2111B, 2211A, 2213A, and 2213B offshore Namibia. The extension
allows more flexibility and time to execute the exploration program for 1,000 km2 of 3D
seismic on each license in 2015 and drilling an exploratory well in 2016 before the first
renewal period (Oil and Gas Journal, 2013b).
HRT Participacoes em Petroleo SA, Rio de Janeiro, has found non-commercial amounts of
oil its Wingat-1 well on Block 2212 in the Walvis basin offshore field. The fact that the source
rock is in the oil window and generating liquid hydrocarbons of excellent quality confirms the
source potential of the basin (Oil and Gas Journal, 2013c). Unfortunately a second hole
drilled by the company was dry, but his has not put off other companies that are all moving
ahead on their prospecting programmes. Geologically the results showed that the area
remains prospective and that the source rock is present. HRT will be going ahead with its
next hole “Moosehead-1” in August (Namibian Sun, 2013).
21.2.1
Value addition
It was reported on the 19th July 2013 that NamPower is looking for investment partners for a
$1 b Kudu combined-cycle gas and steam 800 MW turbine project, near Oranjemund.
Namibia currently generates only 39% of its own electricity, with 40% of its power coming
from Eskom, 9% from Zambia Electricity Supply Corporation and 12% from Zimbabwe
Page 110
Electricity Supply Authority respectively (Odendaal, 2013). In the latest news NamPower has
approved a shortlist of 15 international companies and consortia that have applied to
participate in the engineering, procurement and construction (EPC) tender for the design,
supply, manufacture, delivery, erection, test and commissioning of the Kudu power station
(Greve, 2013a).
Figure 65: Namibian oil and gas fields
Source: http://www.2b1stconsulting.com/
Page 111
22 RWANDA
22.1
Coal
There are no known significant deposits of Coal in Rwanda.
22.2
Oil
Rwanda, has hydrocarbon potential in North Western Rwanda and deep under Lake Kivu.
The preliminary magnetic and gravity exploration results indicated a sedimentary basin of 23.5 km thickness in the northern and central part of Lake Kivu.
Vanoil Energy had completed a two month extension of its technical evaluation agreement
with the government, a move that provides the company with exclusive rights to benefit from
the production of oil in the Kivu Graben if discovered (see Figure 66). The Technical
Evaluation Agreement expired on 17 June 2013, and Vanoil has referred this matter to the
Conciliation Committee (Vanoil, 2013)
Figure 66: Schematic diagram of the lake Kivu graben
Source: Mugisha, 2013
Vanoil has held exclusive exploration rights to the 1,631 km2 East Kivu Graben in northwestern Rwanda since 2010. The Lake Kivu graben lies at the southern edge of the
Albertine graben were there have already been oil discoveries in Uganda (Mugisha,
undated).
Page 112
23 SEYCHELLES
23.1
Coal
There are no coalfields of any significance in the Seychelles.
23.2
Oil and Gas
After completing a review of laws regulating the sector, Seychelles has invited oil and gas
companies to bid for exploration blocks. This move ends a two year moratorium and
introduces new rules for bidders.
Seychelles does not have a fixed number of exploration areas, but companies can bid for
areas of up to 10,000 km2 each out of its 1.3 million km2 Exclusive Economic Zone. Under
the new rules, once a company approaches the government on a first-come, first-served
basis for an exploration area, rivals will have up to 90 days to submit bids for the same
block. Once the 90-day bidding period expires, the government will select the company that
has demonstrated the financial ability to conduct exploration and go into production if it
strikes commercial quantities. Seychelles operates under concession contracts, whereby the
company keeps exclusive rights to develop and produce the petroleum if it is commercial.
Under the new licensing regulation, exploration companies will be required to pay 10% of
petroleum revenues as a royalty, up from a previous 5% (Reuters, 2013e).
Afren plc and Australia’s WHL Energy are the only companies currently holding exploration
licences in Seychelles (Reuters, 2013e).
23.2.1
Afren
In 2012, Afren relinquished Area C in order to focus on high-priority plays in Areas A and B
(see Figure 67). Areas A and B are cover a combined area of approximately 14,319 km2.
The main exploration targets are the Permo-Triassic Karoo interval, which comprises nonmarine sands inter-bedded with shales and a Cretaceous marine rift basin underlain by
Jurassic platform source rocks. The Karoo formation contains both the source rock and the
reservoir. Over 1980 to 1981, three exploration wells were drilled, all of which encountered
oil shows and confirmed the presence of a working hydrocarbon system.
In Q1 2013, Afren completed a major 3D seismic programme, the first 3D survey to be
conducted in the Seychelles. The programme consisted of two surveys in Afren’s licence
areas. The first 3D survey was conducted in the southern portion of the licence over the
Page 113
Bonit prospect and covered 600 km2. The second survey was in the northern section of the
licence area and covered an area of 2,775 km2 (Afren, 2013).
Figure 67: Seychelles: Areas A and B
The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may
have to delete the image and then insert it again.
Source: Afren, 2013
Page 114
24 SOUTH AFRICA
24.1
Introduction
The South African energy supply scenario is dominated by coal (see Figure 68).
The National Energy Regulator of South Africa (NERSA) is responsible for implementing
South Africa’s energy plan inclusive of the electricity sector.
South Africa’s upstream oil and gas sector is dominated by the state-owned company
Petroleum Oil and Gas Corporation of South Africa (PetroSA), while the downstream oil
sector is more diversified. Sasol is a pivotal player in South Africa’s energy sector.
PetroSA operates all upstream oil and gas assets in South Africa, along with the GTL plant
in Mossel Bay. The company also participates in upstream projects regionally. It has
purchased a small stake in Ghana’s deepwater Jubilee field and signed an agreement with
the DRC’s Cohydro for joint oil exploration. It has also invested in oil and gas exploration in
Egypt, Nigeria, Gabon, Equatorial Guinea, and Namibia (EIA, 2013e).
Figure 68: SA Primary Energy Supply
Source: Based on EIA, 2013e
Page 115
24.2
Coal
South Africa holds large coal resources and is one of the major producers and is the sixth
largest coal exporter of steam coal in the world. Coal provides around 80% of the primary
energy supply, 93% of electricity generation and is used as a feedstock to manufacture 30%
of total liquids fuel requirements (Cornot-Gandolphe, 2013). About 28% (72 Mt) of total
production is exported. An inefficient transportation network has limited export growth but
this has improved in the last year. Because of South Africa’s heavy reliance on coal for
electricity, as well as its production of liquid fuels from coal, it is the world’s 14th highest
emitter of greenhouse gases (Ramela, 2011). In South Africa’s draft Integrated Resource
Plan the 2030 scenario (policy adjusted) indicates a drop to 65% reliance on coal by 2030
(see Figure 69).
Figure 69: South Africa: Planned Energy Scenario: 2030
Source: IRP 2010-2030, 2011.
South African coal deposits occur in a series of basins in the north and east of the country.
The Karoo basin covers an area of more than 80,000 km2. There are many dolerite dykes
and sills that have intruded the coal and as a result there is a great degree of variation in
rank within the coal.
Page 116
In the west (Vereeniging-Sasolberg and South Rand coalfields) seams of up to 25 m thick
occur whilst in the Witbank, Eastern Mapumalanga, and Highveld coalfields there are up to
five coal seams of which two may be up to 10 m thick. In the Vryheid and Utrecht coalfields
there are also five seams. In general South African coals are high volatile bituminous coals
with high ash and variable sulphur content (Thomas, 2002).
The Molteno-Indwe coalfield has coal of a lower rank than the rest of the country. The
Limpopo and Lebombo coalfields have bituminous coal with high ash content (Thomas,
2002). As the traditional coalfields are mined out attention will be more focussed on the
Waterberg and possibly the Springbok Flats coalfields. Cornot-Gandolphe (2013), estimates
that about $10 b will need to be invested in mining, processing and transport infrastructure to
bring these coalfields into full production.
24.2.1
Reserves and Resources
The actual reserves and resources of South Africa’s coal are not well known. Coal occurs
over a large area covering (9.7 Mha) on the eastern side of South Africa and has traditionally
been divided into 19 coalfields. These are clearly depicted in Figure 70. There is an excellent
summary of the geology and quality of the coal in the coalfields in Jeffrey (2005).
According to the Department of Energy South Africa has proven coal reserves of 48 bt (5.7%
of the world total). Eberhard (2011) indicates a resource figure of 15-55 bt of recoverable
coal reserves. Andruleit and others (2012) who provided the majority of the resource data
used in this report only accord South Africa a reserve of 33.896 bt, whilst the World Energy
Council (2010) reports a proved recoverable reserve of 30.156 bt. They observe that South
Africa’s coal resource assessments remain in a state of flux and there is not yet total
consensus in respect of the tonnages that are currently economically and technologically
recoverable.
An indication of the reserve status of the coalfields (2001 figures, as reported in Jeffrey
2005) is given in Table 7. Note that these figures are all contested, but they nevertheless
give an indication of the relative proportions of “reserve” available and thus give some
indication of the areas where coal will be mined in the future.
Hartnady (2010) argues that all of the previous estimates have been too high. He points out
that since 2003 official estimates for South African coal reserves have dropped from ~48 bt
to ~30 bt. Meanwhile his analysis suggests a value of less than 15 bt may be more realistic
based on strict SAMREC definitions. He suggests that South African “peak coal” will come
as soon as 2020 and that by that time there must already be significant other resources of
energy available for continued growth (Hartnady, 2010).
Page 117
More recently analysts believe the critical coal supply shortage for South Africa will hit as
early as 2015! But this is expected to be due to administrative, financial and transport
barriers rather than a lack of resources.
The Council for Geoscience is currently undertaking a review which was expected in 2012.
Ian Hall, South African Coal roadmap chairman is quoted as saying that the new study
suggests that South Africa still has more than 60 bt of recoverable coal (Creamer, 2013b).
The author has not yet been able to obtain a copy of the report and it is unlikely that a public
version is available yet.
Table 7: Remaining recoverable “reserves”
Coalfield
Witbank
Highveld
Waterberg
Ermelo (Eastern Tvl)
Free State
Vereeniging-Sasolburg
Springbok Flats
Klip River
Vryheid
Utrecht
South Rand
Somkhele and Nongoma
Soutpansberg
Kangwane
Limpopo
Nongoma
Total
Recoverable
(Bredell,
1987)
12460
10979
15487
4698
4919
2233
1700
655
204
649
730
98
267
147
107
nd
55333
ROM Production
“Reserves” (Mt)
Remaining 2000
2320.23
972.49
384.00
101.11
0.22
334.91
0
85.26
81.80
54.47
22.03
15.18
6.11
0.96
0
nd
4388.77
10139.77
10006.51
15103.00
4596.89
4918.78
1898.09
1700.00
569.74
122.20
584.53
707.97
82.82
260.89
146.04
107.00
nd
50944.23
Recoverable
(Prevost, 2009 )
Council for
Geoscience 2013
8509
9475
6744
4388
1708
529
100
541
716
nd
257
146
nd
6
33118
Source: Bredell, (1987), as given in Jeffrey (2005), Prevost (2009), Based on de Jager 1983, updated
24.2.2
Production
In 2007, South Africa had 73 collieries distributed per province as follows: Mpumalanga (61),
KwaZulu-Natal (7), Free State (2), Limpopo (2), and Gauteng (1) (DME, 2007:44 quoted in
Pooe and Mathu, 2011).
South Africa mined 312 Mt of ROM coal in 2006 of which 244.8 Mt was saleable and
177.0 Mt was used for local consumption – chiefly for the production of electricity
(Maleka et al 2010). The 2011 production was in the order of 253 Mt (Andruleit et al 2012),
almost all of it being steam coal. South Africa now ranks as the 7th largest hard coal
producer in the world after China, US, Australia, India, Indonesia and Russia (World Coal
Page 118
Institute, 2011). The major South African producers, accounting for about 80% of production
are: BHP Billiton, Anglo-American, Xstrata/Glencore, Exxaro and Sasol.
24.2.3
Consumption
Domestic consumption reached 181 Mt in 2011. Rising electricity demand amidst poor long
term planning has led to severe power shortages. To meet growing demand, Eskom, is
restarting three mothballed coal-fired power plants with a combined capacity of 3,800 MW
(Cornot-Gandolphe, 2013). It is also constructing two 4,800 MW coal-fired power plants at
Medupi and Kusile, and as a result Eskom’s coal consumption is likely to increase by 50 Mt
by the end of the decade.
Consumption by Sasol for the manufacture of liquids from coal is likely to expand with plans
to increase coal to liquids (CTL) production and reduce oil imports. A state-owned mining
company was created in 2011 which has developed one mine and may develop further coal
mines in the future to provide coal to local consumers.
24.2.4
Coalfields and deposits
24.2.4.1
W itbank Coalfield
Up to 10 seams can be identified in the Witbank coalfield but only four of these are normally
considered as mineable. Seam 3 is generally less than 0.5 m thick and considered
uneconomic. These are Seams 1, 2, 4 and 5 (the seams are numbered from the bottom
(earliest deposited) to the top). Pre-Karoo glacial valleys which are north-south trending
influence seam distribution and thickness, whilst post-Karoo erosion has led to some of the
upper seams including seam 5 and in some places seam 4 to be removed. Seam 1 reaches
2 m thick near Arnot, but elsewhere it is generally considered uneconomic and it represents
only about 2% of the resources of the coalfield. Seam 2, in contrast contains 69% of the
resource and is the most economically important seam (Snyman, 1998). Seam 2 averages
about 6.5 m thick (Spalding, 1999).
24.2.4.2
Highveld coalfield
The Highveld coalfield covers some 7,000 km2 and has seams 1-5 as in the Witbank
coalfield. In general, neither seams 1 or 3 are mineable in the Highveld coalfield. Here seam
2 varies from 1.5-4 m thick (locally up to 8 m in the west and northeast) and consists of lowgrade bituminous coal. Seam 4 is split into 2 (4 upper and 4 lower, with seam 4 lower
providing the bulk of the coal in the Highveld coalfield) (Spalding, 1999).
Page 119
Figure 70: Distribution of South African coalfields
Page 120
24.2.4.3
W aterberg Coalfield
The Waterberg Coalfield, covers an area of about 3500 km2. The coal occurs associated
with the Karoo Supergroup and deposits are complicated by faulted in an east-west direction
paralleling the major Melinda fault line. The coal field is fault-bounded along its northern and
southern margins by the Zoetfontein fault in the north and the Eenzaamheid fault in the
south which form a graben.
The post-depositional Daarby Fault subdivides the coal field into a shallow western segment
that allows open cut mining and a deeper eastern portion where the coal deposits occur at a
depth of more than 350 m below surface (Snyman, 1998). The coal bearing zone is typically
115 m in thickness. The Waterberg coalfield hosts over 40% of South Africa’s in situ
mineable coal reserves and is considered as the major future source of South African coal.
24.2.4.3.1
Grootegeluk M ine
Coal was discovered in this area in March 1920 during water drilling operations on the farm
Grootegeluk 459LQ, 25 km west of the present town of Lephalale. During the period 1941 to
1952, 143 diamond drill holes and two prospecting shafts sunk. In 1955 the Minister of Mines
reserved coal on 29 farms in the coal field for ISCOR (now known as Exxaro) and SASOL.
Two more farms were added in 1961, five in 1964, and a further 89 in 1965. As a result of
this reservation, ISCOR and SASOL were the only two parties qualifying to apply for
prospecting or mining leases in respect of coal over a total of 125 farms in the Waterberg
Coalfield.
The Grootegeluk Coal Mine on the farm Enkelbult 462 LQ, was developed in mid 1970s. In
2008 it had a total coal resource of 5.57 bt. The Medupi six-pack powerstation (Project Alpha
and Project Charlie) was officially named on 20 March 2007. Exxaro was awarded the coal
supply contract for 14.6 Mtpa. The coal supply and off-take agreement (CSA) was signed by
Eskom and Exxaro on 19 September 2008.
24.2.4.4
Boikarabelo m ine
Construction activities at Resgen’s Boikarabelo mine were making good progress, including
the establishment of site infrastructure, roadworks and water and power connections in April
2013. Resgen started construction at the mine in mid-February 2013.
Page 121
Figure 71: Grootegeluk Mine and Waterberg Power Stations
Resgen had secured a third export coal offtake contract with the Noble Group for the supply
of 2.5 Mtpa of coal for 5 years. It had also entered into an exclusive supply chain
management and marketing agreement with Noble under which Noble will manage the
supply chain and marketing of domestic and export coal sales for 35 years.
In the stage 1 development it is targeting 6 Mtpa of saleable coal from its probable reserves
of 744.8 Mt on only 35% of the tenements under Resgen’s control. A rail haulage contract
with Transnet with confirmed allocation to meet export and domestic sales requirements for
Stage 1 of operations had been secured, along with a port access contract sufficient for
Stage 1 export requirements (Greve, 2013).
24.2.4.5
Erm elo Coalfield
In the northern part of the coalfield, seams are numbered A to E with A being the uppermost
seam. In the south the nomenclature for the seams is the same as that used in KwaZuluNatal. The E seam has a maximum thickness of 3 m in the north. The D seam is not
considered thick enough to mine (except in opencast situations). Seam C is complicated by
being split into several plies – in the south the equivalent Gus seam can reach 3m in
Page 122
thickness. The B seam (Alfred) may reach 3 m in thickness and usually consists of dull coal.
The A seam is of low grade and becomes shaly in the south; it is usually less than 1m thick.
24.2.4.6
Kangwane Coalfield
Here coal occurs in the Vryheid Formation (seam 1 at the base of the sequence) and the
Volksrust Formation (Seams 2-8). Seam 1 may reach 10 m thick in places but its distribution
is erratic and it contains low grade coal. The seams dip eastward at 3-20° steepening in the
east, and the region is intensely faulted with north-south striking faults. There are also a
number of dolerite intrusions and as a result the coal has been metamorphosed to
anthracite.
24.2.4.7
Nkom ati M ine
This anthracite mine has historically been a collection of opencast pits, but due to restriction
imposed by surface development is now being further developed as an underground mine.
The mine has extensive resources and a new order mining right to September 2020.
24.2.4.8
Natal Coalfields
ASX-listed coal developer ZYL has decided to significantly reduce its corporate overheads in
South Africa and has retrenched the majority of its South African employees. ZYL has
discontinued its acquisition of the Mbila anthracite project, in KwaZulu-Natal and is looking at
the work requirements to secure the necessary permitting to allow for the development of its
Kangwane projects (de Bruyn, 2013).
24.2.4.8.1
Vanggatfontein
Keaton Energy’s Vanggatfontein colliery delivered 526,034 t of washed 2-seam and 4-seam
thermal coal to Eskom in the first quarter of 2013. Metallurgical coal sales from 5-seam into
the domestic market rose to 25,246 t (de Bruyn, 2013a).
The colliery, situated in in KwaZulu-Natal, had “geological difficulties” during first quarter of
2013 but still dispatched 76,454 t of anthracite to domestic and export customers (De Bruyn,
2013a).
24.2.4.9
Vlakvarkfontein
Continental Coal’s Vlakvarkfontein thermal coal has produced 1.4 Mt ROM coal in the 11
months to the end of May 2013. It produced 0.89 Mt in 2011 and 1.24 Mt in 2012.
Page 123
24.2.4.10
Soutpansberg Coalfield
24.2.4.11
M akhado M ine
Coal of Africa Limited (CoAL has had the results of its DFS and is working towards a funding
structure. The DFS put the cost of the mine at R3.96 b. The mine is expected to produce
2.3 Mtpa of hard coking coal and 3.2 Mtpa of steam coal. This is seen as the first step in
CoAL developing its 8 bt resource.
If all goes well the mine will start producing in 2014. Mining would take place at an average
rate of 12.6 Mtpa ROM over 16 years at an average gate cost of R865 per saleable hard
coking coal tonne. It will be mined as an opencast operation, with the potential for expansion
underground (Creamer media, 2013).
24.2.4.12
Free State Coalfield
African Carbon Energy (Africary) a company started by former Sasol executives Johan
Brand and Eliphus Monkoe, has signed an MOU with an IPP, to build, own and operate a
50 MW combined-cycle gas turbine (CCGT) power plant and buy syngas produced through
underground coal gasification (UCG) (Creamer, 2013).
Africary expects a bankable feasibility study to be in place by year-end. The project may well
be feasible and profitable now that the average annual selling price of Eskom electricity has
risen from 12.98c/kWh in 2001 to 60.66c/kWh in 2012, and still set to increase further
(Creamer, 2013).
Africary has bought the rights to 1.4 bt of coal from BHP Billiton as well as farms within the
300 km2 Theunissen concession for the siting of the proposed CCGT plant. The coal seams
are at depths of 350 m and 450 m in an area where subsidence is legally permissible. The
coal tonnage in the target area is estimated to be about 100 Mt (Creamer, 2013).
If this project proves successful it opens the door to use UCG in many localities across
Southern Africa including Botswana, Zimbabwe, Mozambique and Namibia.
24.2.5
Beneficiation
From the 1970’s South Africa built large “six pack” power stations of 3600 MW or higher
capacity. Two of these the Kendal and Matimbe power stations are dry cooled and these are
the largest dry-cooled power stations in the world. When considering future development it is
important to note that in the Copenhagen Accord, South Africa made a voluntary
commitment to reduce its greenhouse gas emissions below a business-as-usual scenario
(Eberhard, 2011).
Page 124
Although coal is included specifically as a commodity in the South African beneficiation
strategy the fact is that the vast majority of coal suitable for the production of electricity is
being used for such and being beneficiated through the use of the electricity in downstream
processes. In total of the 253 Mt of saleable coal produced in 2011 only 72 Mt was exported.
Local use of coal (by mass) is as follows: Electricity generation, 70%; Coal-to liquids (CTL)
20%, Chemical and other industry, 5%; metallurgical, 3%; and residential and small business
supplied by local merchants 2% (see Figure 72).
In the case of export coal, it is washed before export to improve quality, reduce ash content
and produce a sought after homogeneous product.
Eskom has 13 power stations and there are two new power stations under construction (see
Table 8), but as from 2020 some of the older Eskom power stations will be decommissioned.
The new power stations are the Medupi and Kusile power stations. The Medupi Power
Station units were scheduled to be commissioned at nine-monthly intervals, in line with
international practice, with the first unit was scheduled to be commissioned in 2012 and with
the last unit scheduled for commissioning by 2015. The Medupi power station – the largest
air cooled power station in the world will be run at higher temperatures and pressures than
previous boilers (supercritical design) which will add considerable water and coal usage
efficiency. The power stations will be built to 4,788 MW and 4,800 MW capacities
respectively.
Figure 72: Estimated use of coal in South Africa
Note: excluding exports.
Page 125
Unfortunately the process of construction has been hit by a series of events that speak to
poor planning. According to Eliseev (2013) reporting on the 8th July 2013, the first electricity
from the Medupi power station is only to be expected in the second half of 2014, whilst the
cost of the power station has ballooned by R15 b.
Table 8: Eskom’s current and planned coal fired power stations
Power Station
Arnot
Camden
Duvha
Grootvlei
Hendrina
Kendal
Komati
Kriel
Lethabo
Majuba
Matimba
Matla
Tutuka
Medupi
Kusile
Location
Middelburg
Ermelo
Witbank
Balfour
Hendrina
Witbank
Middelburg
Bethal
Sasolburg
Volksrust
Lephalale
Bethal
Standerton
Lephalale
Delmas
MW
2,040
1,440
3,450
760 (1,200)
1,895
3,840
(1,000)
2,850
3,558
3,843
3,690
3,450
3,510
4,788A
4,800A
Principal coal supply
Exxaro
BHP Billiton
BHP Billiton
BHP Billiton
Anglo Coal
Anglo Coal
Exxaro
Exxaro
Anglo Coal
Exarro?
Anglo coal (47 year commitment)
Note: Bracketed capacity refers to mothballed capacity being returned to production.
A; Not yet in full operation
Source: Eberhard, 2011, Eskom website
After electrical power the majority of the rest of the coal used in South Africa is used by the
Sasol coal-to-liquids facilities. Sasol produces some 160,000 barrels of petroleum per day at
its Secunda plant – this equates to more than 25% of the South African consumption. Sasol
uses about 44 Mtpa of high ash (35%) low calorific value (<21 MJ/kg) coal for its process
(Eberhard, 2011).
Sasol has been involved with a study for a possible $5-7 billion 80,000 barrel per day plant
in the area of the Waterberg coalfield, to use an estimated 25 Mtpa of coal from Exxaro.
Sasol is seeking a range of incentives from government to make this possible.
24.2.6
Challenges
24.2.6.1
Logistics
The rail capacity on the line to Richards Bay is insufficient and there is no ore rail from the
Waterberg coal fields to the ports. Transnet launched an investment program of R300 b
($35 b) in 2012 to upgrade rail and port infrastructure over the period to 2019. The plan
includes a rail link to the Waterberg coal fields. The new line, to be built by 2015, will initially
Page 126
carry around 23 Mtpa. The plan also foresees to raise capacity of the rail line to Richards
Bay to 98 Mtpa by 2019 (Cornot-Gandolphe, 2013).
The ability to get coal to the coast is restraining the further development of the coal sector.
South Africa’s major coal outlet is the Richards Bay Coal Terminal (RBCT), which is privately
owned. The terminal has a 91 Mtpa capacity but the restriction remains on delivering the
coal to the terminal, although this is improving, Transnet could only deliver 68.3 Mt of coal to
be exported through the terminal in 2012 (Creamer, 2013a).
Transnet reports that rail capacity on the Richards Bay line to the RBCT would be increased
to 95 Mtpa by 2018 and investment in the Swazi rail link would take non-coal freight off the
coal line and thus open up more capacity for coal (Creamer, 2013a).
The state of the South African National transport system is very much at the heart of the
apparent deficiencies of the coal industry to supply the required coal to Eskom and to the
RBCT for export. A widely quoted statement from the Department of Transport’s 2005,
National Freight Logistics Strategy is (Ittmann, 2005):
“The freight system in South Africa is fraught with inefficiencies at the system and firm levels.
There are infrastructure shortfalls and mismatches; the institutional structure of the freight
sector is inappropriate, and there is a lack of integrated planning. Information gaps and
asymmetries abound; the skills base is deficient, and the regulatory frameworks are incapable
of resolving problems in the industry.”
24.2.6.2
Licencing and financing
South Africa could be on the verge of a coal supply crisis. Once it has all coal fired power
stations running, the supply of coal could become a real dilemma. Many small scale miners
however are unable to get into production due to turnover times in state departments and, in
some cases not being able to find finance for opening greenfields mines. Furthermore, if
they were operational it is not certain that the road and rail infrastructure could cope with the
increased loads.
One of the major problems mines have is to get all of the government paper work done.
Mining, environment and water legislation is in dire need of an overhaul to enable it to work
smoothly and quickly. Water use licences can take years – there appears to be no recourse
and miners lose both contracts and financing in the interim. Add to this the uncertainty in the
country at the moment as to coal being declared a strategic resource, and what that might
mean for the miner, and you have a recipe for failure.
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24.3
Oil
South Africa has only small deposits of conventional oil. Most of the oil used, is imported
from the Middle East and West Africa and refined locally.
South Africa had proven oil reserves of 15 Mbls as of the end of 2011. All of the proven
reserves are located offshore of southern South Africa in the Bredasdorp Basin and off the
west coast of the country near the border with Namibia (see Figure 65). South Africa’s total
oil production is around 180 kblpd; this is made up by 160 kblpd in synthetic fuels 2 kblpd
crude oil and lease condensate, 4 kblpd natural gas liquids and 14 kblpd refinery processing
gain. Crude oil and lease condensate is produced at the Oribi and Oryz fields, which
PetroSA operates.
South Africa’s offshore Orange Basin may have substantial oil and gas reserves, but Shell,
which has exploration rights over a large area, has made little progress with exploration
(EIA, 2013e).
Figure 73: Estimated use of coal in South Africa
Source: www.PetroleumagencySA.com
24.3.1
Imports
EIA estimates that South African total petroleum consumption was 610 kblpd in 2011. The
majority of crude oil imports are from OPEC countries (see Figure 74), although there do
appear to be some discrepancies in the data. In 2012 the imports from Iran have dropped in
favour, largely, of Angola.
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Figure 74: South African Crude oil imports, 2011.
Source: Based on EIA, 2013e
24.3.2
Value addition
South Africa has the second largest crude oil refining capacity in Africa at 484,547 blpd of
total oil. Egypt at 726,250 blpd is the only African country with a greater capacity. However
this is not sufficient and EIA estimates that South Africa imported almost 80 kblpd of refined
petroleum products in 2010, as a result South Africa is planning to increase domestic
refining capacity (EIA, 2013e).
The South African government is planning to implement new tighter fuel standards by 2017
that would require upgrades at all refineries; however, refinery operators do not want to
upgrade due to low returns on investment. Furthermore, government has increased tariffs on
refined product pipelines to assist in financing the construction costs for a new multi-fuel
pipeline between Durban and Johannesburg.
PetroSA has been advocating the construction of a new 400,000 blpd refinery at Coega to
meet the new fuel standards. According to PetroSA, the refinery could meet the
180,000 blpd shortfall in locally refined diesel and gasoline expected by 2020. Government
has not yet approved the project.
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24.4
Gas
South Africa has only small deposits of natural gas. Sasol produces downstream liquid fuel
products from local coal and natural gas imported from Mozambique.
In April 2011, the government enacted a moratorium on licensing and exploration on shale
resources, but this was lifted in September 2012.
In 2011, South Africa produced 1.27 bcm of natural gas and consumed 4.59 bcm, with the
difference being imported from Mozambique. South Africa has very limited and declining
conventional natural gas reserves. Most of the natural gas is produced from the maturing
offshore F-A field and South Coast Complex fields and sent to the GTL facility in Mossel Bay
via an offshore pipeline (EIA, 2013e).
PetroSA is developing the F-O field, also known as Project Ikhwezi, to sustain gas supplies
to the GTL facility. Reserves are estimated at almost 28 bcm, and the field is expected to
come online in the second half of 2013. The company expects gas production to continue for
six years at the F-O field, but it plans to tap into nearby prospective areas to continue gas
flows to the GTL plant (EIA, 2013e).
PetroSA is also planning to develop the Ibhubesi gas field and expects first production in
2016. Infrastructure constraints limit the role of natural gas in the country’s electricity sector.
Figure 75 shows natural gas production and consumption in South Africa from 2000-2011.
Figure 75: SA natural gas production and consumption
Source EIA, 2013e
Page 130
24.4.1
Shale Gas
According to recent analysis by EIA and Advanced Resources International, South Africa
has 13.73 tcm of technically recoverable shale gas resources. Shell has three pending
exploration license applications and Falcon Oil and Gas Ltd. and Bundu Gas & Oil have one
each. O&GJ reported that Shell plans to spend $200 million to drill 6 wells in the first stage of
exploration pending government approvals. Additionally, Chevron signed a five-year joint
venture with Falcon Oil and Gas Ltd. in December 2012 to explore the area covered in
Falcon’s TCP located in the southern Karoo Basin (EIA 2013e).
24.4.2
Value addition
24.4.2.1
Coal to fuel
Sasol runs the worlds only coal-based synthetic fuels plant outside of China at Secunda. The
company holds majority interest in the Natref refinery, the smallest crude oil refinery in the
country. Sasol has operations all around the world, ranging from supplying petrochemicals in
Asia to using its proprietary Fischer-Tropsch conversion technology to pursue opportunities
to open GTL plants in Uzbekistan, Canada, United States, Australia, China, and India.
24.4.2.2
Gas-to-liquids (GTL)
The PetroSA Mossel Bay GTL plant was commissioned in 1992 and is one of the largest in
the world. The GTL refinery has the capacity of 450 kblpd of oil equivalent through a FischerTropsch Process. The plant produces unleaded petrol, paraffin, diesel, propane, liquid
oxygen and nitrogen, distillates, eco-fuels, process oils and alcohols (EIA, 2013e).
PetroSA may make an investment of $375-510 M for a LNG import facility near Mossel Bay,
during the fourth quarter of 2014, in order to improve gas supply security for the group’s gasto-liquids (GTL) refinery. The project may also include supply to Eskom, to allow it to convert
its Gourikwa open cycle gas turbine peaking power plant, in Mossel Bay, from diesel to gas
(Creamer, T. 2013).
The GTL refinery is currently operating at less than 50% of its 42 kblpd nameplate capacity,
owing to feedstock constraints, which will be partly mitigated later this year once gas begins
to flow from the FO field. However, production from the FO field is expensive and technically
challenging and will also only secure feedstock for the GTL refinery until 2020 (Creamer, T.
2013).
PetroSA is also considering options for transitioning its GTL plant from the production of
fuels to higher-value petrochemicals as its gas feedstock costs continue to rise. This will
especially be the case once supply from the FO field flows from October 2013. Such a shift
Page 131
is partly linked to the development of a new 300 kblpd crude refinery at Coega, in the
Eastern Cape, which would free the GTL refinery in Mossel Bay from its national fuel
security-of-supply obligations. The initiative, dubbed Project Mthombo, could involve an
investment of $9-11 b (Creamer, T. 2013a).
Page 132
25 SOUTH SUDAN
25.1
Introduction
The Republic of South Sudan became Africa’s 55th country on July 9, 2011, following a
peaceful referendum in January 2011. The referendum was foreseen as part of the 2005
Comprehensive Peace Agreement signed by the Government of the Republic of the Sudan
and the then southern-based rebel group, the Sudan People’s Liberation Movement (World
Bank, 2013).
25.2
Coal
South Sudan does not have significant coal reserves.
25.3
Oil and gas
About 75% of Sudanese oil production originates from the South, while the pipeline, refining,
and export infrastructure is in the North (See Figure 76). The comprehensive Peace
Agreement of 2005 did not make provision for a post-independence oil sharing mechanism
or transit fees. Sudan’s government in Khartoum asked for transit fees of $32-36 per barrel,
South Sudan argued that less than $1 per barrel would be reasonable (EIA, 2012a).
As a result of the impasse on transit fees, Sudan began to divert South Sudan’s Nile Blend
crude to its Khartoum and el-Obeid refineries in December 2011. On January 20, 2012,
South Sudan shut in production until a fair deal was reached, or an alternative pipeline built
(EIA, 2012a). This move hurts both countries – the government of South Sudan earning
some 80%-98% and the government of Sudan more than 50% of its revenue from Oil
(Francis, et al. 2012, World Bank, 2013).
The Nile Petroleum Corporation (Nilepet) is the technical, operational & commercial arm of
the Ministry of Petroleum and Mining in the government of the Republic of South Sudan. It
was created to build the national technical capabilities of the Government and to maximize
the oil profit.
Southern Sudan is seeking new ways to get oil to the coast to assist with the issues that they
have with Sudan around pricing. There have been several suggestions and Toyota Tshusho
has submitted a proposal to design and construct a 2050 km oil pipeline from South Sudan
to the new port planned for Lamu in Kenya. Other possibilities include a 1,600 km pipeline
through Ethiopia to Djibouti and a 800 km pipeline to Uganda to connect to the proposed
Ugandan pipeline to take crude oil to Mombasa (Bol, 2012 – see Figure 77).
Page 133
Figure 76: Oil fields and pipelines of South Sudan and Sudan
Source: Francis et al, 2012
25.3.1
South Sudan has proved oil reserves of 3.5 bbl or some 0.2% of the world total (BP, 2013).
Naath resources estimated the oil reserves of South Sudan at 6.5 bbl (Naath, 2012). Despite
considerable natural gas reserves associated with the oil, the gas is generally flared or reinjected.
As with most oilfields details of the reserves are easily available, however, Fatal
Transactions (2008) did publish some figures of “remaining commercial reserves”. These are
shown in Table 9.
25.3.2
Nearly half of the country is covered by oil rights holdings (see Figure 79).
Page 134
In January 2012 South Sudan shut down its oil production, starting with Block 5A. Production
in Blocks 3 and 7 and South Sudan’s oil fields in the Greater Nile Oil Project were gradually
reduced and stopped by the end of January. Water was injected into the pipeline to prevent
clogging. (EIA, 2012a).
Figure 77: Potential Pipeline routes
Source: Bol, 2012
Table 9: Estimated commercial reserves as at 31 December 2006
Block
Block 1,2,4
Block 3,7
Block 5A
Block 6
Total
Original (Mbl)
1686
803
175
331
2995
Remaining (Mbl)
938
779
168
299
2229
Source: Fatal Transactions, 2008.
More than a year after it stopped production, South Sudan restarted production, based on an
agreement reached earlier. This is a part of efforts to avoid an all-out conflict over oil
revenues and border disputes. According to BP (2013) South Sudan produced only 31 kblpd
in 2012. In a September 2012 agreement the processing and transportation costs per barrel
were set at $1.60 and $8.40 (GNOP facility) and $6.50 (Petrodar facility) respectively.
Furthermore, a transit fee of $1 per barrel was agreed to (Agreement, 2012).
Page 135
It is not clear how long the country will take to return to its normal output of 350,000 barrels a
day. The first oil was expected to reach Sudan’s ports by the end of May 2013, according to
Sudan’s state news agency, with output expected to reach 150,000 to 200,000 barrels a day
(BBC, 2013).
South Sudan plans to sell 6.4 Mbls of oil worth $300 M before shutting down its entire
production again by the end of July 2013 due to a row over its alleged support for rebels in
neighbouring Sudan. Juba denies backing insurgents (Green and Abelaziz, 2013).
Figure 78: Producing blocks
Source: Insidekenyatoday (2011)
Total may restart exploration activities on its Block B concession in South Sudan after a gap
of 27 years. Total holds a 32.5% share of Block B, which is located in Jonglei State, near the
Ethiopian border. Any oil found in the Block B concession could feed a pipeline the company
may build from South Sudan to Uganda and on to Kenya’s coast (Reuters, 2012a).
Page 136
Most of the oil produced in South Sudan originates from Blocks 3 and 7 (see Figure 78),
Block 5A, and Blocks 1, 2, and 4. Oil fields in Blocks 1, 2, and 4, collectively known as the
Greater Nile Oil Project, are split between the two countries, since it covers an area that
straddles the North, South, and the disputed Abyei region (EIA, 2012a).
Figure 79: Map of South Sudan oil rights holders
Source: sudantribune.com
Figure 80: Sudan and South Sudan: Historical Oil production by block
Page 137
Source: EIA, 2012a
25.3.3
Exports
25.3.4
Value addition
There is no refinery in South Sudan. The pipeline project in discussion with Kenya includes a
refinery in Lamu (EIA, 2012a)
Naath has entered into negotiations with the government to provide refinery capacity. The
initial program is for two mini-refineries that would only
process diesel fuel and return
unused crude to the source. Later they plan to develop a larger refinery (20,000 blpd) at the
southern terminus of the existing pipeline that goes to a refinery on the Red Sea. The
refinery development will depend on:
a) Sufficient crude from existing production provided to the refineries, and
b) Naath to have some oil concessions in BLK 7 or BLK B to develop its own crude (Naath,
2012).
Page 138
26 SUDAN
26.1
Introduction
See Section 25.1.
26.2
Coal
There are no significant coal deposits known in Sudan.
26.3
Oil
26.3.1
Sudan had proved oil reserves of 1.5 billion barrels at the end of 2012. This represents
about 0.1% of the global total and Sudan has an R/P rate of 50 years (BP, 2013). However it
is thought that there is still a considerable amount of oil that might be located and Sudan has
recently signed agreements with a number of exploration companies to continue with
exploration in the country.
Despite considerable natural gas reserves associated with the oil, the gas is generally flared
or reinjected.
26.3.2
The government of Sudan said it will open six exploration blocks for bidding by international
oil companies. The bidding process for the six blocks was to start on January 15 and the
government aimed to announce winners by May 2013.
On offer are Blocks 14 and 18 bordering Egypt; Block 12B in the conflict-plagued Darfur
region; Block 15, onshore and offshore along the Red Sea; and Blocks 8 and 10, south of
Khartoum and in eastern Sudan (Radiomiraya, 2013).
Resulting from this offer, Sudan has signed exploration and production-sharing agreements
with companies from Australia, Brazil, Canada, Egypt, France, Belgium and Nigeria. The
contracts apply to five of the six blocks, offered in January. Only a block in the Darfur region
failed to gain a contract (AFP, 2012).
Most of the oil produced in originates from Block 6 and Blocks 1, 2, and 4. Oil fields in Blocks
1, 2, and 4, collectively known as the Greater Nile Oil Project, are split between the two
countries, since it covers an area that straddles the North, South, and the disputed Abyei
region (EIA, 2012).
Page 139
For the past 10 years, production has been declining in the Greater Nile Oil Project. The
decline is driven by maturing oil fields and lack of investment,
26.3.3
Exports
Detailed information of exports is not available after the secession of the south. However in
2010 China received some 67% of all exported oil, followed by Malaysia (12%), Japan (11%)
and Indonesia 1% (Figure 81).
Figure 81: Sudan, pipelines refineries and 2010 exports
Source: Classwarfareexists, 2013
26.3.4
Value addition
Sudan has refineries in Khartoum, Port Sudan, and El-Obeid with a total of almost
122 kblpd. The biggest refinery is some 70 km north of Khartoum. It started with a capacity
of 50 kblpd in 2000 as a joint venture between CNPC and the Sudanese government. It
expanded to 100 kblpd in 2006. It can process both the Nile Blend and the more acidic,
heavier Fula Blend of crude oil. The refinery output is mainly for domestic use (EIA, 2012a).
Page 140
26.3.5
Consumption
In 2010, total Sudan and South Sudan consumption was 98,000 blpd; most of which was
used in Sudan.
Page 141
27 SWAZILAND
27.1
Coal
Karoo sediments occur in the east. Two major coal zones occur, each with multiple seams of
low volatile coal or anthracite. The seams dip eastwards at 5-7°. The Upper coal zone tends
to have inferior anthracitic coal whilst in the Lower zone there are moderate to good quality
anthracitic coals. The coalfield is block faulted and intruded by dolerite dykes and sills.
The Mhlume coalfield in central Swaziland produces some anthracite. Coal is also known to
occur in the Maloma area in the south (Thomas, 2002).
27.1.1
The resources in Swaziland are not known, but may be more than 200 Mt (Meyer, 2012). A
“mineable in-situ reserve” of 1 bt is suggested by Spalding (1999). Potentially exploitable
resources occur in 6 seams ranging from 0.5-8m in thickness.
27.1.2
Swaziland has an active coalmine in the Molome area (see Figure 82). It is owned by
Chancellor House and produces anthracite for use in the ferroalloys industry. The main coal
seam here is on average 3 m thick and is good quality anthracite. The number 1 seam
occurs 30 m above the main seam and averages 1.5 m in thickness (Spalding, 1999). There
has been a steady decline in production since 2007 (Meyer, 2012).
Midwinter resources is investigating a project at Emaswati/Mpaka area where they have
prospecting rights over 16 km2. The main seam in this area varies from 1.4-8.5 m in
thickness with an average of 3 m. It occurs at about 200 m depth, with the number 1 seam
lying 17-30 m above it. The number 1 seam has an average thickness of 1.5 m. (Spalding,
1999).
The roof of the main seam is coarse sandstone but the floor is weak shale that breaks up
under heavy mining equipment (Spalding, 1999). The potential resource is in the order of 5585 Mt and a yield of 70-80% can be expected. Washed coal from the deposit is reported to
have a quality in the order of: Fixed carbon, 72%; Calorific value, 29 MJ/kg; Ash, 14%;
Volatiles, 13%; Moisture, 1.3%; Sulphur 0.35%; and phosphorous, 0.01% (Meyer, 2012).
Page 142
Figure 82: Malome Colliery
The Minister of Natural Resources and Energy, Princess Tsandzile announced in 2010 that
the long-‐defunct coal mine at Lubhuku would be reopened in 2011 under the auspices of the
Swaziland Electricity Company (SEC).
It is thought that this coal may be used for the proposed Swaziland 300 MW thermal power
station (Meyer, 2012)
27.2
Oil and Gas
No oil and gas reserves of consequence are known in Swaziland
Page 143
28 TANZANIA
28.1
Coal
There are ten coalfields in Tanzania. These include the Ketewaka-Mchuchuma, Ngaka,
Songwe-Kiwiri coalfields which are the most important. In these coalfields coal occurs in
two zones, the lower of which is of more value. Seams can be as thick as 7 m, but are
normally much thinner. The coals are bituminous with high to low volatiles, high ash and low
sulphur content. Other coalfields are the Rukwa (Galula), Mbamba Bay, Mhukuru, Njuga
and Ufipa coalfields (Spalding, 1999, Thomas, 2002, Mruma, undated).
28.1.1
Tanzania has coal reserves of up to 5 bt according to Energy and Minerals Minister Sospeter
Muhongo. Tanzania produces coal from two mines mainly for domestic use, such as power
generation. It has plans to increase its coal-fired power generation capacity and could also
export more (Reuters, 2013a).
The resources of the Tanzanian coalfields were recently summarised by the geological
survey of Tanzania and have been tabulated here (see Table 10).
Table 10: Coal resources of Tanzania
Coalfield
Mchuchuma-Ketewaka
Ngaka (Mbalawala)
Ngaka (Mbalawala)
Songwe-Kiwira
Rukwa
Mbamba Bay
Mhukuru
Njuga
Status
Indicated
Measured and indicated
Additional inferred
Indicated
Indicated
Inferred
Inferred
Inferred
Resource (Mt)B
536
167
256
147A
71
28
27
23
Source: Mruma, undated, Kibomining, 2013, Intraenergy 2013
Note: A: Kigozi gives 200 Mt as an “identified reserve”
B; Reuters (2013f) indicates that “In July the country also revised its coal reserves to five-billion
tonnes from about 1.5-billion tonnes”
28.1.2
Production
Until August 2011 when the Ngaka operation started, Kiwiri was the only operating mine in
Tanzania, however it was closed last year at which point it was producing about 35 ktpa
(Tanzania, 2013). Indexmundi, however shows that the coal production from Kiwiri has been
much better in the past (see Figure 83).
Page 144
Figure 83: Tanzania coal production
Source: IndexMundi, Tanzania, 2013
28.1.3
Consumption
The majority of the local production has been used for power production.
28.1.4
Coalfields
28.1.4.1
M chuchum a-Ketewaka
This coalfield has two seams that have potential to be mined – one of them exhibiting coking
properties. The coal has CV of 22-27 MJ/kg, ash varies from 8% to 23% and sulphur from
0.5-1.7% (Spalding 1999).
Kigozi (undated) indicates that within the Mchuchuma-Ketewaka deposit there is 159 Mt
proven reserve and that feasibility studies have shown that it would be viable to open an
opencast mine to produce 1.5 Mtpa. Furthermore the technical and economic viability of a
400 MW thermal power station has been established.
28.1.4.2
Ngaka Coalfield
The Ngaka Coalfields comprise the Mbalawala sub basin, the Ngaka Central Basin and the
Mbuyura/Mkapa sub basin. In this coalfield as many as 7 seams may prove workable, two
having a thickness of over 5 m. The coal has CV of 21-28 MJ/kg, volatiles of 22-30%, ash
varies from 8% to 26% and sulphur is up to 0.9% (Spalding 1999).
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28.1.4.3
Ngaka coal m ine
The Ngaka Thermal Coal Project is operated through joint venture with Tancoal Energy
Limited (Tancoal), 70% owned by Intra Energy and 30% by the National Development
Corporation (NDC) of Tanzania. In time it is hoped that this project will supply a 120 MW
mine mouth power station to connect to a new 132 kV transmission line and supply
electricity to Songea and the local region, as well as into the Tanzanian national grid. Once
in operation, Tancoal expects to supply approximately 400 ktpa of coal to the power station
(Intra Energy, 2013a).
At a later stage the plan is to export some 1.5 Mtpa to thermal coal markets in Kenya,
Mauritius and India (Intra Energy, 2013a).
28.1.4.4
Songwe-Kiwiri
Only one or two of the seams are workable. The structure of the area is very complex and
the coal quality is reasonable with a CV of 25-26 MJ/kg, ash at 15% and sulphur of 0.5%
(Spalding 1999).
28.1.4.5
Kiwiri Coal M ine
The Kiwiri mine opened in 1988 with an initial output of 93 ktpa. However, it had problems in
selling its coal because of the high ash content. A mine mouth power station was reduced
from 24 MW to 6 MW. Although the mine was intended to produce 600 ktpa, Spalding (1999)
indicated that due to a variety of market, infrastructure and financing difficulties it was
unlikely to exceed an output of 200 ktpa.
In mid-2012 the Kiwiri mine was shut down, with the loss of 400 jobs, to try to keep
expenses under control. The State Mining Corporation (Stamico) was sole owner of Kiwira
coal mine up to 2005 when it sold its shares to TanPower. But in 2008, the Tanzanian
parliament directed the government to repossess Kiwira. However Stamico is not ready to
develop the mine further (Matsiko, 2012).
28.1.4.6
Kabulo deposit
Intra Energy is investigating this deposit. The current JORC study reports Indicated
resources of 74.7 Mt for seams A2, B and C from the surface to approximately 200 metres
depth. Seam A2 is thickest at an average of 6.2 m and contains 52.8 Mt of 32% ash and
3.5% inherent moisture coal (Intra Energy, 2013a).
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28.1.4.7
Rukwa Coalfield
KiboMining is investigating this coalfield.
The Rukwa coal project comprises two Prospecting Licences and two Prospecting Licence
Applications (PLAs) located in southwestern Tanzania. Within the project area, Karoo rocks
were deposited within the Songwe Basin which is a sub-basin of the larger Rukwa Basin.
They were deposited on Precambrian basement (metamorphic rocks) which now form
flanking uplifted fault blocks to the rift basin. Within the Songwe Basin, the Karoo rocks are
divided into three main units, K1, K2 and K3 of which K2 is the main coal bearing horizon
(KiboMining, 2013).
All of the current resource is located within the Muasa and Kanga Blocks which have been
extensively explored to date. The coal which occurs with the K3 unit in these blocks is
contained within seven coal plies which to the northeast. The seams vary in thickness from
0.5 m to 5 m and have been drilled over a strike length of 9 km. The most recent resource
estimate for the Rukwa deposit was completed in April 2012. The estimate shows that the
total resource is 109.28 Mt (indicated, 71.33 Mt and Inferred 38.05 Mt) (KiboMining, 2013).
28.1.5
Beneficiation
In 2011, China’s Sichuan Hongda Co. Ltd. signed a $3-billion deal with Tanzania to mine
coal and iron ore and build a 600 MW coal-fired power plant.
28.2
Oil
According to EIA (2013f), Tanzania has no proven crude oil reserves. However it does have
considerable gas reserves and remains prospective for oil, and there have been oil shows in
several wells drilled in the past. The government has announced the fourth Tanzania
Offshore (Deep Offshore and North Lake Tanganyika) Licensing Round to be launched on
25th October 2013 (bids to close on Thursday 15th May 2014) (TPDC, 2013).
28.3
Gas
Significant gas discoveries have been made on the coastal shores of Songo Songo Island
and Mnazi Bay (Kigozi, undated). The government has said it plans to have in place new
legislation to regulate natural gas during 2013/14 and this will come after the adoption of the
natural gas policy (Reuters, 2013a).
Britain’s BG Group, its exploration partner and Norway’s Statoil have all discovered gas.
They plan to build a $10 b liquefied natural gas (LNG) terminal (Reuters, 2013c). Sospeter
Muhongo, minister of energy and minerals, has been reported to have said that Tanzania will
Page 147
be a net exporter of electricity by 2015. Tanzania currently holds some 1.22 tcm of gas
reserves and this number may rise to over 5 tcm if new finds prove productive (Reuters,
2013 f)
28.3.1
28.3.1.1
Songo Songo
EIA (2013) mentions a proved natural gas reserve for January 2013 as 6.51 Mcm, and more
than 0.566 tcm of recoverable gas resources in Blocks 1-4. Tanzania estimates a resource
of 1.18 tcm of recoverable natural gas reserves (Reuters, 2013c), however according to EIA
(2013) these have not yet been proven to be commercially viable. Nevertheless according to
Muhongo (2013) Songo Songo gas is being utilised in Dar Es Salaam in the following ways:
 Power generation (414 MW)
 Heating source in industries - 37 industries currently connected
 Compressed Natural Gas (CNG) for domestic use, hotels and vehicles
28.3.1.2
M nazi Bay
The Mnazi Bay Concession is in southeastern Tanzania in the Rovuma basin (see Figure
84). It has two gas fields, Mnazi Bay and Msimbati. One of the five wells in the concession,
MB-1, is already producing gas at a rate of 48-56.6 kcm per day. This gas is piped to the
Mtwara Power Plant to generate electricity for local communities. Full scale gas production
at the Mnazi Bay Concession is expected to start once the 530 km Mnazi Bay to Dar es
Salaam Gas Pipeline is completed. China’s Export-Import Bank is funding the project (EIA,
2013). The full extent of the resources is still not fully known but it appears as if they are
much less than those in Mozambique at this stage.
28.3.1.3
Jodari and M zia
The Jodari and Mzia discoveries in block 1 are looking particularly promising. Ophir (2013)
has been firming up on the discoveries and estimates a possible future resource inventory of
more than 2.1 tcm. Currently field appraisals have led to estimates for Mzia at 169 bcm and
for Jodari at 127 bcm (see Figure 84).
28.3.2
Production
According to EIA (2013) Tanzania produced 849.6 Mcm of dry natural gas from the Songo
Songo field in 2011; all of it was used domestically, about 70% being for electricity
generation.
Page 148
28.3.3
Challenges
The results of the Natural gas finds are not being felt fast enough for either the President or
the people around Mtwara in the south of Tanzania. The President is calling for more speed
in the development and the residents near Mtwara are protesting against the construction of
a 532 km pipeline, financed by a Chinese loan, calling for a bigger share of benefits from gas
development (Reuters, 2013c).
Figure 84: Tanzania Natural gas localities
Source: EIA, 2013
28.4
Electricity Generation
The government said plans were under way for Kiwira and Tancoal to each have power
plants with 400 MW capacity (Reuters, 2013a).
Page 149
29 UGANDA
29.1
Coal
In Uganda there are lenses of lignite located in the Kisegi Valley (Spalding, 1999); otherwise
there are no coal deposits of any significance in the country.
29.2
Oil
Although oil seeps were first noticed in Uganda on the shores of Lake Albert in the 1920’s,
the first commercial discovery was only made in 2006 by Heritage and Tullow in the Lake
Albert Rift basin at the Mputa-1 well. Further discoveries followed at the Waraga-1 and Nzizi
wells and many more after that.
Uganda is aiming for commercial output of oil by 2016 and estimates its crude reserves at
3.5 bbls. Other estimates as high as 6 bbls of oil have been noted, although EIA (2013)
accords Uganda with only 2.5 bbls of proven oil reserves. A refinery is planned in Uganda to
produce diesel, kerosene and heavy fuel oil, and export will probably be via a pipeline
through Kenya. Companies involved include Tullow, Total, CNOOC (EIA, 2013).
29.2.1
Production
Production will be dependent on transport and processing infrastructure being in place. Initial
output is likely be used for local power plants. Major oil production is expected to start in
2017.
The Ugandan government, Total and CNOOC have agreed to build a 30,000 blpd oil
refinery. The government and the consortium (Total, Tullow, and CNOOC) still have to
decide on daily production levels and the export pipeline route. The government prefers a
gradual ramp-up and lower peak output to slow the depletion of reserves, while the
consortium favours production ramping up quickly and peaking at 200,000 blpd or more by
2020 (EIA, 2013).
29.2.2
Legislation
Uganda’s National Oil and Gas Policy was enacted in 2008. The Ugandan Parliament
recently passed two bills to take the policy forward: the Petroleum (Exploration,
Development and Production) Bill and the Petroleum, Refining, Conversion, Transmission,
and Midstream Storage Bill (EIA, 2013).
Page 150
Figure 85: Uganda oil and gas localities
Source: EIA, 2013
29.2.3
Challenges
Wrangling over taxes and over the size of a refinery to process some of the crude has
stalled commercialisation. In April it was agreed that the refinery would process 30 kbls per
day. There are plans for a pipeline possible through Kenya; Uganda currently transports all
of its fuel – imported primarily through the Kenyan port of Mombasa – in road tankers
(Reuters, 2013).
29.3
Gas
18 commercially viable oil and gas fields where discovered from 2006 to 2011, and there are
some 14.15 bcm of proved natural gas reserves in the Lake Albert area.
Page 151
30 ZAMBIA
30.1
Coal
A series of Karoo basins occur in the eastern side of Zambia in the Luano-Lukusashi Valley,
the Luangwa valley and in the west in the Barotse Basin (see Figure 86).
The Sub-
bituminous and bituminous coal occurs in isolated troughs (Spalding, 1999, Bennet, 1986).
Figure 86: Zambia: Karoo Basins
Source: Reimann, 1986
The bituminous, high volatile and high ash coal at Luangwa is up to 1.6 m thick whilst similar
coal at Luano is in thin seams. Some of the coal has coking properties. The Maamba area,
that produces much of Zambia’s coal is also high ash, high volatile bituminous coal in layers
up to 2 m thick. Coal also occurs below younger sediments at Kahare (Thomas, 2002).
30.1.1
Proven coal deposits are estimated to be over 30 Mt. Probable coal resources at Luangwa
North, Luano, Lukusashi in the Luangwa Valley and Kahare, Chunga, Lubaba in the
Western trough system are believed to be in the region of several hundred million tonnes
(Ministry of Lands, 2013).
Page 152
30.1.2
A seam of coal up to 10 m thick near the base of the Karoo succession is preserved in
several partly fault-bounded basins in the Mid-Zambezi. A detailed diamond-drilling
programme together with three shafts enabled the Geological survey to give an assessment
of the reserves and grade of the coal in a number of the basins. The seam is not of uniform
thickness and in many places two separate seams (Seam ‘A’ and Seam ‘B’) have been
recognised.
In recent years the production of coal has virtually come to a stop in Zambia (see Figure 87).
Figure 87: Zambia: Coal Production
Source: Indexmundi
30.1.2.1
M aam ba Coalfield (Siankondobo)
Currently Zambia’s coal comes from Maamba opencast mine, situated in the Gwembe Valley
of the Southern Province some 70 km south of Choma and about 10 km north of Lake
Kariba. Coal was first produced in Zambia in 1966 from the opencast mine at Nkandabwe
and in the following year coal from the present Maamba mine which has been active ever
since (Ministry of Lands, 2013).
Maamba Collieries produced about 600 ktpa of coal in the 1980s, but production has
slumped due to years of undercapitalisation and operational losses. In September 2009,
state owned Zambia Consolidated Copper Mines Investment Holdings (ZCCM-IH), who
owned the mine, sold a 65% share to the Singapore-based company Nava Bharat. The new
owner spent $550 M to acquire a controlling interest, of which $360 M was used to
Page 153
recapitalise the mine. Around $140 M will be allocated to a 300 MW power plan, to be
completed in 2014. To feed it a new mine is being developed at Maamba to produce 350 kt
in its first year and build to a production of 2 Mtpa (Reuters, 2011).
Maamba Collieries Ltd (MCL) estimates their reserves at 140 Mt of high grade steam coal.
The mine upgrade and 300 MW power plant requires a capital outlay of $750 M.
(Maambacoal, 2013). MCL will supply electricity to ZESCO via a 330 kV line which is
currently being built (Modern Mining, 2013)
30.1.2.2
M ulungwa Coalfield
The first investigations of the Mulungwa area was made by Taverner-Smith (1960), who
described the coal seam as 4.3 m thick, with two thin intercalations of mudstones near the
top. A provisional estimate of the resource stands at 10 Mt to a depth of 100 m. Although the
thickness and the grade of the Main Seam at Mulungwa, are both well above the average for
the known coal occurrences in the Mid-Zambezi Valley, the high dip, and the fact that the
Mulungwa River flows along the sub-outcrop are considered unfavourable for opencast
mining. The Mulungwa Coal Project is about 270 km southwest of Lusaka, and some 30 km
from the town of Maamba, in the Sinazongwe District of Southern Province. The project area
is just over 1,100 ha.
A new discovery has been made by African energy resources at the Sinazongwe prospect in
Zambia close to existing coal mines. Multiple coal seams were intersected in all of the
completed core holes and, importantly, these coal seams are open along strike and down
dip. Raw coal calorific values ranged between 10 and 26 MJ/kg. Because the coal is high in
vitrinite, African Energy plans to test the coking properties of the coal as well as undertake
washing yield analysis (UKZambians, undated).
30.1.2.3
Other deposits
In addition to the above, there are also occurrences such as the Maze-Sinakumbe Coalfield,
Nsanje, Siamambo and many others.
30.1.3
Mines
Currently Zambia has two coal mines. Maamba was once government owned and has a
capacity of 1 Mtpa. However, despite the large reserves, the contribution of coal to total
energy has been declining over the years due to the lack of capitalisation in the industry
which resulted in production constraints at the main mine and also the reduced demand in
the mining industry.
Page 154
30.1.4
Consumption
Current estimated demand for coal is about 240 ktpa, however, it is possible to develop the
local market by improving reliability of coal supplies. Major consumers are the Mining
Industry, Nitrogen Chemical of Zambia, the Chilanga Cement Industries, Premium Oil, the
breweries, laundries, the agricultural and the manufacturing sectors (Ministry of lands, 2013).
30.1.5
Export
Although all the coal produced is used locally, the current export demand is estimated at
15 ktpm to Tanzania, DRC and Malawi.
30.2
Oil
Zambia imports all of its oil and petroleum requirements which contribute 9% to the national
energy demand. Established infrastructure for petroleum import and processing include the
1,706 km pipeline which runs from Dar es Salaam in Tanzania to Ndola, a petroleum refinery
with a design capacity of 800 ktpa and the Ndola Fuel Terminal. Finished products are
marketed and distributed by privately owned Oil Marketing Companies. The transport sector
uses the most petroleum (53%) followed by the mining industry (27%) (Ministry of Lands,
2013).
30.3
Gas
Although Zambia has no known conventional natural gas deposits, there appears to be good
prospect for methane gas (Ministry of lands, 2013).
Page 155
31 ZIMBABWE
Coal is the dominant energy resource for Zimbabwe, with the majority of its requirements
being met by Hwange. The Zimbabwean coal deposits occur in Graben Basins trending
northeast-southwest in the Ecca Group of the Karoo Supergroup (see cross section in Figure
88).
Figure 88: Cross Section through the Zimbabwe Mid Zambesi Basin
Source: Moyo, 2012
In the northwest there are the Wankie, Lubimbi and Sessami-Kaonga coalfields (Thomas,
2002). In the south the coalfields are the Bubye and Tuli coalfields which consist of coal of
variable quality, but some low sulphur coking coal has been identified in the Tuli coalfield.
(Thomas, 2002). The coalfields of Lusulu and Hwange contain medium volatile bituminous
coal, whereas the rank of all the other fields in the Mid-Zambezi Basin ranges from subbituminous to high volatile bituminous coal (Hall, 2012).
Page 156
31.1
31.1.1
Coal
The resources of coal in Zimbabwe vary widely in different reports. UNEP, (1997) accorded
the country with 10.6 billion tonnes of coal resources.
Of the 26.6 bt in situ resources (see Table 11) an estimated 10,500 Mt is potentially
extractable (Itinerant, 2013). There is interest in some of the coal as a source of coalbed
methane.
Table 11: Zimbabwe coal resources
Mine/prospect
Estimated
resource Mt
418
142.9
952
532
21,083
1200
400
786
14
96
1,000
60
569
115
26,625
Hwange
Chaba
Western Area
Entuba
Lubimbi
Lusulu
Sengwa
Lubu-Sebungu
Marowa
Sinametella
Sessami-Kaonga
Bubi
Sabi
Tuli
Total
Source: Various sources
31.1.2
Deposits
31.1.2.1
Hwange Coal M ine
Founded in 1899, the mine is still operational but is suffering from a variety of problems both
technical and in regard to cash flow. Hwange Colliery Limited (HCCL) is in Matabeleland
North and is a public listed mining company on the Zimbabwe Stock Exchange as well as on
the Johannesburg and London Stock Exchanges. It is located in the far northwestern corner
of Zimbabwe. Adjacent to the mine is the Hwange municipal town whose population of about
half a million are economically and socially dependent on Hwange Colliery.
The Wankie Main seam, which carries the majority of the resources, is a medium to high
volatile bituminous coal consisting of coking coal in the lower 4 m of the seam overlain by
steam coal for up to 8 m, the coal, in general, has low sulphur. Overall the quality of the
seam deteriorates upwards (see Figure 89), except in sulphur content, which decreases
upwards (Spalding, 1999).
Page 157
Figure 89: Hwange Main seam quality variation
Source: Moyo, 2012
Higher quality coal from the lower portion of the seam is sold after processing through local
distributors for use in various strategic industries such as agriculture, ferrochrome, steel and
allied industries, cement production, brick making and manufacturing.
When fully operational the coke works produce crude tar and crude benzol for further
refining at Zimchem Refineries in Redcliff to produce road tar, creosote, benzene, toluene
and other chemicals. A tar-based product can also be blended for use as the fuel additive to
manufacture MBM explosive at the opencast mine. Excess coke oven gas from the coke
works has, in the past sold to the Hwange Power Station as a diesel substitute. There is a
pipeline in place to transport the gas.
Mining started at Chaba opencast mine in February 2006. The mine was developed as part
of a strategy to provide a consistent supply of low phosphorous coal and to capture new
markets.
The company’s main local customer is the Hwange Power Station, which requires about
180 ktpm. Hwange exports coking coal to Zambia for copper smelting. In September 2011,
Hwange announce that it would start coal exports to India soon at a rate of 480 ktpa.
Hwange has also been trying to set up exports into the DRC, Tanzania, Botswana and
Mozambique (Sourcewatch, 2013b). However, the company has been struggling to keep up
Page 158
with local demand as production has waned (see Figure 90), and it is unclear if any
significant export has taken place, except for the coking coal produced.
Figure 90: Hwange Raw Coal production 1980-2011
Source: Moyo, 2012
31.1.2.2
Entuba Coalfield
The Makomo opencast mine (see Figure 91) was set up in the Entuba coalfields in 2012 with
15 employees, when granted a licence as a part of the Zimbabwean indigenisation process.
The mine currently produces about 200 ktpm and of this they supply 70 ktpm to the ZPC
Hwange power Station and a further 80 ktpm to the Munyati, Harare, Bulawayo thermal
power stations. The mine currently only sells coal within Zimbabwe but they are now in the
position that they produce more than they can sell and are stockpiling coal. The mine now
employs 500 people in a mine with a resource of about 330 Mt leading to a life of mine of
about 23 years.
31.1.2.3
Sengwe Coal coalfield
The Sengwe Coalfield lies in the eastern sector of the Mid-Zambezi Basin. Both Sengwe
south and Sengwe north were comprehensively explored by Rio Tinto from 1973 to 1994.
Only the Main Seam is economic with thickness averaging 14.1 m in Sengwe North and
12.5 m in Sengwe South. Plans to develop a coal-fired power station in the coalfield (the
Gokwe North Project) are currently on hold due to lack of funding (Hall, 2012).
Page 159
Figure 91: Makomo Opencast mine
31.1.2.4
Tuli Coal M ine
The Tuli coal mine, in Beitbridge was apparently producing 100 ktpm of coking coal in 2007,
of which 80% was Exported. The Company was aiming to raise production to 250 ktpm
(Nkala, 2007).
31.1.2.5
Lubim bi Coalfield
The Lubimbi coalfield lies some 80 km to the east of Hwange. Six coal bearing horizons
occur within a 40 to 50 m thick succession. Lubimbi coal is characteristically banded dull and
bright and alternates with mudstone (Hall, 2012)
The Lubimbi Coal Project covers 16,545 hectare in the Gwaai area of the Kariba Coal Basin.
Current drilling on a small part (~10%) of the licence area has suggested an initial in-situ
tonnage of 550 Mt contained within the six main seams (Sablemining, 2013). The deposit is
close to important infrastructure with the rail from Hwange to Bulawayo passing through the
west of the deposit a tarred road from Bulawayo to the Victoria Falls passing across the
southern portion of the deposit. Furthermore, the 330 kV power line to the Midlands passes
through the Lubimbi deposit (Lontohcoal, 2013).
Page 160
31.1.2.6
Lusulu Coalfield
The Lusulu Coalfield lies in the eastern sector of the Mid-Zambezi Basin, extending NE-SW
for 45 km and is 5 km wide on average. The K2-K3 is 40 – 60 m thick with the two most
important seams, the Main Seam and the A Seam, ranging in thickness from 4 to 10 m and
2.5 to 4.5 m respectively (Hall, 2012).
From the work completed at Lusulu by Shell Developments (185 boreholes) in the 1970’s
and 1980’s, the potential for the licence to host a conservative estimate of 1.2 billion tonnes
of good quality coal has been demonstrated.
31.1.2.7
Lubu Project
The Lubu Coalfield occurs about 70 km north of Lubimbi. It occurs in a downfaulted block
covers an area of approximately 15 km by 8 km. The basal Main Seam averages 12.5 m
with a maximum of 18 m thick. The main seam is overlain by mudstone with two coal seams
averaging 2.5 and 2.0 m in thickness. The best quality coal in this coalfield is found towards
the middle of the main seam (Hall, 2012)
The Lubu Coal Project covers 19,236 hectares in the Hwange mining district in northwestern
Zimbabwe and has initial modelled in-situ resource of 786 Mt. A drilling campaign
commenced in October 2010. Results have confirmed the quality and continuity of the
shallow deposit. The model for the Main Seam has been updated and new models
constructed for the laterally consistent 1B Lower and 1C seams within the blocks that have
been drilled to date. There are a number of seams that occur inconsistently, including the 1B
Upper and the 1A seam (Sablemining, 2013).
31.1.2.8
Sessam i-Kaonga Coalfield
The Sessami-Kaonga Coalfield is located 80 km southeast of Sengwa, near the town of
Gokwe. Boreholes have intersected the coal-bearing K2-K3 sequence at depths of 200 to
300 m (Hall, 2012).
31.2
Oil
Zimbabwe does not produce oil and imports about 14,000 barrels per day (Sourcewatch,
2013a).
Page 161
31.3
Coal Bed Methane
Zimbabwe is known to have large resources of coal bed methane.
Tlou has acquired a 49% ownership interest in two CBM Special Grant licenses and an
application in Zimbabwe covering ~3,000km². The Special Grant licenses are contained
within the Mid-Zambezi Basin, an eastern extension of the Karoo-Kalahari Basin of
Botswana
31.3.1
Tinker Mining
Tinker Mining (Pvt) Limited has applied for special grants for exploration and production of
coal bed methane in the Mid Zambezi Basin in the western part of the Zimbabwe. The
application for a 200,000 ha prospect was approved by the Geological Survey Department
and the Mining Affairs Board (Itinerant, 2013).
31.3.2
Zambezi Gas
Zambesi Gas announced in November 2007 that mining would begin in the following month,
once the company had secured clearance from the Environmental Management Agency.
Zambesi Gas was launched in 2003 with the intention of harnessing methane gas for the
establishment of an ammonium nitrate plant (Thondhlana, 2007)
Page 162
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http://www.worldenergy.org/documents/ser_2010_report_1.pdf
Worldcoal, 2013. World Coal Association webpage. Accessed 4 July 2013.
http://www.worldcoal.org/resources/coal-statistics/
Page 178
APPENDIX I.
DEPOSIT SIZE CATEGORIES (KT)
Past production plus RESOURCES in CONTAINED metal/product up to…
Commodity
Chrome
Coal
Copper
Iron
Lead
Manganese
Natural Gas (bcm)
Oil (Mbls)
Phosphate
Vanadium
Zinc
Nickel
Size 5
5,000,000
5,000
1,000,000
500,000
1,000
10,000
5,000,000
1,000
5,000
1,000
Size 4
100, 000
1,000,000
1,000
100,000
1,000
100,000
500
1,000
1,000,000
500
1,000
500
Size 3
10,000
500,000
100
10,000
200
10,000
100
100
100,000
100
200
100
Page 179
Size 2
1,000
100,000
50
5,000
50
1,000
10
10
10,000
50
50
50
Size 1
100
50,000
5
1,000
10
100
1
1
1,000
5
10
10
Size 0
10 or unknown
10,000 or unknown
1 or unknown
100 or unknown
5 or unknown
10 or unknown
0.1 or unknown
0.2 or unknown
100 or unknown
1 or unknown
5 or unknown
1 or unknown
APPENDIX II.
Name
Bemolonga
Tlou (Saber)
Sese
Mmamantswe
Morupule
Moijabana
Masama
Mmamabula
Lechana – Tshimoyapula
Dukwe
Kweneng PL341/2008
Serowe PL 339/2008
Serowe PL 340/2009
Mmamabula central and
south
Sechaba
Mea
Bolau
Luena Colliery 360
Lukuga Coal Basin
Luena Coal Mine
El Maghara
Achibo-Sombo
Yayu
Delgi
Delbi (Dilbi)
Chilga
Moatize
Zambeze
Benga
Ncondezi
Revuboe
Minas Moatize
Jindal
Songo
Zóbuè
Muturara
Tete West
Waterberg
Witbank
Highveld
Ermelo (Eastern Tvl)
Free State
Vereeniging-Sasolburg
Springbok Flats
Klip River
Utrecht
State
Com
LISTING OF DEPOSITS
Size
Province
Madagascar
Botswana
Botswana
Botswana
Botswana
Botswana
Botswana
Botswana
Botswana
Botswana
Botswana
Botswana
Botswana
Bitumen
CBM
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
5
3
5
5
5
5
5
5
5
5
5
5
5
Mahajanga
Central
Central
Kgatleng
Central
Central
Northwest
Kweneng
Central
Central
Kgatleng
Central
Central
Prospect
Prospect
Feasibility
Feasibility
Mine
Deposit
Feasibility
Prospect
Prospect
Prospect
Prospect
Prospect
Prospect
(17.7500)
(22.4200)
(21.4000)
(24.2750)
(22.5150)
(22.9500)
(20.2000)
(23.9800)
(22.2000)
(20.6000)
(23.8000)
(22.2811)
(22.1960)
Longitude
(°E)
45.2000
26.0100
27.2000
26.5000
27.0250
26.0700
26.5000
25.9000
27.2000
26.2300
26.3400
26.8073
26.9600
Botswana
Botswana
Botswana
Botswana
DRC
DRC
DRC
Egypt
Ethiopia
Ethiopia
Ethiopia
Ethiopia
Ethiopia
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
South Africa
South Africa
South Africa
South Africa
South Africa
South Africa
South Africa
South Africa
South Africa
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
4
4
3
0
4
1
0
1
3
3
2
1
1
5
6
4
5
5
2
0
5
3
5
4
7
6
6
5
5
5
5
4
4
Kweneng
Prospect
PFS
Prospect
Prospect
Mine
Mine
Opencast mine
Mine
Deposit
Deposit
Deposit
Mine
Deposit
Mine
(24.0400)
25.8000
(21.1700)
(21.4400)
(9.4425)
(5.7500)
(9.3800)
30.6900
8.3700
8.3000
12.3000
7.5000
12.5000
(16.1500)
(16.1000)
(16.2000)
(15.8500)
(16.0600)
(16.1200)
(15.8800)
26.3300
27.1700
25.7800
28.5300
25.8000
33.3150
36.0000
35.8700
37.0000
36.8000
37.1000
33.7500
33.5300
33.7000
33.9600
33.6666
33.6600
33.0000
Central
Central
Katanga
Katanga
Katanga
North Sinai
Oromia
Oromia
Amhara
Oromia
Amhara
Tete
Tete
Tete
Tete
Tete
Tete
Tete
Status
Mine
Latitude (°)
Tete
Prospect
(16.0000)
34.0000
Limpopo
Mpumalanga
Mpumalanga
Mpumalanga
Free State
Free State
Limpopo
KwaZulu Natal
KwaZulu Natal
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
(23.7000)
(26.1000)
(26.7500)
(26.7500)
(28.0000)
(27.2000)
(24.8000)
(28.2200)
(27.8500)
27.3000
29.2000
29.3000
30.0000
26.7500
27.7000
28.8000
30.0000
30.5000
Page 180
Name
South Rand
Vryheid
Soutpansberg
Kangwane
Limpopo
Somkhele and Nongoma
Swaziland Coalfield
Mchuchuma-Ketewaka
Ngaka Mbawala
Songwe-Kiwiri
Rukwa-Galula
Njuga
Mhukuru Coalfield
Mamba Bay
Maamba Colliery
Mulungwa Coalfield
Lubimbi
Lubu
Sessami-Kaonga
Coalfield
Hwange
Makomo Opencast
Hwange
Sengwa
Tuli
Rovuma Basin
Temane
Pande
Buzi
Mamba Complex
Sofala
Kudu
F-A Gasfield
F_O Field
Songo Songo
Mnazi Bay
Mkuranga
Kiliwani
Msimbati
Jodari
Mzia
Tsimiroro Heavy
Lianzi Block
Block 15
Block 0
Block 14
Block 17
Block 18
Block 31
Block 32
State
Com
Size
Province
South Africa
South Africa
South Africa
South Africa
South Africa
South Africa
Swaziland
Tanzania
Tanzania
Tanzania
Tanzania
Tanzania
Tanzania
Tanzania
Zambia
Zambia
Zimbabwe
Zimbabwe
Zimbabwe
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
4
3
3
3
3
2
3
4
3
3
2
1
1
1
2
0
7
5
4
Mpumalanga
KwaZulu Natal
Limpopo
Mpumalanga
Limpopo
KwaZulu Natal
Zimbabwe
Zimbabwe
Zimbabwe
Zimbabwe
Zimbabwe
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Mozambique
Namibia
South Africa
South Africa
Tanzania
Tanzania
Tanzania
Tanzania
Tanzania
Tanzania
Tanzania
Madagascar
Angola
Angola
Angola
Angola
Angola
Angola
Angola
Angola
Coal
Coal
Coal
Coal
Coal
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Heavy Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
3
3
3
3
3
6
4
3
1
3
0
3
3
3
5
2
Matabeleland North
0
4
4
5
3
2
0
0
0
0
0
0
Ruvuma
Status
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
Coalfield
Deposit
Mine
Deposit
Deposit
Deposit
Deposit
Deposit
Producing
Prospect
Prospect
Deposit
Inhambane
Inhambane
Inhambane
Indian Ocean
Atlantic
Bredasdorp Basin
Project Ikhwezi
Mtwara
Indian Ocean
Indian Ocean
Mtwara
Indian Ocean
Indian Ocean
Mahajanga
Atlantic Ocean
Atlantic Ocean
Atlantic Ocean
Atlantic Ocean
Atlantic Ocean
Atlantic Ocean
Atlantic Ocean
Atlantic Ocean
Page 181
Mine
Mine
Mine
Prospect
Mine
Deposit
Producing
Producing
Prospect
Prospect
Deposit
Producing
Deposit
Prospect
Producing
Prospect
Prospect
Prospect
Prospect
Prospect
Prospect
Prospect
Producing
Producing
Producing
Producing
Producing
Producing
Producing
(26.7700)
(27.7200)
(22.6000)
(25.8000)
(22.3600)
(28.1000)
(28.5000)
(10.3000)
(10.6800)
(9.4500)
(8.6500)
(10.9400)
(11.3000)
(11.3200)
(17.3500)
(17.5612)
(18.4800)
(17.9000)
(18.1000)
Longitude
(°E)
28.5000
31.0000
30.0000
31.8700
29.2000
31.8300
31.8000
34.7750
35.6500
33.6500
32.7000
35.7500
35.3700
34.8500
27.1850
27.0332
27.3000
27.6000
28.8000
(18.3600)
(18.4444)
(18.3600)
(17.6600)
(22.1700)
(12.0000)
(21.7300)
(21.4300)
(20.4400)
(10.8000)
(20.2500)
(26.7000)
(35.0000)
(35.2000)
(8.5500)
(10.3522)
(7.3300)
(8.9000)
(10.3700)
(10.0000)
(9.8000)
(18.1500)
(5.2000)
(6.5000)
(5.4000)
(5.3600)
(7.6000)
(8.0000)
(6.4000)
(7.2000)
26.4300
26.5250
26.4300
28.4600
29.8800
41.0000
35.0000
34.8300
34.4000
41.2000
35.2000
14.5000
21.9000
22.4200
39.5000
40.4022
39.5000
39.6000
40.4200
40.4500
40.4500
44.9000
11.4500
11.2000
11.8700
11.3300
11.7000
11.9000
10.0000
10.5000
Latitude (°)
Name
Sinai Penisula Oilfieds
Western Oilfields
Nile delta/Mediteranean
oilfield
Ogaden Basin
Ngamia1
Sirte Basin
Murzuk Basin
Cyrenaica Platform
Ghadames Basin
Tripolitania
Bredasdorp Basin
Oribi/oryx
Sable
Block 1
Block 3
Block 5A
Block 7
Block 2
Block 4
Block 6
Ugandan oilfield
State
Com
Size
Province
Status
Egypt
Egypt
Oil
Oil
5
4
North Sinai
Matrouh
Producing
Producing
Egypt
Ethiopia
Kenya
Libya
Libya
Libya
Libya
Libya
South Africa
South Africa
South Africa
South Sudan
South Sudan
South Sudan
South Sudan
Sudan
Sudan
Sudan
Uganda
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
4
3
0
5
5
0
0
0
2
0
0
0
0
0
0
0
0
0
5
Mediteranean Sea
Somali
Turkana
Ajdabiya
Murzuq
Al Jabal al Akhdar
Ghadamis
Mediteranean Sea
Agulhas Bank
Bredasdorp basin
Bredasdorp Basin
Unity
Upper Nile
Unity
Upper Nile
Producing
Deposit
Deposit
Producing
Producing
Prospective
Producing
Producing
Producing
Producing
Oilfield
Oilfield
Oilfield
Oilfield
Oilfield
Oilfield
Oilfield
31.0100
31.1000
Longitude
(°E)
33.5000
27.6000
31.9000
5.6000
2.4500
29.0000
24.6000
31.2000
29.6000
33.4000
(35.1000)
(35.3000)
(35.3000)
9.8000
10.0000
8.8000
10.6000
10.2000
9.4100
11.0000
1.9600
31.1000
43.2000
36.0000
20.0000
14.3000
22.0000
11.3000
12.6900
21.7000
21.4000
21.1000
29.7400
33.3300
29.5000
32.7000
29.5000
28.7800
28.6000
31.3500
Latitude (°)
Source: Own Data, Internet articles, Google earth, http://pubs.usgs.gov/of/2009/1045/ASCII/Ni_Cr_PGE.txt,
resources.findthedata.org
Page 182
http://mineral-
APPENDIX III.
CONVERSIONS
238.864 kcal/kg = 1 MJ/kg
429.923 Btu/lb = 1 MJ/kg
35.3107 trillion cubic feet (tcf) = 1 trillion cubic metres (tcm)
1,000 billion cubic metres (bcm) = 1 tcm
Page 183
ABOUT TRADEMARK SOUTHERN AFRICA
Trade Mark Southern Africa (TMSA) is a UKAid supported project
that works with the Common Market for Eastern and Southern Africa
(COMESA), the East Africa Community (EAC) and the Southern African
Development Community (SADC) Tripartite to lower the physical, political
and economic barriers that isolate national economies. The purpose of
the programme is to improve southern Africa’s trade performance and
competitiveness for the benefit of poor men and women.
TMSA’s activities address current constraints to trade. By supporting
regional collaboration through the enabling environment in the COMESAEAC-SADC Tripartite area, TMSA is helping African countries to unleash
their full potential. For more information about TMSA please visit our
website at www.trademarksa.org.
Regional Integration Research Network | TradeMark Southern Africa
+27 12 349 7500
www.trademarksa.org/rirn | info@trademarksa.org

Mineral Resource based Growth Pole Industrialisation

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