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19 21 April 2010
BofA Merrill Lynch London E&P conference 2010
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Exploration 22
Conclusions 27
Current projects 15
Executive summary 4
Agenda
Appendix 29
Investor Presentation3
www.afren.com
Agenda
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Investor Presentation4
www.afren.com
Executive summary
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Strategy
The Opportunity set: Sub Saharan Africa
64
Developed 2P
Undeveloped 2P
Contingent
Prospective
Afren Net Reserves & Resources(1,167 mmboe net)
1,054
27
22
1.2.3.4.5.6.7.8.9.
10.11.12.13.14.
15.
Block CI-11Block CI-01Lion Gas PlantKetaOkoroSetuOPL 310OPL 907OPL 917EbokOfaOkwokBlock 1La Noumbi
OML 115
Africa
Reserves & ContingentResources Growth(Certified)
100
80
40
mmboe
20
60
120
1 2
34 7 5 6
11
8 9
10 12
13
14
15
Investor Presentation5
www.afren.com
12
0
8
4
Average up-frontentry cost
Averageappraisal cost
Average regionalacquisition cost
Total AFRentry cost
09 10 11 12
30,000
50,000
70,000
boepd
0807
10,000
Total: 50 billion barrels
PROVED GAS RESERVES
Total: 219 Tcf
Nigeria
Angola
Equatorial Guinea
Congo
Gabon
81%
Source: Waterous & Co, OPEC Annual Statistical Bulletin 2003,BP Statistical Review of World Energy
Nigeria
Angola
Equatorial Guinea
Congo
Gabon
ProductionGrowth
US$/2P bblAcquisition &Development
Executive summary
0
2007 2008 2009
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Country Acquired WI (%) Operator Local Partner Work Prog.
CTE DIVOIRE
1. Block CI-11 Q3 08 47.96% Afren PETROCI
2. Block CI-01 Q3 08 65.00%(1) Afren PETROCI
3. Lion Gas Plant Q3 08 100.00% Afren PETROCI
GHANA
4. Keta Q4 07 68.00% Afren GNPC
Country Acquired WI (%) Tech. Operator (3) Local Partner Work Prog.
NIGERIA
5 & 6. Okoro Setu Q2 06 50.00%(2) Afren Amni
7. OPL 310 Q4 08 70.00% Afren Optimum
8. OPL 907 Q1 08 41.00%* AGER(4) GEC
1
Cte dIvoire Ghana
2
3
Nigeria
1310
65
711
8 9
Asset base summary
4
12
Investor Presentation6
www.afren.com
. .
10. Ebok Q1 08 50.00%(2)
Afren Oriental11. Ofa Q2 07 32.50%(2) Afren IEL
12. Okwok Q3 09 56.00% (2) Afren Oriental
13. OML 115 Q1 10 45.00%(5) Afren Oriental
NIGERIA SO TOM & PRINCIPE JDZ
14. Block 1 Q1 05 4.41% Chevron
Country Acquired WI (%) Operator Work Prog.
CONGO (Brazzaville)
15. La Noumbi Q2 06 14.00% Maurel et Prom
15
Congo
Gabon
Production Exploration Appraisal/Planned development Under review
* Held through AGER joint interest venture in which Afren owns 50%. (1) 65% direct interest and 15% additional right. (2) Share of Profit Oil after recovery of costs. (3) Note on the Okoro Setu Project, Afren is the technic al service provider to Amni, the named operator. On the
Ebok Project, Afren is the technical service provider to Oriental Energy, the named Operator. (4) Afren Global Energy Resources. (5) Assumed effective average working interest.
14
Executive summary
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2009 results highlights
Stable, cash generative production stream
(average production of 22,100 boepd in 2009)
Growing reserves base (100% appraisal success at Ebok)
Portfolio growth: OPL 310, Okwok and OML 115
Indigenous platform: First Hydrocarbon Nigeria Management reserves supported by updated NSAI independent
assessment
Strengthened balance sheet
FD appointed
Established Platform
Investor Presentation7
www.afren.com
80% of proved west African reserves in Nigeria
Industry restructuring Major IOCs under increasing pressure
Proven fields overlooked / remain undeveloped
The Opportunity
Outlook Production growth (Ebok to exit 2010 at 35,000 bopd) Organic reserves growth (E&A wells on Ebok/Okwok/OML 115/OPL
310)
Inorganic reserves growth (strategic positioning in Nigeria)
RBL facility secured up to US$450 million
Executive summary
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2009 Highlights
22.1 kboepd (+470%)(2008: 3.9 kboepd)
US$336 mm (+680%)(2008: US$43 mm)
2007 2008 2009
2007 2008 2009
0
25 kboepd
US$ mm
0
350
Turnover
Production
Investor Presentation8
www.afren.com
US$278 mm (+US$305 mm)(2008: -US$27 mm)
2007 2008 2009
0
350 US$ mmOperating cashflow
US$51 mm (+US$148 mm)(2008: Loss US$96 mm)
2007
2008
2009
-50
50
US$ mm
Normalised net income
Executive summary
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Reserves and production outlook
40,000
50,000
60,000
70,000
boepd (average)
Okoro
CI-11
Ebok(Phases 1&2 only)
NSAI 2P Reserves and Contingent Resources
113 mmboe
64.2
26.9
21.6
2P Developed
Contingent Resources
2P Un-developed
Investor Presentation
0
10,000
20,000
30,000
H1 2010 H2 2010 H1 2011** Okoro cost recovery achieved, reverting to 50% Afren economic share
NSAI Prospective Resources1,054 mmboe
411
364
92
80
15
57
35
Keta
OPL 310
OML 115
Ebok
CI-01
La Noumbi
JDZ Block 1
Executive summary
www.afren.com
10
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High impact exploration
Exposure to the west African Transform Margin andUpper Cretaceous fairway
Offshore south east Nigeria
Investor Presentation11
www.afren.com
Upper Cretaceous fairway
Afren acreage
Executive summary
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2010 drilling schedule and work programme
ASSET ACTIVITY J F M A M J J A S O N D
Ebok Phase 1 Field development
Ebok deep Exploration drilling
Okoro Infill drilling
Ebok WFB Field development
Okwok Appraisal drilling
OML 115 Exploration drilling
Investor Presentation12
www.afren.com
CI-11 infillInfill drilling
(contingent)
OPL 310Seismic reprocessing
& electromagentics
OPL 907/917 Seismic reprocessing
CI-01Electromagnetics and
3D seismic
Keta Block Prospect selection
Executive summary
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2010 Capital budget
US$198 mm capex invested in 2009
(excluding acquisitions)
2010 capex budget focused on Ebok
development in Nigeria
Exploration capex to test Ebok Deep andOML 115 (assume carry on OPL 310)
Benefits of accelerated Ebok capex on
2011 cashflow
0 100 200 300 400
2009
2010
2008
Budget
US$430 mm
US$289 mm
US$198 mm
500
Investor Presentation13
www.afren.com
Appraisal and
development:
US$350 mm
Non drilling E&A:
US$20 mm
Ebok:
US$310 mm
Okoro:
US$40 mm
2010 Capex budget US$430 million
P&D Exploration
Exploration
drilling:
US$60 mmOkwok: US$30 mm
OML115: US$30 mm
Other: US$20 mm
Executive summary
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First Hydrocarbon Nigeria
Onshore
1000
1500
2000
2500
3000
3500
4000
Liqu
idsProduction(000b/d)
500
02000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020
2006 Unrest begins
Shelf Deepwater with FID Deepwater without FID WM View in 2005
Nigeria
shut-inproduction
Structural reform of the Nigerianpetroleum industry
Source: Wood Mackenzie
Emphasis on development of a financially
autonomous NOC
Major IOCs most affected by proposals
Government review of legacy contracts
Recognise and incentivise indigenous
ownership
Investor Presentation14
www.afren.com
ExxonMobil Ebok precedent
FHN indigenous vehicle
Source: IHS Energy data
20
30
40
50
60
10
0
NoofFields
Original Reserve Size Distribution
Oil
Gas
Provedu
ndevelopedfields
>5000
2500-5000
1000-2500
500-1000
250-500
100-250
50-100
25-50
10-25
5-10
1-5
0-1
Unknown
Reserves Size (mmboe)
Afren recognised independent in Nigeria
Established track record Transformational opportunities
Executive summary
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Investor Presentation15
www.afren.com
Current projects
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Okoro development and operating track record
Q3 2008 reservoir model Green field development project
First oil achieved within two years of entry
Successfully operated 7 development and
2 appraisal wells
2 infill wells in 2010
0
4,000
8,000
12,000
16,000
20,000
24,000
28,000
32,000
36,000
40,000
0 1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
15,000
16,000
17,000
18,000
19,000
20,000
21,000
22,000
23,000
24,000
25,000
26,000
27,000
28,000
29,000
30,000
31,000
Cumulative Oil Production, MSTB
OilRate,
STB/D
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
Watercut,fra
ction;GOR,M
scf/STB
FOPR
Observed Daily Rate STB/D
FWCT
Observed WCT %
Actual oil production
Actual water cut
Investor Presentation
Two infill wells
targeting Lower
Sand B interval
mid 2010
0
4,000
8,000
12,000
16,000
20,000
24,000
28,000
32,000
36,000
40,000
OilRate,STB/D
0 1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
15,000
16,000
17,000
18,000
19,000
20,000
21,000
22,000
23,000
24,000
25,000
26,000
27,000
28,000
29,000
30,000
31,000
Cumulative Oil Production, MSTB
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
Watercut,
fraction;GOR,Mscf/STB
Q4 2009 reservoir model
Current projectswww.afren.com
16
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NorthSouth
EQUATORIAL GUINEA NIGERIA
Undisturbed
Enang Ubit Akam ShorelineZafiroE. LubaAlba Estrella
Compressional Translational Extensional
Ebok / Okwok /OML 115
South East Nigeria production hub
Investor Presentation17
www.afren.com
Pleistocene
Benin Sands
D-Series
Qua Iboe
Biafra Sands
Isongo
Diapiric Shale
Source Shale
Oligocene
Eocene
Seep
Gas
Condensate
Oil
Top Mild Pressure
Top Hard Pressure
Not to scale
Current projects
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Production, appraisal and exploration upside
Independently certified Ebokreserves and resources (NSAI)
267 mmbblstotal Ebok 108
43
Investor PresentationCurrent projects
www.afren.com
18
reserves and
resources
53
16
47
2P Reserves
North Fault Block
D2 Upside Extension
West Flank Qua Iboe
Ebok Deep
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Ebok Okwok- OML 115 area resource potential summary
350
400
Gross mmbbls
52
595206
450
500
550
600
Investor Presentation19
www.afren.com
0
50
100
150
200
250
Ebok 2P Okwok 2P* Okwok AFR techcase 2P
Total area 2P Ebok Upside Okwok Upside** Total UnriskedReserves &Resources* Pre acquisition gross 2P reserves estimate, Okwok reserves not yet independently reviewd
** Assumes one prospect only in Qua Iboe
OML 115
108
20
50 178
159
Current projects
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Ebok field development
Ebok WestWellhead
Ebok CentralWellheadPlatform
FSOMoored within70m of CWHP
Investor Presentation20
www.afren.com
135 feet of Water50km Offshore
a orm
8 Production line
6 Water injection
ESP Power & control cable
4 Test linePower &
control cable8 Produced water
8 Produced line
4 Gas line
Current projects
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Ebok / Okwok / OML 115 Exploration and appraisal targets
Ebok Deep Multiple structural closures identified underlying the existing
D series reservoirs
Target selected: Biafra Formation channelised sands
Prospect identified: 30 mmbbls
Q2 2010
Okwok appraisal Optimally placed well to define minimum economic field size
Investor Presentation21
www.afren.com
Q3 2010
OML 115 D Series reservoirs proven at Ebok and Okwok present with
additional deeper potential also identified Fluid substitution work at Ebok and Okwok suggests amplitude
bright spots indicate oil (Biafra / Isonga / Qua Iboe) reservoirs
Q3 2010
Current projects
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Investor Presentation
Exploration
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Exploration portfolio
CTE DIVOIRE - CI-01
Working Interest (65%)
Rights over an additional 15%
Partners (PETROCI - 20%,
SK Corporation - 15%)
Planning exp/app drilling
GHANA - Keta
NIGERIA - OPL 907 / 917
Working Interest (21%)
Held through an 80%
economic interest
Planned 2D seismic & exp
drilling
NIGERIA - OPL 310
Legal Interest (40%)
70% economic interest
Partner (Optimum - 60%)
Potential seismic acquisition
& exp drilling 2010 / 2011
NIGERIA - OML 115
Legal Interest (32.5%)
Partners
(Oriental 60%,
EER 7.5%)
Planned exploration
drilling (1 well) in 2010
Investor Presentation23
www.afren.com
Working Interest (68%)
Partners (GNPC - 10%,
Mitsui - 20%,
Gulf Atlantic - 2%)
One well 2011
CONGO (Brazzaville) - La Noumbi
Working Interest (14%)
Partners (Maurel et Prom - 48.5%,
ENI - 37.5%)
Work commitments fulfilled; likely to
progress into next exploration phase
NIGERIA-SO TOM JDZ- Block 1
Working Interest (4.41%)
Partners (Chevron - 45.9%,
Addax - 40%, Sasol - 5.1%,
Dangote - 4.49%)
Awaiting drilling results from
surrounding blocks
Exploration
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Nigeria: OPL 310
Gross un-risked resource estimate
upgraded to 521 mmboe by NSAI
Several prospects identified all with
multiple reservoir targets (Cenomanian,
Turonian and Albian sandstonereservoirs)
Trapping configurations are 4-way dip
closed structures over basement highs
Prospect 1
Prospect 2
Prospect 3Prospect 4
Investor Presentation24
www.afren.com
proximity to the West African GasPipeline also provides solution for gas
Work programme includes further
seismic reprocessing and
electromagnetic survey
Farm-out planned with potential wellspud late 2010
Prospect 7
Prospect 6
Prospect 5
Exploration
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Ghana: Keta block
Primary target: Upper Cretaceous sandstone
reservoirs, in structural and stratigraphic traps
- Prospectivity identified at five different stratigraphic
intervals
- Not a binary outcome dependent on one well
Play type similar to recent Jubilee and Odum
(Tullow) discoveries
- Odum discovery reported to have been made in
Campanian sands which is extremely promising for
Investor Presentation25
www.afren.com
Source: IHS Energy, Afren
e e a oc
Covered by 1,600 km2 of reprocessed 3D seismic
Cuda - 1x exploration well (December 2008)
- Encountered high pressure zone in Upper Cretaceous
(well P&A)
- Primary Cretaceous objective untested but remains
of high potential
One firm exploration well in 2011
Exploration
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Cte dIvoire: Block CI-01
Three significant discoveries made in 1978
1985, close to existing infrastructure
Oil columns in Kudu and Ibex attest to oil
prospectivity in Upper Cretaceous post-rift
intervals
Potential for missed pay opportunities in
two other previous exploration wells
Investor Presentation26
www.afren.com
Water depth over most of the block
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Investor Presentation27
www.afren.com
Conclusions
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Conclusions
Multi country footprint
Strategically positioned in sub Saharan Africas largest oil and gas play
Organic growth - large scale appraisal and development opportunity
set
Inorganic growth opportunities (company well capitalised)
Operating track record at Okoro - 22,100 boepd net W.I. production
all o erated
Strategy
Established track record
Investor Presentation28
www.afren.com
100% appraisal success at Ebok; development underway Significant reserves base - independently certified 2P reserves and
contingent resources 113 mmboe, prospective upside to 1,167
mmboe
Outlook Production growth (Ebok to exit 2010 at 35,000 bopd)
Organic reserves growth, aggressive 12 month E&A drilling campaign
(Ebok/Okwok/OML 115/OPL 310/Keta Block)
Strategic positioning in Nigeria
Conclusions
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Investor Presentation29
www.afren.com
Appendix
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Exploration portfolio 57Management team 63
Cte dIvoire 53
Nigeria 31
Appendix
Reserves update and 2009 results 67
Investor Presentation30
www.afren.com
Appendix
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Investor Presentation31
www.afren.com
Nigeria
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Ebok-4 well results
Formation Tops Depth,ft TVDSS
Top D1 2466 ft
D1 OWC 2641 ft
175 ft gross hydrocarbon pay
34 ft gross hydrocarbon payTop LD-1A 2738 ft
LD-1A ODT 2772 ft
67 ft gross hydrocarbon payTop LD-1B 2806 ft
-
Investor Presentation32
www.afren.com
Top D2 3550 ft78 ft gross hydrocarbon pay
D2 ODT 3628 ft
Top LD-1E 3161 ft
Appendix
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Ebok-6 well results
Formation Tops Depth,ft TVDSS
Top D1 2909 ft
25 ft gross hydrocarbon payTop LD-1A 3256 ft
LD-1A ODT 3281 ft
LD-1A
25 ft gross interval (oil bearing)
ODT established MDT indicates communication
with E-4
Significant reserves upgrade
Investor Presentation34
www.afren.com
Top LD-1E 3713 ft
Top D2 4029 ft82ft gross hydrocarbon pay
D2 ODT 4111 ft
82 ft gross interval(20 ft gas cap, 54 ft oil leg)
ODT established
MDT indicates pressure isolation
from E-4 area
Reserves in line with pre-drill
expectations
Appendix
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Phased Ebok development
Phased approach to field development
- Simultaneous development / appraisal / exploration
Allows for optimal development sequencing in response to drilling results
- Dynamic project
- Accelerate development of most value accretive components to maximise recovery / IRR
Facilities and development concept selected to provide maximum flexibility
- Central production processing and storage hub
- FSO can easily and inexpensively be changed out at short notice
Investor Presentation35
www.afren.com
Development Phase 1 underway
- Central Fault Blocks
Development Phase 2 to follow immediately
- West Fault Block
Ongoing development expected in 2011 and beyond
- Targeting remaining proved oil accumulations and futurereserve additions from ongoing E&A drilling
Appendix
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Ebok development drilling
Ebok-3
Ebok-5
Ebok-2
Ebok-4
Ebok-1
Phase 2 wells
Phase 1 wells
Ebok-6
Investor Presentation36
www.afren.com
D2 south lobe appraisal
(Ebok-6 well completed)
Appendix
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Ebok wellhead support structure (WSS)
Installation completed March
2010 on central field location
12 well slots
Investor Presentation37
www.afren.com
Appendix
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Mobile Offshore Processing Unit (MOPU) secured
Acquired from Spartan Offshore
Title transferred to Mercator upon purchase
Refurbishment of hull, legs and mat underway
to full ABS requirements
Will be leased back to Afren in combined
MOPU/FSO package over an initial 7 year
period at US$98,092/day
Investor Presentation38
www.afren.com
Option to extend (negotiable)
Initial specification:
Up to 50,000 bopd oil production capacity
Water injection capacity: 25,000 bwpd
Gas injection capacity: 15 mmcfd
Power Generation: 2 x 3.5 MW gas turbine
Appendix
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Ebok FSO Prem Prachi
Contracted vessel (Prem Prachi) inspected
by LOC in Sept 09
Initial 7 year lease term with option
to extend
Storage capacity: 1.2 mmbbls
Vessel to be spread moored at location
DPR approved fiscal metering system to
Investor Presentation39
www.afren.com
e nsta e
Helideck installed
Accommodation for 50 persons
Tank heating to be provided
Dual fuel (gas and HFO) boilers to be installed
Appendix
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3D seismic reservoir continuity through to Okwok
500
Ebok-1 Ebok-2 Mfon-1 Okwok-1 Okwok-2
Investor Presentation41
www.afren.com
1500
2000
Appendix
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Ebok & Okwok - well developed regional sub-surface understanding
1179m 789m 8892m 2935m 1987m
Okwok 2Okwok 8AEbok 4Ebok 5Ebok 2Ebok 1
Okwok 1
1
33
3
OkwokEbok
Investor Presentation42
www.afren.com
D2 Base
Base D1
2
Appendix
Eb k & Ok k i l i
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Ebok & Okwok strong synergies to exploit
Work undertaken at Ebok has provided an insight into the broader area
and its hydrocarbon potential
Enabled Afren to recognise significant potential at Okwok
- Enhanced understanding of regional geology
- Sub-surface interpretation validated by Ebok appraisal drilling
Close proximity offers scale and development
synergies, including
-
Investor Presentation43
www.afren.com
Okwok crude oil export
- Supply vessel sharing
- Helicopter sharing
- Drilling rig(s)
Appendix
Ok k k & id
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Okwok work programme & upside
OML 115
OkwokEbok
Block 1
Block 2
Wells -
Exploration
Appraisal
2km
Investor Presentation44
www.afren.com
One firm well in Q3 2010 to establish minimum economic field size and define development
requirements
Enhanced understanding of regional geology (through Ebok) and relevant technical experience will aidoptimal appraisal and development
Estimated mid case STOIIP of 225 mmbbls and estimated recoverable reserves of 70 mmbbls
Significant exploration potential exists at the deeper Qua Iboe level two prospects identified,
each estimated to contain 200 mmbbls STOIIP
Source: Addax Petroleum
Appendix
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Okoro Setu development
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Okoro Setu development
FPSO moored 800m south east of platformfor crude processing and storage
OkoroWellhead platform
Investor Presentation46
www.afren.com
FPSOWith Gas Lift
and Water Injection
3 Phase Production Flowline
Gas Lift
Flowline
3 Phase
Test Flowline
ExportTanker
12km offshore, Water depthof 46 ft
First Oil achieved in June 2008
Development phase
successfully completed
All 7 wells successfully broughtonstream and are currently
producing circa 18,000 bopd
(gross)
Appendix
Okoro better reservoir performance and enhanced recovery
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Okoro better reservoir performance and enhanced recovery
Production continues at
gross rates between
18,000 to 19,000 bopd
- 44 cargos exported at
end 2009
- Offtake process optimised
with exports via the Ima
terminal
- Production uptime 99.6%
Base Qua Iboe
h
ft
EastWest
0 500 m
Okoro-12Okoro-11
Investor Presentation47
www.afren.com
Infill drilling targets
identified- Expected to restore
production to >21,000 bopd
Remaining reserves (at
31/12/09) upgraded by
NSAI to 24.8 mmbbls (from15.5 mmbbls*)
* NSAI gross 2P remaining reserve estimate of 18.9 mmbbls at 30/06/09 adjusted for H2 2009 production and re-based to 31/12/09 (like-for-like comparison)
Top Upper Sand ATop Upper Sand B
Top Upper Sand C
Top Lower Sand A
Top Lower Sand B
Top Lower Sand COkoro 4 PilotOkoro 12 Pilot
Dept
Appendix
Okoro Setu field development plan
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Okoro Setu field development plan
Armada Perkassa
360,000 barrels storage capacity
27,000 b/d processing capacity
5-year lease (expires 2013) with option to extend
Water depth of 46 ft
FPSO moored 800m south east of platform for
crude processing and storage
7 high angle and horizontal development wells
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Well head platform and Adriatic VI drilling rigFlow line hook up to the Armada Perkassa FPSO
Armada Perkassa FPSO spread moored
Source: Bumi Armada
Appendix
Okoro Setu fast track development
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Q1 07 Q1 08 Q2 08 Q3 08 Q4 08
RBL facility / certified reserves
Okoro Setu fast track development
Q2 07 Q3 07 Q4 07Q1 06 Q2 06 Q3 06 Q4 06
Agreement signed with partner AMNI
Appraisal drilling
Rig secured for development drilling
Investor Presentation49
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FDP approval
FPSO secured
Development drilling (7 wells)
Production
Long lead items
CompleteSource: Afren
Appendix
Okoro Setu community development
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Okoro Setu community development
Okoro Community Development (CD)
Regular dialogue through community relations committee
Active recruitment from local community
- FPSO, drilling, etc
To contribute towards making a significant and lasting impact on wealth creation and sustainable livelihood in
the area of our operations
Afrens Community Development Vision
Investor Presentation50
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Ongoing Community Development projects
- 148 secondary and tertiary scholarships awarded
- Micro credit fund for local business
- Socio-economic needs assessment
- Vocational training programmes
- Industry training programmes
- Health/Infrastructure project
(e.g. potable water project)
The FPSO crew including members of the eastern Obolo
Community at the FPSO Ceremony, Keppel Shipyard, Singapore
Appendix
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2010 firm drilling programme
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2010 firm drilling programme
Ebok Deep
Prospect size: 30 mmbbls
Okwok
Objective to define field
size and development
requirements
D2 reservoir target
1 well Q3 2010
OML 115
Extension of D series reservoirs
proven at Ebok and Okwok
Ebok Phase 1 and 2 (underway)
12 production wells &
1 water injection wells
Onstream October 2010
(15,000 bopd)
2010 exit 35,000 bopd
Investor Presentation52
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Base Qua Iboe
Top Upper Sand ATop Upper Sand BTop Upper Sand C
Top Lower Sand ATop Lower Sand BTop Lower Sand C
Okoro-4 Pilot
Okoro-11Okoro-12
Okoro-12 Pilot
channelised sands
1 well Q2 2010
Okoro infill drilling
2 infill wells
Top lower sand B
3,000 bopd incremental
production
Additional prospectivity
identified in deep horizons 1 well Q3 2010
OPL 310
Large scale prospectivity
defined in Upper Cretaceous
Electromagnetic survey
commissioned
1 well Q4 2010
(post farm out)
Appendix
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Cte dIvoire
Production, development and exploration upside
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Block CI-11
WI: 47.9592% (Joint Operator with Petroci)
13km offshore: 246 ft water depth
Lion & Panthre producing fields
30 mmcfd and 1,230 bopd current gross
production (~6,359 boepd)
Block CI-01
Investor Presentation54
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WI: 65% (Operator) (1)
Three discoveries
Lion Gas Plant
WI: 100% (Operator)
Butane & gasoline extracted from CI-11, CI-26 (Espoir) & CI-40 (Baobab) gas
1,165 boepd NGLs produced
(1) 65% direct equity and rights over an additional 15%
Appendix
Block CI-01
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Lion Gas Plant
14 wells (exploration and appraisal) drilled by Esso and Agip
3 signficant discoveries: Kudu (1964), Eland (1978)
and Ibex (1985)
37.3 mmbboe gross independently certified contingent
resources (NSAI)
Potential development concept
- Ibex Field Oil development Full offshore facility and 98km pipeline to SIR refinery
Produced gas compressed 8km pipeline to Eland platform
- Kudu and Eland Field Gas development
Minimum offshore facility
Investor Presentation55
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Shore
Approach
Gas-Condensate Export
Pipeline to Lion GPL
72km; 10 dia
Oil Pipeline to LGPL
98km; 6 dia
Full Facility
IBEX
ELAND
Pipeline to Kudu
18km; 8 dia Gas Pipeline
8km; 4 dia
KUDU
Gas and liquids via 72km pipeline to Lion GPL
PotentialDevelopment
Schematic
Appendix
Lion gas plant
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Afren: 100% (Operated)
Capacity to process 75 mmcf/d
Third party gas recieved from Blocks CI-26 and CI-40
(Espoir and Baobab)
Butane and Gasoline produced
- Gasoline spiked into Lion crude stream and sold on the world
market at prevailing global oil prices
-
Investor Presentation56
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(meeting 35% of total domestic demand)
Enjoys tax exempt status, generating
attractive plant economics
Appendix
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Exploration Portfolio
Exploration: focus on West African Transform Margin and Cretaceous plays
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OPL 310 Adjacent to OML 113
Upper Cretaceous multiple prospects in same Cenonian,
Turonian and Albian sands
West AfricanTransform Margin
CI-01: Cretaceous depositional model suggests significant
exploration / appraisal upside
Keta: covered by high quality, modern vintage seismic data set
Investor Presentation58
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Ebok reservoir continuity through to Okwok
Significant exploration potential at deeper Qua Iboe levels
Potential to grow position excellent subsurface understanding
Stratigraphic trap demonstrated and working at West Cape Three
Points and Deepwater Tano discoveries Giant field potential Multiple play concepts at five intervals
Ebok Okwok
OML 115
Appendix
Nigeria: OPL 310
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Licence details Partners: %
Area km2: 1,850 Afren (Op.) 40
Expiry: February 2019 Optimum 60
Licence type: PSC
Main plays:Cretaceous shelfal to deep water clastics in structural and stratigraphic traps
Investor Presentation59
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High-impact shallow-to-deep water exploration block in western Nigeria, with prospects similar to the
adjacent major Aje discovery, and with access to the newly-completed West African Gas Pipeline (WAGP) Afren holds a 40% legal interest, with a 70% effective economic interest
2009 work programme: Continued technical and commercial studies. Possible purchase of 2D and 3D seismic data
Future work programme: Potential 3D seismic and EM surveys in 2010, exploration well in 2010 / 2011
Appendix
OPL 310: Arbitrary NE-SW Line Across Aptian High Block Time Section
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0.500
1.000
1.500
2.000
2.500
South of Aje Field
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3.000
3.500
4.000
4.500
5.000
5.500
Line 3
Aptian unconformity
Appendix
OPL 310: Key Prospects
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OPL 310 contains several identified prospects in the same Cenomian, Turonian and Albian sandstonereservoirs and similar trapping configurations in four-way-dip closed structures over basement highs.
The Shiny Nose prospect features an electro-magnetic anomaly consistent with that over Aje.
Further on-trend analogues include the Seme, Atacora and Alibori discoveries in neighbouring Benin.
There is a unique gas sales solution opportunity available to Afren via access to the West African Gas
Pipeline (WAGP).
Investor Presentation61
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Appendix
Ghana: Keta block
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Licence details Partners: %
Area km2: 5,500 Afren (Op.) 68
Expiry: 31st
December 2010 Mitsui 20Licence type: Tax / royalty GNPC 10
Main plays: Cretaceous deepwater clastics in
combined structural/stratigraphic
Gulf Atlantic Energy 2
Investor Presentation62
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High impact, deepwater exploration in easternmost Ghanaian waters along the highlyprospective but under-explored West African Transform Margin. Multiple play types offer
diverse potential
traps
2009 workprogramme:
Continued geophysical studies and evaluation of Cuda-1 drilling performance
Future work
programme:
Exploration drilling in 2011
Appendix
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Management Team
Board: extensive African / industry experience
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Egbert Imomoh - Chairman
OsmanShahenshah
Chief Executive
Peter BinghamNon exec
John St. JohnNon exec
ConstantineOgunbiyi
Director
Shahid UllahCOO
Ennio SganzerlaNon exec
Toby HaywardNon exec
BRASSExploration UnlimitedBRASSExploration Unlimited
Investor Presentation64
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BUSINESS UNITS
INTERNATIONAL ADVISORY BOARD
Operated Non-Operated
Brian WardBert Cooper
Founder
Hiroshi Kanematsu Ekwere
Peters
Henry
Groppe
Nigeria Cte dIvoire Ghana CongoGas
monetisationNigeria
So Tom JDZ
Appendix
Management team
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Senior Management - London
Iain WrightTechnical Director
Faiz ImamDirector Afren Nigeria
Jack McFarlandOperations Director
Galib ViraniHead of Acquisitions & IR
Patrick CherletCommercial Director
BRASSExploration UnlimitedBRASSExploration Unlimited
BRASSExploration UnlimitedBRASSExploration Unlimited
Jeremy WhitlockFinancial Controller
Shirin JohriGroup General Counsel
Andrew Olleavant
EHSS
Jane BarkerHead of Human Resources
Darra Comyn
Group Finance Director
Investor Presentation65
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Senior Management - Lagos
Rotimi BrightReservoir
Engineering Manager
Daniel SasegbonGeneral Counsel
Senior Management - AbidjanKoffi Adje
General Manager
Sirima BassinaGovernment & Business
Relations
Sylvie Kodja
Finance Manager
Deji WestFinance Director
Adebayo AyorindeTechnical director/
Okoro Project Mgr
Okon AkpanEngineering Manager
Taiwo OlushinaDrilling Manager
Appendix
Technical and operational resources
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Egbert ImomohChairman
Petroleum Engineer
>35 years
Ennio SganzerlaNon exec
Petroleum &
Mechanical Engineer
>35 years
Shahid UllahCOO
BRASSExplorationUnlimitedBRASSExplorationUnlimited
Petroleum Engineer >20 years
Brian Ward
Petroleum Engineer
>35 years
Henry Groppe
Petroleum Engineer
>55 years
Petroleum Engineer
>25 years
Prof. Ekwere Peters
Iain WrightTechnical Director
Andrew OlleavantEHSS
Jack McfarlandOperations Director
Investor Presentation66
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BRASSExploration UnlimitedBRASSExploration Unlimited
Taiwo OlushinaDrilling Manager
Keith Payne
Geoscientists
x7
Engineering
x6
EHSS
x11
Facilities
Engineering
x4
Production
Operations
x70
Commercial
x3
Appendix
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Reserves update (NSAI)
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Okoro Gross 2P (31/12/09)
18.9
9.4
0.0
5.0
10.0
15.0
20.0
25.0
30.0
mmbbls
3.4
24.8
CI-11 Gross 2P (31/12/09)
9.70.5
0.0
10.0
mmboe
1.19.1
2.0
6.0
4.0
8.0
12.0
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Ebok Gross 2P (31/12/09)
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0mmbbls
88.4
19.1
107.5
30/06/09 31/12/09Prod Revisions
Appendix
Net income
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Gross Profit / (loss) 105.8 (28.0) 105.8 (28.0)
Administrative expenses (13.9) (21.7) (13.8) (21.7)
Derivatives unrealised (45.1) 51.0
Derivatives realised 11.4 3.6 11.4 3.6
Exploration costs 0.9 (38.2) 0.9 (38.2)
Other* (13.3) (10.8)
US$ mm 2009 2008
Profit and loss account
statutory2009 2008
Profit and loss account
normalised
Cost controlinitiatives
Marked-to-market, noncash effects
Investor Presentation69
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* Includes costs associated with main market move and share options
** Includes FX, fair value financial liabilities and associate costs
Operating profit 45.8 (44.1) 104.3 (84.3)
Finance costs (37.0) (16.4) (37.0) (16.4)
Interest income 0.6 5.3 0.6 5.3
Other** (8.9) (0.4)
Profit before tax 0.5 (55.6) 67.9 (95.4)
Tax (17.3) (0.5) (17.3) (0.5)
Profit / (Loss) after tax (16.8) (56.1) 50.6 (95.9)
Appendix
Sources and uses of funds
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Cash sources- Operating Cash inflow US$278 mm
(2008 US$27 mm outflow)
- Net Equity Proceeds US$313 mm
- Investment Revenue US$1 mm
(2008 US$5 mm)
Cash uses
- Investment activities US$209 mm300
400
500
600
US$m
313
148
207
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(2008 US$465 mm)
- Repayment of loan US$148 mm(2008 US$29 mm)
- Debt amortised as planned
- Cash interest & financing fees US$27 mm
(2008 US$16 mm)
-FX effect US$3 mm
Net cash inflow 2009: US$207 mm
Cash at bank, end period: US$321 mm
Operating cash flow Net equity proceeds Investment activity
Repayment of loan Interest & financing fees
Cash at 31/12/2008 Net increase in cash FX rates effect
Cash inflow Cash Outflow
100
200
Cash & equivalents
209
117
0
Appendix
2010 financial strategy and outlook
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Continue with strict cost control and discipline
- Drive costs down at every opportunity
- Okoro opex
- Ebok development capex and opex
Appropriate budget set at US$430 mm
- Production growth
- Attractive appraisal and exploration
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- Portfolio approach: high grading of investment opportunities
(target base case IRR >40%)
Financial flexibility
- Continued debt amortisation
- US$450 million RBL facility
- Portfolio growth
2011 capex fully funded out of cashflow
Appendix