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Southern African Energy
24 August 2012
Investment Flows and Challenges
Nicholas Green
Oil & Gas | Standard Bank CIB
Ntlai Mosiah
Power & Infrastructure | Standard Bank CIB
Thokozani Simelane
Africa Institute of South Africa
Vumile Linganiso
Corporate Banking CT| Standard Bank CIB
1 Contents
Section Page
1. Introduction to Standard Bank 2
2. Hydrocarbons 4
2.1 SA Gas Infrastructure 7
2.2 Mozambique LNG 14
2.3 Potential Timelines 18
3. Biofuels & Biomass 20
4. Nuclear Energy 24
5. Renewable Energy 29
6. Geothermal Energy 34
2
Section 1:
Introduction to Standard Bank
3
On-the-ground presence in 18 African countries
Nearly 150 years of experience in Africa
Largest bank in Africa
– Over 40,000 employees in Africa
– Over 8,000 bank branches
Growth on the continent is a key strategic focus area
Market Capitalisation – ZAR 176.4 billion
Investment banking presence across the region and in
key markets strengthened by recent acquisitions:
– IBTC Chartered Bank, Nigeria
– CFC Bank, Kenya
– Opening fully in Angola
– Recently opened in South Sudan
Standard Bank
Angola (20.1 million)
Botswana (2.1 million)
DRC (73.6 million)
Ghana (25.2 million)
Kenya (43.0 million)
Mozambique (23.5 million)
Lesotho (1.9 million)
Malawi (16.3 million)
Mauritius (1.3 million)
Nigeria (170.1 million)
South Africa (48.8 million)
Swaziland (1.4 million)
Tanzania (43.6 million)
Uganda (35.9 million)
Zambia (14.3 million)
Zimbabwe (12.6 million)
Strong product
teams in
Johannesburg,
Lagos, Nairobi and
London
Unrivalled
knowledge of sub-
Saharan Africa
through on ground
presence
On-the-ground
presence in 18
African countries
Standard Bank - Natural partner in Africa
Key points Most comprehensive network in Sub-Saharan Africa
Namibia (2.1 million)
South Sudan (10.6 million)
Source: CIA World Factbook
4
Hydrocarbons
Section 2:
5 African Oil & Gas: Snapshot
Oil & Gas
activities in Africa
dominated by
Nigeria, Angola,
Egypt, Algeria
and Libya
Development of
Oil & Gas
projects
challenging due
to lack of
infrastructure
World oil production 1999
(72.4mn bbl/d)
World oil reserves
(1.3 tn bbl)
North America S. & Cent. America Europe & Eurasia Middle East Africa Asia Pacific
O&G production
Key points Before 2000 Today
World oil production
(83.5mn bbl/d)
World oil reserves
(1.65tn bbl)
O&G
development
projects
Increased exploration
activities across East &
West Africa has
delivered new
reserves
New frontier
exploration in
deep/ultra deep
offshore, and
potentially also shale
Oil & Gas projects financed
by Oil Majors using their
corporate balance sheets
Development of infrastructure
projects catalyst for exploration
and development of O&G
projects
Financing available from
industry players, banks,
investment funds, capital
markets
17%
10%
21% 33%
10%
10% 216
325
141 795
132 41 20%
9%
19% 31%
11%
10% 107
98
70
686
85 40
Source: BP Statistical Review 2012
6
12.6
20.2
5.6
10.2
2000 2010
African Oil & Gas: Unprecedented growth
Accompanying the sustained growth in the
upstream segment requires similar expansion in
downstream infrastructure: Refineries, terminals,
LNG, pipelines
Infrastructure particularly important for where new
production is landlocked
Many new infrastructure projects have already
been approved
International and domestic demand putting
pressure on Africa to increase production level and
to expand infrastructure network
Oil (m bbl/d) Gas (bcf/d)
Production Consumption
7.8
10.1
2.4 3.3
2000 2010
West African
Transform Margin
Pre-salt
play
East
African
gas
Indigenisation
Rift
Valley
Existing refinery
Existing LNG
Planned refinery
Planned LNG
Key points
7
Section 2.2:
SA Gas Infrastructure
8 Gas Infrastructure Snapshot
What will the gas be used for?
How much of the gas to be used domestically?
How much gas can be sold to South Africa and why?
What infrastructure needs to be put in place?
How much capacity can be handled?
What is the timeframe of project implementation?
Key points
Standard Bank
believes that
SADC’s gas
infrastructure is on
the verge of a
significant
transformation
Will SA become a gas economy?
Will coastal diesel fired plants be repowered?
Will SA buy LNG?
Will SA invest in GTL?
How will Namibia use any gas discoveries?
Can cross-border projects succeed?
The Underlying Gas Discussions Implications for South Africa and others
SADC gas infrastructure is relatively poor due to
– Regional energy requirements were historically met by coal resources and imported hydrocarbons;
– Limited historical gas discoveries; and
– There has been a limited route to market
East Africa gas discoveries offer a game changer, coupled with potentially also Namibia and SA shale gas (see
separate presentation)
Background
9
Key Scenario 1 – West Coast Gas
Ibhubesi IPP
(in time, multiple?)
ROMPCO gas pipeline
Utilised and sold by Sasol
in SA
Pande &
Temane Fields
Secunda GTL
South Africa: Potential Gas Infrastructure
Kudu IPP
West Coast Gas
Existing Gas Pipeline
New Gas Source
New CCGT IPP (?)
New Gas Pipeline (?)
Gas to liquids (GTL)
Mossel Bay GTL
3 Bcm (2010) (BP)
Offshore Gas adjacent to
SA & Namibia
SA Gas Infrastructure
Requirements:
– Offshore Pipe
– Gas-fired IPPs
(or Eskom)
Matola Gas Company
Servicing Maputo
10
Scenario 2 – East Coast Gas Key
Significant natural gas
reserves discovered in:
– Mozambique, e.g.
Anadarko, ENI
(c. 77-112 Tcf total)
– Tanzania, e.g.
BG/Ophir/Statoil/Exxon
(15 Tcf)
East Coast Sales Options
– Export GTL
– Pipeline to SA (Moz)
– Liquefied Natural Gas
(LNG), e.g. to Asia
Secunda GTL
South Africa: Potential Gas Infrastructure
East Coast Gas
West Coast Gas
Existing Gas Pipeline
New Gas Source
New CCGT IPP (?)
New Gas Pipeline (?)
Gas to liquids (GTL)
Ibhubesi IPP
(in time, multiple?)
Kudu IPP
Mossel Bay GTL
11
SA Gas Infrastructure Requirements:
– Multiple LNG Receiving Terminals
(Onshore/Floating)
– Repowered OCGT plants (to CCGT)
– New CCGT plants
– New/Expanded gas pipeline
Scenario 3 – East Coast Uses of Gas Key
Gourikwa
Ankerlig
Port Elizabeth
South Africa: Potential Gas Infrastructure
?
Ibhubesi IPP
(in time, multiple?)
Kudu IPP
Repower OCGT
Repower new OCGT
East Coast Gas
West Coast Gas
Existing Gas Pipeline
New Gas Source
New CCGT IPP (?)
New Gas Pipeline (?)
Gas to liquids (GTL)
Secunda GTL
?
Durban
Mossel Bay GTL
12
Scenario 4 – Impact of Shale Gas Key
Shale Gas potential being
evaluated in the Karoo Basin
US EIA est. 485 Tcf of Shale Gas
technical potential
Gourikwa
Durban
South Africa: Potential Gas Infrastructure
?
?
?
?
Shale Gas Potential
Repower OCGT
Repower new OCGT
East Coast Gas
West Coast Gas
Existing Gas Pipeline
New Gas Source
New CCGT IPP (?)
New Gas Pipeline (?)
Gas to liquids (GTL)
Kudu IPP
Secunda GTL
Ankerlig
SA Gas Infrastructure Requirements:
– New CCGT plants
– Multiple gas pipelines
Offshore Gas adjacent to
SA & Namibia
SA Gas Infrastructure
Requirements:
– Offshore Pipe
– Gas-fired IPPs
(or Eskom)
Ibhubesi IPP
(in time, multiple?)
Port Elizabeth Mossel Bay GTL
SA Gas Infrastructure Requirements:
– Multiple LNG Receiving Terminals
(Onshore/Floating)
– Repowered OCGT plants (to CCGT)
– New CCGT plants
– New/Expanded gas pipeline
13 SA LPG Market
Key points Current Supply Infrastructure
Currently, the domestic supply of LPG is produced at the
local refineries
– Refinery capacity is constrained within South Africa at
present, thus negatively affecting LPG production and
delays to market
– Overall production is low and falls short of the current
demand
Albeit there is a global surplus of LPG, local demand outstrips
local supply
South Africa's LPG supplies were particularly constrained by
the lack of sufficient import capacity for the product,
– Costly and will take time to build
LPG is therefore imported to cover the shortfall – a strategic
DoE decision
Current import infrastructure limits imports to 3,600 tonnes
The below schematic outlines the domestic production and
import / storage hubs within the country
Refinery
Import / Storage terminal
Ibhubesi
CALREF
PETROSA
SASOL
ENGEN
SAPREF
Future Potential LPG Production
The proposed Ibhubesi IPP‟s associated gas processing
facility, on South Africa‟s west coast, will produce both
LPG and condensate in the refining process
The Gas processing facility will be able to sell the LPG
and condensate to the market, under the DoE regulations:
– At the maximum coastal retail gate price
Increased local LPG supply will :
– Decrease domestic dependency on LPG imports
Increasing security of supply
– Enable the DoE to reach its LPG conversion targets,
with the current LPG infrastructure and refinery
constraints
Potential to delay import infrastructure expansion
– Assist Eskom in their DSM/load management efforts
– From an infrastructural perspective LPG can be made
available faster than electricity generation and
transmission networks and at substantially lower cost
– Allow for smoothing of supply (stockpiling) to cater to
seasonal demand changes
The condensate produced can be transported to offtakers
countrywide, by road or rail, to be utilised in industry in
various applications
Albeit there is a
global LPG surplus,
local demand
outstrips local
supply
Current import
infrastructure limits
imports to 3,600
tonnes
LPG is imported into
South Africa to
cover the shortfall –
a strategic DoE
decision
14
Section 2.3:
Mozambique LNG
15 East Africa: the new frontier
Tullow:
Albertine Graben basin comprises of five sub-basins
Uganda:
Encountered first oil bearing reservoir in Ngiri-1
Oil discovery at Kasamene - 3 and Kasamene - 3A wells in Block 2
Estimates production of 200,000bopd by 2014/15 horizon
Kenya:
Oil discoveries at Ngamia-1 exploration well onshore Kenya – 10BB
Mozambique: Areas 1 & 4
Anadarko
First deepwater discovery (Feb 2010)
Banquentine well encounters 416ft of gas (Oct. 2010)
Major gas discovery in Lagosta prospect (Dec. 2010)
Discovered 110 net feet of gas in the Rovuma Basin (Feb. 2011)
Major discovery in Lagosta-2 well (Jan. 2012)
Further discovery in Lagosta-3 well (Feb. 2012)
Barquentine-4 in the Rovuma Basin gas discovery (Apr. 2012)
Golfinho exploration well a success (May. 2012)
Recent discovery at the Atum exploration well (Jun. 2012) – Anadarko estimates the area holds between 30 - 60 TcF, with an upside potential approaching approximately 100Tcf
African lakes
Offshore gas
Tanzania:
Statoil, ExxonMobil
First major gas discovery in Block 2 – approx. 6 Tcf (Jan. 2012)
Second Block 2 discovery – 3Tcf (Jun. 2012)
BG/Ophir Energy
Pweza-1 well encounters gas-bearing sands (Oct. 2010)
Chewa-1 makes gas discovery (Dec. 2010)
Chaza-1 well (Apr. 2011)
Jodari-1 well potential for up to 2.5 - 4.4 Tcf of gas (Mar. 2012)
Mzia-1 well discovery (May 2012)
Mozambique
Malawi
Tanzania
Kenya Uganda
Ethiopia
DRC
Key points
Anadarko and ENI
have both been
extremely
successful in their
exploration
activities in Areas 1
& 4 of Mozambique
Mozambique: Areas 1 & 4
Eni
First major gas discovery estimated at 15Tcf (Oct. 2011)
Raised estimates to 22.Tcf of natural gas (Nov. 2011)
Second major discovery estimated at 7.5Tcf (Jan. 2011)
A further discovery of an estimated 7-10 Tcf (Mar. 2012)
Announced a further 7-10 Tcf discovery (May 2012)
Most recent discovery of 10Tcf making the total Area 4 potential of 57-62 Tcf (Aug. 2012)
Approx. 160 Tcf in Areaa 1 & 4
16
0
20
40
60
80
100
120
2007 2008 2009 2010 2011
Vo
l. (
Tc
f)
P
PP
PPP
Unprecedented Reserve Growth
Key points Current Reserve Breakdown
3.5 Tcf Proven reserves in current Pande and Temane fields
which have been in production since 2004
Approx. 87-122 Tcf of Proven and Probable reserves based
on existing discoveries in Areas 1 and 4 (yet to be certified)
Current reserve estimates sit at 160 Tcf of Possible reserves
based on seismic interpretation tied back to current discovery
wells (based on Eni and Anadarko announcements)
– Certification process has commenced
Potential World ranking of Mozambique
Reserves identified
to date would, if
proved up, place
Mozambique in the
top tier of domestic
gas reserves on a
worldwide basis.
Sources: Anadarko, ENI, Standard Bank &ENH Presentation March
2012 (prior to recent discoveries)
Source: BP Statistical Review 2012; ENI; Anadarko; Standard Bank
Rank Country Bcm Mboe Tcf % of
total
1 Russian
Federation 441,000 283,500 1,575.0 20.97%
2 Iran 327,208 210,348 1,168.6 15.56%
3 Qatar 247,660 159,210 884.5 11.78%
4 Turkmenistan 240,464 154,584 858.8 11.43%
5 USA 83,944 53,964 299.8 3.99%
6 Saudi Arabia 80,584 51,804 287.8 3.83%
7 UAE 60,228 38,718 215.1 2.86%
8 Venezuela 54,656 35,136 195.2 2.60%
9 Nigeria 50,540 32,490 180.5 2.40%
10 Mozambique 42,000 27,000 160.0 2.13%
11 Algeria 44,548 28,638 159.1 2.12%
12 Australia 37,184 23,904 132.8 1.77%
13 Iraq 35,476 22,806 126.7 1.69%
14 China 30,156 19,386 107.7 1.43%
15 Indonesia 29,316 18,846 104.7 1.39%
LNG export potential
On a non-associated
gas basis,
Mozambique ranks
even higher
17 LNG: The Key to the Future
Export market is the key to attract funding to develop gas resources Key points
LNG Sales
Contracts
Upstream and
LNG
Development
Funding
Airport Expansion
Port Construction
Rail Network Expansion
Road Improvement
Fertilizer Plant
LNG Revenue
Tax Revenue
Gas-fired Power Plant
Petrochemical Plant
Methanol plant
Enhanced Agricultural Output
Accelerate Infrastructure
Accelerate Industrialisation
and
Increased Access to Electricity
Enhanced Social Investment
Enhanced Industrial Output
18
Private and confidential
Section 2.3:
Potential Timelines
19 19
Build
2010 2017 2016 2015 2014 2013 2012 2011 2020 2018 2019
Source: Anadarko
Source: Standard Bank
2010 2017 2016 2015 2014 2013 2012 2011 2020 2018 2019
Planning
Well Head
Power Plants
New gas pipelines
New GTL plants
New CCGT plants
Planning
Fin
an
cia
l C
los
e
1st Well
Drilled
Mar
2010
Train 1
Complete
Train 2
Complete
2018 2020
Mozambique - LNG
South Africa - Shale Gas
Discussion Timelines
Based on Anadarko
disclosures, our
expectation of the
timing of
Mozambique LNG is
as follows
Standard Bank’s
timing assumptions
around shale gas
are as follows
(dependent on
future IEPs/IRPs)
Drilling & Production
20
Private and confidential
Section 3:
Biofuels & Biomass
21 21 Liquid Biofuels
Maize
– Food price inflation globally
– Initially banned in SA
► Political challenge
– Surplus crops for energy production
► Economically sustainable?
Sugar cane
– Option for sugar companies
– Estimated 10% of fuel supply replaced is
equivalent to a new sugar industry
► 110000 jobs – Source: Who Owns Whom
– High water requirement for new crops
Sorghum
– Previously cultivated, demand decreased
– Drought resistant
Sugarbeet
– Research and development ongoing
Glycerol is a by-product – sell to refiners
Oilseeds are used for protein meal or oilcake,
which is used in animal feeds
Feedstock
Sunflower seed
– Sunflower meal supply on parity with demand
► Market cannot absorb more
Soya Beans
– Soya meal high in protein
► Local supply does not satisfy demand
– Potential to crush locally and import meal
Waste Oil
– Availability?
– Current uses – animal feed, reprocessed
Algae
– Research by Sasol and Rhodes University
Key points Ethanol – Potential Feedstock Biodiesel
22 22 Liquid Biofuels
Stable feedstock availability for an efficient
manufacturing plant capacity
Plant costs differ depending on feedstock used
– Proven technologies
Associated infrastructure costs
– Blending
► Refinery – low cost
► Depot – high cost
– Land
– Refinery upgrades for clean fuels policy
– Storage of output
– Transportation
– Water usage
End user vehicle conversion costs and impact on
economy
Offtake agreements
– Downstream companies
Regulatory framework and incentives
Blending
– 30 May 2012 Petroleum Products Act
amendment allows for the sale of low sulphur
diesel with maximum biodiesel blends of 5%,
10%, 20%, 30% and 50% as well as 100%
which must be clearly labelled B10, B20, B30,
B50 or B100
Government Research support
– Algal biofuel research at universities
– ADEPT Airmotive pre-production
IDC plans to support projects to develop 300
million litres per annum by 2016. Pre-feasibilty
studies indicated cost of circa R5.1bn
Announcement of investment in 90 million litre per
annum bio-ethanol from Sorghum plant located in
Cradock with construction commencement in 2012
Key points
Investment Consideration Government
23 23 Sugar/ Pulp Mill Bioenergy
The need to turn away from the fossil fuel era has opened new opportunities for the use of products from
renewable resources such as biomass or bagasse
Many pulp and paper or sugar mills produce more than half of their energy needs from biomass fuels
recovered from solid wastes.
It is believed that the use of biomass for energy and fuel production will be limited by maximum production
rates and supply of biomass rather than the demand for energy and fuel.
Typically pulp mills also have to eliminate the wood residues generated in the wood handling area, which
consist basically of barks, sawdust or fines from screening.
– They are normally burned in auxiliary boilers. The high pressure steam from both recovery and auxiliary
boilers is sent to the turbo generators to produce power and heat for the mill
– .
Alternatively, sugar companies already use bagasse waste in their own factory production process. It is a
small extension to then use it to produce grid connected electricity
In Europe, biomass is a meaningful contributor to the energy mix. Standard Bank believes each of the SA
sugar and pulp and paper industries can provide a contribution to SA‟s electricity sector
Key points Overview
Many sugar / pulp
and paper mills
produce more than
half of their energy
needs from biomass
fuels recovered from
solid wastes
24
Private and confidential
Section 4:
Nuclear Energy
25 25 Challenges for nuclear financing
General challenges
Novel aspect of NPPs – few new plants for 30 years (other than Russia, China, Korea, Japan)
Limited recent local NPP construction, equipment manufacturing, fuel cycle experience
Design complexities (especially newer technologies), creating construction delays and cost over-runs (Flamanville and Olkiluoto)
Permitting and Licensing; ESIA / public consultation processes and NNR licensing for new plants
Performance risks: NPPs generally underperform on availability basis relative to initial promises
Trade-offs between speed, cost and localisation policy objectives
Supportive regulatory framework, including cost-reflective tariff policies
Potential unseen externalities: „Black Swan” events especially with regards to environmental risk
Large size of debt funding required
Long tenor required, longer than commercial lenders can provide
Duration of Construction period 5-7 years resulting in high IDC
Inability to swap large size, longer tenor ZAR/USD exposures
Currency risk / USD exposure of the SA Economy and inflation
Limitations on the local ZAR funding pool, especially given other power / infrastructure projects and increased
public utility borrowings
Limitations on capacity of National Treasury for funding/support
Limitations of Eskom balance sheet to meet all funding requirements
Foreign funding sources will require Political Risk Insurance, which will invariably have to come from foreign
Governments due to high costs of privately sourced PRI cover
Key points
Financing Issues
Potential unseen
externalities: ‘Black
Swan” events
Novel aspect of
NPPs – few new
plants for 30 years
Limited recent local
NPP construction,
equipment
manufacturing, fuel
cycle experience
Large size of debt
funding required
Limitations on
capacity of National
Treasury for
funding/support
26 26 Potential Sources of Funding
Funding sources largely dependent on project structure
Directly from Government multi-year Budget
Government Bonds (local and foreign currency)
Government Loan Guarantees e.g. USA
Government Concessional Loans from Foreign Governments (Bilateral Gov-Gov loan)
Export Credit funding or guarantees from foreign Government ECAs covering foreign commercial bank loans
Infrastructure Bonds or other securitization structures, with varying levels of Gov support, funded by ring-
fenced tariffs or levies
Eskom Corporate Bonds (local or foreign currency), with varying levels of Gov support
Commercial Project Financing (limited recourse)
No Carbon Credits funding options as Nuclear doesn‟t fall under the UNFCCC carbon offset eligibility rules
Public Sources
Private Sources
Key points
27 27 Addressing Nuclear financing challenges
International Precedent of financing NPPs
USA
– Issuing Government loan guarantees to unlock private funding, two projects already issued after
extensive delays to the process
– New nuclear investments challenged by multiple State utility boards on cost grounds, compared with
shale gas-generated power
France
– Strong Government role in developing a globally competitive nuclear industry (Areva, EDF) but fleet of
similar age to Eskom and problems with Flamanville new-build
China
– Successfully leveraged country partnerships to build domestic nuclear power capacity while concurrently
developing a local nuclear industry into a new global player (Areva/EDF; Westinghouse)
– Limited domestic permitting/licensing challenges
South Korea
– Similar to China - leveraged foreign partnership with technology provider (Westinghouse/Combustion
Engineering) to develop local industry and home-grown nuclear technology IP
Abu Dhabi
– New SOE procured (with impressive speed) a single foreign partner to effectively build/operate a nuclear
fleet, with limited local nuclear industry capacity
UK
– Nuclear renaissance discussed since mid 2000s. Potential nuclear PPPs now more likely to be executed
through integrated utilities
New nuclear also under discussion/procurement in Brazil, India, Thailand and Turkey
28 28 Implications of financing strategy on localisation
Speed, cost, liquidity and localisation trade-offs
South Africa has suffered from a declining nuclear industry capability
– Some capability retained within power generation (Koeberg) and Research/Commercialisation (NECSA)
South Africa’s Localisation objectives:
Re-establish the local nuclear industry, including: Nuclear Fuel Cycle; component manufacturing; NPP
Balance of Plant construction; NPP O&M, research and commercial nuclear products
Seek new export markets arising out of the above
Thereby creating sustainable jobs, skills and foreign exchange earnings.
Challenges:
Technology of nuclear island needs to be imported
– Significant non-nuclear equipment and services (boilers, turbines etc.) also needs to be imported (initially,
until sufficient local manufacturing capability is established)
Limited local (O&M) capability increases reliance on foreign partners and thus increases foreign funding
requirements (especially in a PPP-type scenario with foreign equity investors)
Limited local engineering/technical capability to construct NPPs
– Fleet strategy needed to allow for local skills development over time
Limited domestic sources of funding
– Foreign funding (e.g. ECA) is often linked to the import of foreign equipment
Interest During Construction is a key driver of costs.
– Controlling costs through faster construction period would challenge localisation in the first few units
Key points
29
Private and confidential
Section 5:
Renewable Energy
30
Key points
SA Renewables Sector
Introduction
…The IPP
Procurements
Programme, which
was released on 3
August 2011, relates
to renewable energy
IPP’s and uses the
tariffs as a cap, for a
competitive bidding
process
IRP 2010 has
significantly
increased
disclosure of SA’s
material power
challenges…
South Africa is becoming one of the world‟s most exciting renewables markets, adopting renewables late but with a
high growth rate
IRP2010 is the SA Government‟s 20 year energy master-plan, issued for public consultation in October 2010, Cabinet
approved on 16th March 2011 and promulgated on 6th May 2011.
42% (17.8 GW) of new generation in IRP 2010 is proposed to come from renewable energy - 8.4 GW from solar PV, 1
GW CSP and 8.4 GW will come from wind;
– Cogeneration being excluded from the new build options
Standard Bank believes new build wind will achieve SA grid parity with the blended wholesale tariff by 2015/2016 and
new build solar may achieve grid parity by 2018/2019. NT is expected to introduce carbon taxes in the near future,
wherein the exposure of the blended Eskom portfolio exposure is an additional R0.06 – R0.10 kWh1
– This will further boost renewable energy (no CO2 charge) competitiveness within SA
REFIT was the planned renewables route to market. This has been replaced by the IPP Procurements Programme
(IPPPP), which was released on 3 August 2011. This Programme relates to renewable energy IPP‟s and uses a
revised tariff as a cap, for a competitive bidding process.
The Third Bid Submission Date is currently set for 1 October 2012, the Preferred Bidders announcement expected
10 December 2012 and the projects reaching financial close on 1-12 July 2013.
– Standard Bank expects these indicative dates to be pushed back further, due to the closing of the First Round transactions being pushed back, thus delaying the Third Round Submission timeline.
1 Standard Bank Calculations
31 31
Key
Kusile
Medupi
Thyspunt
Bantamsklip
Koeberg
Ibhubesi
Onshore wind in the Eastern / Western Capes
Strong potential
Natural Gas deposits
found on the west
coast of South Africa
Piped onshore and
used as a feedstock
for Gas-fired power
plants
Shale Gas potential being
evaluated in the Karoo Basin
North-Eastern SA renowned for large coal deposits
3 potential new nuclear sites
ROMPCO gas pipeline
Utilised and sold by
Sasol
Mozambique SA has exceptional DNI
levels
High Solar PV, CPV and
CSP potential
Gas-fired Power
Wind Power Potential
Coal Power Potential
New Nuclear Sites
New/Discard Coal
New Gas
Solar Power Potential
CCGT/Shale Gas Potential
Existing Gas Pipeline
Secunda
Potential New Electricity Generation
Bagasse/ Paper Pulp
Cogen Potential
Bagasse/Paper Pulp Cogen Potential
Geographical Overview
32 32
Key points
The promulgated IRP2010 features the below energy mix
targets for 2030, in terms of new build:
Nuclear 23%
Coal 15%
Imported hydro 6%
Peaking OCGT 9%
Natural gas 6%, and
Renewables 42% or 17,800MW, of which:
– PV: 8,400MW
– CSP: 1,000MW
– Wind: 8,400MW
IRP 2010
Overview Consultation Process
The consultation process that ensued after the publishing
of the draft IRP2010 allowed for stakeholders to address
their concerns and make suggestions (479 submissions
received). The below two graphs depict the major
impact that the process had on capacity sources:
Afte
r co
nsu
ltatio
n p
roc
es
s
Pre
- c
on
su
ltati
on
pro
ce
ss
In context
Changes to the IRP2010 include:
The increased allocation of Renewables to the overall
energy mix plan for the 20 year period
Reduction in planned initial allocations of Peak-
OCGT and an increase in Natural Gas-Fired CCGT
Reference to domestic and imported gas
Reference to prompt decision-making needed to
implement natural gas-fired power by 2019-2011
(711 MW)
IRP2010 is a
landmark public
policy document
that is shaping the
SA energy
landscape
Further versions of
the IRP will be
issued on an
ongoing basis, e.g.
IRP 2012, 2014 etc
33 33 Tariffs - Grid Parity is nearing
Tariff Paths: IRP 2010 vs. Medupi/Kusile vs. Renewables vs. Cogeneration Key points
SA electricity tariffs
are increasing at a
fast rate from a low
base
The YELLOW line is the Policy-Adjusted Scenario („‟PAS’‟) from IRP 2010 (nominal money). The RED line is the PAS from IRP
2010 (nominal money), plus a potential price increase resulting from the proposed carbon tax
The GREEN and BROWN lines are potential tariff paths for Medupi/Kusile (calculated from public information), calculated with and
without carbon taxes. The costs of each project are highly material in terms of Eskom‟s assets and lead to Eskom envisaging two
further 25% tariff increases over the 2013-2015 period, before inflationary increases are expected
The BLUE line is the BD2 wind IPPPP average price indexed at 5.7% p.a
The GREY line is the BD2 solar PV IPPPP average price indexed at 5.7% p.a.
As cogen example, the PURPLE line is the COFI Woodchips expected tariff path indexed at 5.7% p.a.
Clearly, in the medium to long-term, Renewables is set to become highly competitive in the SA energy space.
Note the central IRP
projections exclude
the introduction of
Carbon Taxes (dealt
with as a scenario
although scheduled
to be imposed from
2012)
In the medium to
long-term,
Cogeneration from
Bagasse is set to
become highly
competitive in the
SA energy space.
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Eskom National Blended Tariff (as per Policy-Adjusted Scenario) + Carbon Tax
Eskom National Blended Tariff (as per Policy-Adjusted Scenario)
Onshore Wind (BD2 average price)
Kusile + Enviromental Levy + Carbon Tax
Kusile + Enviromental Levy
Medupi + Enviromental Levy + Carbon Tax
Medupi + Enviromental Levy
Solar PV (BD2 average price)
Cogeneration - Woodchips
ZA
R / k
Wh
34
Private and confidential
Section 6:
Geothermal Energy
35 35 Geothermal Potential in Africa
Kenya Challenges
Kenya is endowed with geothermal resources mainly
located in the Rift Valley
It is estimated conservatively that the Kenya Rift has a
potential of greater 2000 MWe of Geothermal Power.
– Exploration first started by drilling 2 wells in 1956 in
Olkaria I - followed by increased interest in the „70s
Geothermal power currently makes up about 15% of
Kenya‟s electrical power generation – and this is set to
increase
The main problem hindering Geothermal Power
development is one of high upfront costs:
– Feasibility studies
– High Risk
– Deep drilling costs
the particular skills set needed to expand the industry is
often lacking, thus inhibiting uptake and growth
Geothermal Energy
to Meet 30% of
Kenya’s Electricity
Needs by 2030
Key points
Rwanda is to start
Geothermal energy
drilling in December
2012
Geothermal in South Africa
There is, currently, no large-scale geothermal
production in South Africa, since coal is abundant and
relatively cheap, supplying the largest part of the
country‟s energy requirements
South Africa‟s geology is such that the heat is very
deep and requires significant drilling to obtain clear
feasibility
Additionally, there are limited geo- thermal skills within
South Africa
Applications in South Africa would likely be smaller
than the larger plants gaining traction in Kenya and
Rwanda
36
Private and confidential
Title slide – for on-screen presentations only
Prepared for Client Name
Your name here
Date
Nicholas Green
Oil & Gas | Standard Bank CIB
Thank You
Questions...
Ntlai Mosiah
Power & Infrastructure Advisory | Standard Bank CIB
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