bofam le&p conf slides

8/9/2019 BofAM LE&P Conf Slides

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19 21 April 2010

BofA Merrill Lynch London E&P conference 2010


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3/71

Exploration 22

Conclusions 27

Current projects 15

Executive summary 4

Agenda

Appendix 29

Investor Presentation3

www.afren.com

Agenda


4/71


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


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


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


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


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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10/71

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


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


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


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


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


15/71


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


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


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


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


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


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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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


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


www.afren.com


Partners (GNPC - 10%,

Mitsui - 20%,

Gulf Atlantic - 2%)

One well 2011

CONGO (Brazzaville) - La Noumbi


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


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


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


www.afren.com

Water depth over most of the block


27/71


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


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


29/71


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


www.afren.com

Appendix


31/71


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

-


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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34/71

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


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


35/71

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


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


36/71

Ebok development drilling

Ebok-3

Ebok-5

Ebok-2

Ebok-4

Ebok-1

Phase 2 wells

Phase 1 wells

Ebok-6


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


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


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


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


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


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

-


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


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


45/71

Okoro Setu development


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Okoro Setu development

FPSO moored 800m south east of platformfor crude processing and storage

OkoroWellhead platform


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


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


www.afren.com

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


www.afren.com

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


www.afren.com

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


www.afren.com

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


53/71


www.afren.com

Cte dIvoire

Production, development and exploration upside


54/71

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


www.afren.com

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


www.afren.com

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

-


www.afren.com

(meeting 35% of total domestic demand)

Enjoys tax exempt status, generating

attractive plant economics

Appendix


57/71


www.afren.com

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


www.afren.com

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


www.afren.com

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


www.afren.com

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).


www.afren.com

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


www.afren.com

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


63/71


www.afren.comwww.afren.comwww.afren.com

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


www.afren.com

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



Jeremy WhitlockFinancial Controller

Shirin JohriGroup General Counsel

Andrew Olleavant

EHSS

Jane BarkerHead of Human Resources

Darra Comyn

Group Finance Director


www.afren.com

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


www.afren.com


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


www.afren.com

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


www.afren.com

* 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


www.afren.com

(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


www.afren.com

- 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

bofam le&p conf slides

Documents