southern african energy - pmgpressure on africa to increase production level and to expand...

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Southern African Energy

24 August 2012

Investment Flows and Challenges

Nicholas Green

Oil & Gas | Standard Bank CIB

[email protected]

Ntlai Mosiah

Power & Infrastructure | Standard Bank CIB

[email protected]

Thokozani Simelane

Africa Institute of South Africa

[email protected]

Vumile Linganiso

Corporate Banking CT| Standard Bank CIB

[email protected]

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

http://markosun.files.wordpress.com/2012/04/south-sudan-flag.gif

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


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


East Coast Gas

West Coast Gas


New Gas Source

New CCGT IPP (?)



Ibhubesi IPP


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


?

Ibhubesi IPP


Kudu IPP

Repower OCGT

Repower new OCGT

East Coast Gas

West Coast Gas


New Gas Source

New CCGT IPP (?)



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


?

?

?

?

Shale Gas Potential

Repower OCGT

Repower new OCGT

East Coast Gas

West Coast Gas


New Gas Source

New CCGT IPP (?)



Kudu IPP

Secunda GTL

Ankerlig


– New CCGT plants

– Multiple gas pipelines

Offshore Gas adjacent to

SA & Namibia


Requirements:

– Offshore Pipe

– Gas-fired IPPs

(or Eskom)

Ibhubesi IPP


Port Elizabeth Mossel Bay GTL


– 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


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


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


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


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


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 geothermal skills within

South Africa

Applications in South Africa would likely be smaller

than the larger plants gaining traction in Kenya and

Rwanda

36


Title slide – for on-screen presentations only

Prepared for Client Name

Your name here

Date

Nicholas Green

Oil & Gas | Standard Bank CIB

[email protected]

Thank You

Questions...

Ntlai Mosiah

Power & Infrastructure Advisory | Standard Bank CIB

[email protected]

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