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]
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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
– 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.
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