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IF Oil Discovery Update Presentation 1 st June 2009 1 1 st June 2009 - - PowerPoint PPT Presentation

IF Oil Discovery Update Presentation 1 st June 2009 1 1 st June 2009 Disclaimer Important Notice Nothing in this presentation or in any accompanying management discussion of this presentation (the " Presentation ") constitutes, nor is


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SLIDE 1

1st June 2009

IF Oil Discovery Update Presentation

1st June 2009

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SLIDE 2

Disclaimer

Important Notice Nothing in this presentation or in any accompanying management discussion of this presentation (the "Presentation") constitutes, nor is it intended to constitute: (i) an invitation or inducement to engage in any investment activity, whether in the United Kingdom or in any other jurisdiction; (ii) any recommendation or advice in respect of the ordinary shares (the "Shares") in Bowleven plc (the "Company"); or (iii) any offer for the sale, purchase or subscription of any Shares. The Shares are not registered under the US Securities Act of 1933 (as amended) (the "Securities Act") and may not be offered, sold or transferred except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and in compliance with any other applicable state securities laws. The Presentation may include statements that are, or may be deemed to be "forward-looking statements". These forward-looking statements can be identified by the use of forward-looking terminology, including the terms "believes", "estimates", "anticipates", "projects", "expects", "intends", "may", "will", "seeks" or "should" or, in each case, their negative or other variations or comparable terminology, or by discussions of strategy, plans, objectives, goals, future events or intentions These forward-looking statements include all matters that are not historical facts They include statements regarding the Company's intentions

1st June 2009

  • intentions. These forward looking statements include all matters that are not historical facts. They include statements regarding the Company s intentions,

beliefs or current expectations concerning, amongst other things, the results of operations, financial conditions, liquidity, prospects, growth and strategies of the Company and its direct and indirect subsidiaries (the ‘Group’) and the industry in which the Group operates. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. Forward-looking statements are not guarantees of future performance. The Group’s actual results of operations, financial conditions and liquidity, and the development of the industry in which the Group operates, may differ materially from those suggested by the forward-looking statements contained in the Presentation. In addition, even if the Group’s results of operations, financial conditions and liquidity, and the development of the industry in which the Group operates, are consistent with the forward-looking statements contained in the Presentation, those results or developments may not be indicative of results or developments in subsequent periods. Recipients of the Presentation are advised to read the admission document dated 1 December 2004 issued by the Group (as supplemented by subsequent prospectuses issued by the Company and subsequent announcements by the Company to Regulatory Information Services) for a more complete discussion of the factors that could affect future performance and the industry in which the Group operates. In light of those risks, uncertainties and assumptions, the events described in the forward-looking statements in the Presentation may not occur. Other than in accordance with the Company's obligations under the AIM Rules for Companies, the Company undertakes no obligation to update or revise publicly any forward-looking statement, whether as a result of new information, future events or otherwise. All written and oral forward-looking statements attributable to the Company or to persons acting on the Company's behalf are expressly qualified in their entirety by the cautionary statements referred to above and contained elsewhere in the Presentation.

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SLIDE 3

Presenters

  • Kevin Hart, CEO

Kevin Hart

1st June 2009

  • Ed Willett, Exploration Director

3

Ed Willett

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Executive Summary

1st June 2009

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Kevin Hart, CEO

4

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SLIDE 5

Executive Summary

  • TRACS report independently supports Bowleven’s view
  • f IF field potential.
  • Further appraisal warranted.
  • High likelihood of commercial development.
  • Rig tenders issued.
  • Project sanction possible by mid-2010 with first oil in

1st June 2009

5 j p y late 2011 assuming FPSO concept.

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SLIDE 6

Highlights of CPR

  • IF Oil Discovery CPR completed by TRACS

International Consultancy Ltd.

  • STOIIP and Contingent Resources are assessed as:

1C 2C 3C

Total STOIIP mmbbl

101.2 194.5 274.1

1st June 2009

  • NPV (10%) is assessed as:
  • Probability of Commercial Success estimated as 65%.

6 Oil Contingent Resources mmbbl

23.9 53.1 94.3 1C 2C 3C

Bowleven NPV (10%) mmUS$ 10.6 556.3 1038.3

Nymex crude oil (light) forward curve to 2017 and 1.8% inflation p.a. applied thereafter.

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SLIDE 7
  • Structure now defined as a simple 4-way dip closure.

MLHP-7 IF Field – Bowleven Current View

STOIIP mmbbl P90 P50 P10 Mean Total 131 206 335 225 Contingent Resource P90 P50 P10 Mean Total 44 76 130 82

1st June 2009

7

  • Recovery factors 30-40-55%.
  • Anticipated ultimate development likely to incorporate

FPSO resulting in significant CAPEX savings.

  • Development design will facilitate further future on-

block field integration (IE, IM, etc.).

  • Highly attractive project economics.

IF-1r well DST Flare

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SLIDE 8

IF Oil CPR Presentation

1st June 2009

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Ed Willett, Exploration Director

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SLIDE 9

Cameroon Acreage Position

Bomono Permit 100%

  • OLHP 1 & 2
  • 2,328 km²
  • PSC signed 12 Dec 2007
  • First term ends 11 Dec 2012
  • 500km seismic & one well

commitment

IF Oil Discovery

1st June 2009

commitment Etinde Permit 100%

  • MLHP 5,6 & 7
  • 2,314 km²
  • Etinde PSC signed on 22 Dec

2008

  • Exploration period extended by

three years from date of signing

  • 200km² 3D seismic and one well

commitment

9

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SLIDE 10

Competent Persons Report:

  • TRACS International Consultancy Ltd were commissioned

by Bowleven Plc to conduct an independent third party review and audit of the IF Oil Discovery.

  • The CPR process included a complete assessment of:
  • Seismic interpretation
  • Petrophysics

MLHP-7 IF Field – CPR May 2009

1st June 2009

10

  • Mapping and Volumetric Calculations
  • Fluid data (MDT and DST)
  • Production Tests
  • Recovery Factors
  • Field Development Plan
  • Reserves & Resources Calculations
  • Resource Valuation
  • CPR completed May 2009.

Trident IV Jack-up on IF-1r location Summer 2008.

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SLIDE 11

Appraise

POS 65%

Appraisal High Case Mid Case

MLHP-7 IF Field – CPR May 2009

Evaluation Methodology

Competent Persons Report:

  • The CPR assumes that the proven field

area (IF-1r locale) is insufficient for commercial development and an

1st June 2009

Appraise

POS 65%

Successful Mid Case Low Case

11

IF-1r Discovery

p appraisal program is required.

  • Overall probability of commercial success

is evaluated as 65%.

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SLIDE 12

Appraise

POS 65%

Appraisal High Case Mid Case

MLHP-7 IF Field – CPR May 2009

Evaluation Methodology

1st June 2009

Appraise

POS 65%

Successful Mid Case Low Case

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IF-1r Discovery

  • The CPR provides an unrisked

assessment of the IF Field and gives a range of high, mid and low case outcomes.

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High Case Areal Extent

IF-1R

Poor Data Zone ?Gas Chimney

MLHP-7 IF Field – CPR May 2009

GRV Derivation - Structural Interpretation

Bowleven Structure (Mar ‘09)

(based on Green pick) 1st June 2009

13

  • Both Bowleven and TRACS map sets identify an

independent 4-way dip closure updip to the SE of the IF-1r discovery well.

  • High and Mid cases defined by seismic interpretation.
  • Low Case GRV derived by structural

compartmentalisation and more pessimistic time-depth conversion than encountered in IF-1r.

High case

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SLIDE 14

IF-1R

Poor Data Zone ?Gas Chimney

MLHP-7 IF Field – CPR May 2009

GRV Derivation - Structural Interpretation

Bowleven Structure (Mar ‘09)

(based on Green pick)

TRACS Structure Map (May ‘09)

(based on Yellow pick) 1st June 2009

14

  • Both Bowleven and TRACS map sets identify an

independent 4-way dip closure updip to the SE of the IF-1r discovery well.

  • High and Mid cases defined by seismic interpretation.
  • Low Case GRV derived by structural

compartmentalisation and more pessimistic time-depth conversion than encountered in IF-1r.

Mid case High case Mid Case Areal Extent

(Includes Low Case Areal Extent)

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SLIDE 15

Shale Thin Beds TRACS CPI log with Reservoir Zonation

GR Res Rhobz-TNph-DT Vclay Phie

MLHP-7 IF Field – CPR May 2009

N:G Derivation – Reservoir Zonation

OWC 6548ftMD

Core

ft) 98%recovery

DST 1

  • Ave. 3371 bopd,

Peak 4184bopd ½” choke TRACS CPR Top Amalgamated Sands pick. 1st June 2009

Sand 1 Sand 2 Sand 3 Shale

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  • Reservoir zonation used to define Gross Rock Volume and N:G for

input into STOIIP calculations.

  • Alternative volumetric cases (high, mid, low) based on uncertainties in:
  • seismic/structural interpretation,
  • depth conversion
  • reservoir continuation updip into the crestal areas.

Core (455f

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SLIDE 16

Shale Thin Beds TRACS CPI log with Reservoir Zonation

GR Res Rhobz-TNph-DT Vclay Phie

MLHP-7 IF Field – CPR May 2009

N:G Derivation – Reservoir Zonation

OWC 6548ftmd

Core

ft) 98%recovery

DST 1

  • Ave. 3371 bopd,

Peak 4184bopd ½” choke TRACS CPR Top Amalgamated Sands pick. 1st June 2009

Cross-section through Mid Case GRV Model Sand 1 Sand 2 Sand 3 Shale

16

  • Reservoir zonation used to define Gross Rock Volume and N:G for

input into STOIIP calculations.

  • Alternative volumetric cases (high, mid, low) based on uncertainties in:
  • seismic/structural interpretation,
  • depth conversion
  • reservoir continuation updip into the crestal areas.

Core (455f

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SLIDE 17

Shale Thin Beds TRACS CPI log with Reservoir Zonation

GR Res Rhobz-TNph-DT Vclay Phie

MLHP-7 IF Field – CPR May 2009

N:G Derivation – Reservoir Zonation

OWC 6548ftmd

Core

ft) 98%recovery

DST 1

  • Ave. 3371 bopd,

Peak 4184bopd ½” choke TRACS CPR Top Amalgamated Sands pick. 1st June 2009

Cross-section through Mid Case GRV Model Cross-section through High Case GRV Model Sand 1 Sand 2 Sand 3 Shale

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  • Reservoir zonation used to define Gross Rock Volume and N:G for

input into STOIIP calculations.

  • Alternative volumetric cases (high, mid, low) based on uncertainties in:
  • seismic/structural interpretation,
  • depth conversion
  • reservoir continuation updip into the crestal areas.

Core (455f

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SLIDE 18

Competent Persons Report:

  • In each of the high, mid and low case, the following

parameters are constant (based on core, log, MDT and test data):

  • Porosity = 21%
  • Oil Saturation = 75%

High Case 274.1mmbbl STOIIP

MLHP-7 IF Field – CPR May 2009

STOIIP Calculation

Thin Beds 365 35% 72.7 Sand 1 390 78% 173.2 Sand 2 13.5 82% 6.3 Sand 3 65 54% 21.9

High Case Total 274.1

Zone GRV mcum N:G STOIIP

1st June 2009

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Thin Beds 525 25% 74.7 Sand 1 290 70% 115.6 Sand 2 6 82% 2.8 Sand 3 4 54% 1.3

Mid Case Total 194.5

  • Formation Volume Factor = 1.74 rb/stb
  • High Case: Structure as Bowleven (Mar ‘09), N:G

higher than in IF-1r well.

  • Mid Case: Structure as TRACS CPR mapping, N:G

as encountered in IF-1r well.

  • Low Case: compartmentalised structure, depth

conversion perturbed depressing the IF structure, N:G lower than prognosed from well data.

Mid Case 194.5mmbbl STOIIP Low Case 101.2mmbbl STOIIP

Thin Beds 450 15% 38.4 Sand 1 190 58% 62.7 Sand 2 82% Sand 3 54%

Low Case Total 101.2

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SLIDE 19

High Case

(Structure as Bowleven mapping) (N:G higher than in IF-1r well)

274.1mmbbl STOIIP

MLHP-7 IF Field – CPR May 2009

Evaluation Methodology

1st June 2009

Appraisal Successful (POS 65%)

Mid Case

(Structure as TRACS mapping) (N:G as in IF-1r well)

194.5mmbbl STOIIP Low Case

(structure low; low pick and different depth conversion over poor data area) (N:G lower than prognosed)

101.2mmbbl STOIIP

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SLIDE 20

Competent Persons Report:

  • Sweep efficiency has been assessed for the

individual reservoir zones and combined probabilistically to derive an overall recovery factor.

MLHP-7 IF Field – CPR May 2009

Resource Calculation

Range of Recovery Factors Average Recovery Factor

23.6% 27.3% 34.4%

1st June 2009

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  • Combining the STOIIP values and range of recovery

factors probabilistically yield the CPR statement of contingent resources. 1C 2C 3C

Total STOIIP mmbbl

101.2 194.5 274.1

Oil Contingent Resources mmbbl

23.9 53.1 94.3

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SLIDE 21

MLHP 7

IE ID IM IC Manyikebi

MLHP-7 IF Field – CPR May 2009

TRACS Conceptual Development

IF associated gas used as fuel gas, remaining to onshore

Limbé

New oil & gas processing facilities Gas to Power station

1st June 2009

MLHP 7 IF WHP Platform Host water injection facilities & mobile drilling rig

IF

IF Development Wells 4* Producers 3 Injectors Facilities 30kbpd oil, 45kbpd liquids, 36Mscfd gas 60kbwpd injection capability

21

Multiphase pipeline from field to new onshore oil & gas processing facility MLHP 5 Export via existing Limbé facilities

*The 4 production wells include 2 completed appraisal wells

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SLIDE 22

MLHP 7

IE ID IM IC Manyikebi

MLHP-7 IF Field – CPR May 2009

TRACS Conceptual Development

IF associated gas used as fuel gas, remaining to onshore

Limbé

New oil & gas processing facilities Gas to Power station

Cost Item Cost (MM US$ RT 2009)

Topsides

68

Platform substructure

74

1st June 2009

MLHP 7 IF WHP Platform Host water injection facilities & mobile drilling rig

IF

IF Development Wells 4* Producers 3 Injectors Facilities 30kbpd oil, 45kbpd liquids, 36Mscfd gas 60kbwpd injection capability

22

Multiphase pipeline from field to new onshore oil & gas processing facility MLHP 5 Export via existing Limbé facilities

Offshore Pipelines

69

Subsea Equipment

7

Onshore Processing plant

298

Appraisal wells

70

Development drilling

190 Total 776

*The 4 production wells include 2 completed appraisal wells

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SLIDE 23

Competent Persons Report:

  • Production start-up date Jan 2013.
  • Uptime factor of 90% assumed.
  • High Case: 27kbopd plateau until Q2 2020.

MLHP-7 IF Field – CPR May 2009

Production Profiles

1st June 2009

  • Mid Case: 27kbopd plateau until Q3 2017.
  • Low Case: 20kbopd plateau until Q1 2015.
  • The low case assumes that wells need to be

flow restricted due to unrealistically high

  • fftake (30kbopd is ~45% recoverable

volumes per annum). 23

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SLIDE 24
  • NPV (10%) assumes consistent development scenario

for high, mid and low cases.

  • All values are referenced to 1st July 2009.
  • The Mid-Case NPV (10%) is >$500 Million.
  • The TRACS EMV (10%) is $339 Million assuming one

appraisal well is required to identify the failure case 1C 2C 3C POS

Oil Contingent Resources (mmbbl) 23.9 53.1 94.3 65% Oil Contingent Resources (mmbbl) Post-SNH back-in* 19.1 42.5 75.4 B l NPV (10%)

MLHP-7 IF Field – CPR May 2009

Economic Evaluation of Resources

1st June 2009

24 appraisal well is required to identify the failure case and a 65% POS.

  • In the event of a low case scenario is realised, the

proposed development would be appropriately re-scaled.

  • Economic Assumptions:
  • Nymex crude oil (light) forward curve from May 13th used to
  • 2017. 1.8% per year inflation applied thereafter (equates to

$65/bbl real (flat)).

  • Costs escalated by 3% per annum.

Bowleven NPV (10%) mmUS$ 10.6 556.3 1038.3

2010 2011 2012 2013 2014 2015 2016 2017 $67.1 $71.3 $73.3 $74.8 $76.3 $77.7 $79.2 $80.6 *Note SNH have 20% back-in rights in the event of declaration of commerciality.NPV assumes SNH back-in. Oil price deck $/bbl (associated gas is excluded from evaluation)

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Bowleven Current View

1st June 2009

25 25 25

25

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SLIDE 26

MLHP-7 IF Bowleven Interpretation Update

High Case Areal Extent

Bowleven Structure (Mar ‘09)

(based on Green pick)

Bowleven In-house volumes

STOIIP P90 MMbbl P50 MMbbl P10 MMbbl Mean MMbbl Thin Bed zone 21 52 125 65 Massive Bed zone 79 142 244 153 TOTAL *Monte Carlo addition) 131 206 335 225 IF Contingent Resource P90 MMbbl P50 MMbbl P10 MMbbl Mean MMbbl

1st June 2009

26

Thin Bed zone 6 14 38 19 Massive Bed zone 30 57 105 63 TOTAL *Monte Carlo addition) 44 76 130 82

  • Structure now defined as a simple 4-way dip closure.
  • Recovery factors 30-40-55%.
  • Anticipated ultimate development likely to incorporate

FPSO resulting in significant CAPEX savings.

  • Development design will facilitate further future on-block

field integration (IE, IM, etc.).

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SLIDE 27

MLHP-7 Current Development Potential

IF Oil Anticipated Ultimate Development Scenario

MLHP 7

ID IM IC Manyikebi

MLHP 7

IE ID

Phase 1 Oil Process: 30,000 bopd Gas Flared Water Overboard

Limbé

Phase 2 Liquids: 60,000 bpd Water Injection: 60,000bpd Gas Dehydration & Compression: 36 MMscfd

Phase 2: Fuel Gas Pipeline to Limbé.

1st June 2009

MLHP 7

IF

Phase Producers Injectors 1 2x Appraisal 2 2 2x Dry, 1x Subsea 3 (Contingent) 3 1 TOTAL 7 4

27 MLHP 5 MLHP 7 MLHP 5

Appraisal well 1 (~2km) Appraisal well 2 (~2km)

FPSO: Spread moored, dynamic flexible production and injection risers and umbilicals Phase 2: 9-Slot WHP 2 prod. 3 inj.

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SLIDE 28

MLHP-7 Current Development Potential

IF Oil Anticipated Ultimate Development Scenario

MLHP 7

ID IM IC Manyikebi

MLHP 7

IE ID

Phase 1 Oil Process: 30,000 bopd Gas Flared Water Overboard

Limbé

Phase 2 Liquids: 60,000 bpd Water Injection: 60,000bpd Gas Dehydration & Compression: 36 MMscfd

Phase 2: Fuel Gas Pipeline to Limbé.

Cost Item Phase 1 ($Millions) Phase 2 ($Millions) Topsides

35

Jacket

18

1st June 2009

MLHP 7

IF

Phase Producers Injectors 1 2x Appraisal 2 2 2x Dry, 1x Subsea 3 (Contingent) 3 1 TOTAL 7 4

28 MLHP 5 MLHP 7 MLHP 5

Appraisal well 1 (~2km) Appraisal well 2 (~2km)

FPSO: Spread moored, dynamic flexible production and injection risers and umbilicals Phase 2: 9-Slot WHP 2 prod. 3 inj.

Subsea

20

Infield flowlines

26 31

FPSO installation

31 104

Subsea Flowlines

29 21 Total 106 209

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SLIDE 29

Estimated capex/opex for each case

Case Total Estimated Capex (USD millions) Total Estimated Annual Opex (USD millions, Cost estimates from Genesis:

Initial well count: 4 producers

1st June 2009

excluding drilling and well intervention) Onshore processing (CPR) 515 (facs) 190 (wells) 15.0 FPSO 315 (facs) 205 (wells) 51.5*

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4 producers 3 injectors Drilling and WI: $10 million every 2 years

* Bowleven high level estimate, based on est. USD100,000/d lease rate and USD15m annual opex.

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SLIDE 30

1000 1200 1400 1600 1800

945 1179 1420 1656 009 US$million

IF Stand Alone Oil Development: Bowleven NPV 225 mmbbls Mean STOIIP; CPR Costs; 30 mbpd

Economic Evaluation

1st June 2009

30 200 400 600 800 50 60 70 80

NPV10 at 1.7.20 Brent Real Oil Price US$/bbl

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SLIDE 31

Remaining Assets

1st June 2009

31 31 31

Ed Willett, Exploration Director

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SLIDE 32

MLHP-7 Isongo and Biafra Inventory

Isongo Gas Condensate Fields - Isongo Marine, IC, ID and IE. IE successfully appraised by Bowleven in 2007. Characterised by rich condensate Isongo Prospects - Multiple undrilled structural culminations associated with existing discoveries. Low risk and high potential.

1st June 2009

rich condensate yield – CGR of 70 to ~140. Isongo Oil Discovery - IF – Bowleven 2008. Tertiary sourced 35°API oil transforms prospectivity and value of acreage. Biafra - Shallow dry gas accumulations at Manyikebi and IE plus additional prospectivity. Oil shows in IM-1. Isongo Leads - Significant additional emergent prospectivity.

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SLIDE 33

Block MLHP-7 Oil/Gas Resource

(Mean Volumes Initially In Place)

Dry GIIP (bcf) Wet GIIP* (bcf) NGL† (mmbbl) STOIIP (mmbbl) Isongo Marine Field* 348 18 Isongo E Field* 80 463 105 Isongo D Discovery* 8 1 Isongo C Discovery* 77 5 Isongo F Discovery 194.5‡ Manyikebi* 56 Total Discovered 136 896 129 194 5

1st June 2009

Resource 136 896 129 194.5

*includes NGLs, which comprise condensate and LPGs. †NGLs include LPGs for ID & IE only. ‡TRACS CPR Mid-Case

Isongo Marine Exploration 823 35 Isongo D Exploration 158 35 Isongo C Exploration 274 6 Isongo E Exploration 16 23 5 Isongo G Cluster 349 8 Total Exploration Resource 16 1627 89

Total MLHP 7 Resource

152 2523 218 194.5

33

IF-1r DST Flare

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SLIDE 34

MLHP-7 Current Development Potential

IF Oil with IM-ID-IE Gas Condensate Development – Possible Synergies

MLHP 7

IE ID IM IC Manyikebi

Gas Injection Pipeline

Potential tie-in of Isongo-Marine gas-condensate IE WHP Platform

Limbé

New oil processing & export facilities Limbé Refinery and Power station

1st June 2009

MLHP 7 IF WHP Platform 6-Slot Wellhead

IF

IE WHP Platform 9-Slot Wellhead Field Oil/NGLs Mbbl/d Gas Export MMscf/d Gas Production MMscf/d Development Wells

Producers Injectors

IF 15-20 (oil) 16-22

  • 3-4

ID-IE 15-25 (NGL)

  • 130-150

3-5 2-3 TOTAL 30-45 (liquids) 16-22 130-150 6-9 2-3 34 Multiphase pipelines from fields to FPSO for fluid separation, gas compression and living quarters MLHP 5

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SLIDE 35

MLHP-5 & 6 Prospect and Lead Inventory

Sanaga-1X 1st June 2009

  • Prospect inventory significantly enhanced with detailed

subsurface review of Block 5 & 6

  • Exploration focus on Miocene channelised turbidites and

Cretaceous lower slope turbidite deposits

  • 18 Prospects & Leads identified across the two blocks
  • Miocene predominately gas-condensate play (D1-r)
  • Cretaceous oil play

35

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SLIDE 36

Wet GIIP (bcf)* CIIP (mmbbl)† STOIIP (mmbbl) Delta‡ 175 10 Kappa 75 Lambda 12 1 Qof 595 33 Phi-chi 451 25 Psi 158 9 Pi 44 2 B t W

MLHP-5 & 6 Prospect and Lead Inventory

(Unrisked Mean In Place volumes)

1st June 2009

Beta W 88 Beta E 117 Beta S 417 e-Epsilon 17 1 e-Alpha 30 sub-Epsilon 1793 99 supra Zeta 350 19 Zayin 113 6 Zeta 295 16 Tau 296 16 Sigma 248 14

TOTALS 4547 251 727

*includes NGLs, which comprise condensate and LPGs .

† Condensate estimated at 55bbl/mmscf ref D-1r. ‡D1r Discovery is 40bcf mean in place resources additional to Delta prospect volumes.

Well location Source: IHS Energy Noble Energy O5 ‘Carmen’ Oil Discovery .

36

Sanaga-1X 1200ft Oil Shows

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SLIDE 37

Gabon Overview

Epaemeno Permit 50%

  • Block G4-211, 1340 km²
  • Second term ends August 2010

(50% relinquishment)

  • Third period expires Aug 2013
  • Addax (Operator); Bowleven

conducting G&G work through to

1st June 2009

well locations under TSA

  • $10m (net) exploration carry, $8m

(net) development carry East Orovinyare Permit 100%

  • Block G5-92, 105 km²
  • Exploitation permit over entire block

37

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SLIDE 38

Gabon - Epaemeno

Omko-1 (20MMbbl)

A A’

1st June 2009

  • Multiple potential reservoir targets:
  • Gamba/Dentale Sandstones (Traditional play)
  • Basal Sandstone (Evolving play)
  • Kissenda Sandstones (New play)
  • Post-Salt play
  • New seismic program exploring pre-salt plays

Tsiengui (145MMbbl) Obangue (55MMbbl) Koula (75MMbbl) Avocette (265MMbbl) Onal (180MMbbl)

2P STOIIP source: IHS Energy

Riviere Perdue-1

A A’

Rembo Kotto (60MMbbl) Assewe (18MMbbl)

38

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SLIDE 39

A

Gabon – EOV Permit – NW Kowe

A Azile Depth Map

1st June 2009

  • Simple tilted fault block structure.
  • Multiple stacked reservoir targets with robust closures.
  • Targets include the Batanga, Pt. Clairette, Anguille, Azile, and

Cap Lopez turbidite sands of the Upper Cretaceous.

  • Closure areas ranges from 2km2 to 15km2+.
  • Largest undrilled prospect in block.
  • Possible synergy development with EOV.
  • Mean STOIIP 190mmbbl (in penetrated targets).

A’

39

30km 10km A’

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SLIDE 40

1st June 2009