IF Oil Discovery Update Presentation - Bowleven PLC · IF Oil CPR Presentation 1st June 2009 8 8 Ed Willett, Exploration Director 8. Cameroon Acreage Position Bomono Permit 100% •

1st June 2009

IF Oil Discovery Update Presentation1st June 2009

1

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.

2

Presenters

• Kevin Hart, CEOKevin Hart

1st June 2009

• Ed Willett, Exploration Director

3

Ed Willett

Executive Summary

1st June 2009

444

Kevin Hart, CEO

4

Executive Summary

• TRACS report independently supports Bowleven’s view of 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 ylate 2011 assuming FPSO concept.

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.

• 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

IF Oil CPR Presentation

1st June 2009

888

Ed Willett, Exploration Director

8

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

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.

Appraise POS 65% Appraisal

High Case

Mid Case

MLHP-7 IF Field – CPR May 2009Evaluation Methodology


• 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

pappraisal program is required.

• Overall probability of commercial success is evaluated as 65%.

Appraise POS 65% Appraisal

High Case

Mid Case


1st June 2009

Appraise POS 65% Successful Mid Case

Low Case

12

IF-1r Discovery

• The CPR provides an unriskedassessment of the IF Field and gives a range of high, mid and low case outcomes.

High Case Areal Extent

IF-1R

Poor Data Zone?Gas Chimney

MLHP-7 IF Field – CPR May 2009GRV 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

IF-1R

Poor Data Zone?Gas Chimney

MLHP-7 IF Field – CPR May 2009GRV Derivation - Structural Interpretation


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 caseMid Case Areal Extent

(Includes Low Case Areal Extent)

Shale

Thin

Bed

s

TRACS CPI log with Reservoir Zonation

GR Res Rhobz-TNph-DT Vclay Phie

MLHP-7 IF Field – CPR May 2009N:G Derivation – Reservoir Zonation

OWC 6548ftMD

Cor

e

ft) 9

8%re

cove

ryD

ST

1 Ave. 3371 bopd, Peak 4184bopd ½” choke

TRACS CPR TopAmalgamatedSands pick.

1st June 2009

San

d 1

Sand 2

San

d 3

Shale

15

• 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.

Cor

e (4

55f

Shale

Thin

Bed

s




OWC 6548ftmd

Cor

e

ft) 9

8%re

cove

ryD

ST

1

Ave. 3371 bopd, Peak 4184bopd ½” choke


1st June 2009

Cross-section through Mid Case GRV Model

San

d 1

Sand 2

San

d 3

Shale

16



Cor

e (4

55f

Shale

Thin

Bed

s




OWC 6548ftmd

Cor

e

ft) 9

8%re

cove

ryD

ST

1

Ave. 3371 bopd, Peak 4184bopd ½” choke


1st June 2009

Cross-section through Mid Case GRV ModelCross-section through High Case GRV Model

San

d 1

Sand 2

San

d 3

Shale

17



Cor

e (4

55f


• 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

274.1mmbblSTOIIP

MLHP-7 IF Field – CPR May 2009STOIIP Calculation

Thin Beds 365 35% 72.7

Sand 1 390 78% 173.2Sand 2 13.5 82% 6.3Sand 3 65 54% 21.9

High Case Total 274.1

ZoneGRV

mcumN:G STOIIP

1st June 2009 18

Thin Beds 525 25% 74.7

Sand 1 290 70% 115.6Sand 2 6 82% 2.8Sand 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

194.5mmbblSTOIIP

Low Case

101.2mmbblSTOIIP

Thin Beds 450 15% 38.4Sand 1 190 58% 62.7Sand 2 0 82% 0Sand 3 0 54% 0

Low Case Total 101.2

High Case(Structure as Bowleven mapping)

(N:G higher than in IF-1r well)

274.1mmbblSTOIIP


1st June 2009

Appraisal Successful(POS 65%)

Mid Case(Structure as TRACS mapping)

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

194.5mmbblSTOIIP

Low Case(structure low; low pick and different depth

conversion over poor data area)(N:G lower than prognosed)

101.2mmbblSTOIIP

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• 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 2009Resource Calculation

Range of Recovery Factors

Average Recovery Factor 23.6% 27.3% 34.4%

1st June 2009 20

• Combining the STOIIP values and range of recovery factors probabilistically yield the CPR statement of contingent resources.

1C 2C 3CTotal STOIIP mmbbl 101.2 194.5 274.1Oil Contingent Resources mmbbl 23.9 53.1 94.3

MLHP 7

IE

ID

IMIC

Manyikebi

MLHP-7 IF Field – CPR May 2009TRACS 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 PlatformHost water injection facilities & mobile

drilling rig

IF

IF Development Wells 4* Producers 3 Injectors

Facilities

30kbpd oil, 45kbpd liquids, 36Mscfd gas

60kbwpd injection capability

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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

MLHP 7

IE

ID

IMIC

Manyikebi

MLHP-7 IF Field – CPR May 2009TRACS 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 PlatformHost 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


• Production start-up date Jan 2013.

• Uptime factor of 90% assumed.

• High Case: 27kbopd plateau until Q2 2020.

MLHP-7 IF Field – CPR May 2009Production 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 offtake (30kbopd is ~45% recoverable volumes per annum).

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• 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 2009Economic 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)

Bowleven Current View

1st June 2009

25252525

MLHP-7 IF Bowleven Interpretation Update

High Case Areal Extent


Bowleven In-house volumesSTOIIP P90

MMbblP50

MMbblP10

MMbblMeanMMbbl

Thin Bed zone 21 52 125 65

Massive Bedzone 79 142 244 153

TOTAL *MonteCarlo addition) 131 206 335 225

IF ContingentResource

P90MMbbl

P50MMbbl

P10MMbbl

MeanMMbbl

1st June 2009 26

Thin Bed zone 6 14 38 19

Massive Bedzone 30 57 105 63

TOTAL *MonteCarlo 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.).

MLHP-7 Current Development PotentialIF Oil Anticipated Ultimate Development Scenario

MLHP 7ID

IM

IC

Manyikebi

MLHP 7

IE

ID

Phase 1Oil Process: 30,000 bopdGas FlaredWater Overboard

Limbé

Phase 2Liquids: 60,000 bpdWater Injection: 60,000bpdGas Dehydration & Compression: 36 MMscfd

Phase 2:Fuel Gas

Pipeline to Limbé.

1st June 2009

MLHP 7IF

Phase Producers Injectors

1 2x Appraisal

2 2 2x Dry, 1x Subsea

3 (Contingent) 3 1

TOTAL 7 4

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MLHP 5

MLHP 7

MLHP 5

Appraisal well 1 (~2km)


FPSO:Spread moored, dynamic flexible production and

injection risers and umbilicals

Phase 2:9-Slot WHP2 prod. 3 inj.

MLHP-7 Current Development PotentialIF Oil Anticipated Ultimate Development Scenario

MLHP 7ID

IM

IC

Manyikebi

MLHP 7

IE

ID

Phase 1Oil Process: 30,000 bopdGas FlaredWater Overboard

Limbé

Phase 2Liquids: 60,000 bpdWater Injection: 60,000bpdGas 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 7IF

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



FPSO:Spread moored, dynamic flexible production and

injection risers and umbilicals

Phase 2:9-Slot WHP2 prod. 3 inj.

Subsea 20

Infield flowlines 26 31

FPSO installation 31 104

Subsea Flowlines 29 21

Total 106 209

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*

29

4 producers3 injectors

Drilling and WI:$10 million every 2years

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

1000

1200

1400

1600

1800

945

1179

1420

1656

009 US$million

IF Stand Alone Oil Development: Bowleven NPV225 mmbbls Mean STOIIP; CPR Costs; 30 mbpd

Economic Evaluation

1st June 2009 30

0

200

400

600

800

50 60 70 80

NPV

10 at 1

.7.20

Brent Real Oil Price US$/bbl

Remaining Assets

1st June 2009

313131

Ed Willett, Exploration Director

31

MLHP-7 Isongo and Biafra Inventory

IsongoGas CondensateFields -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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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

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IF-1r DST Flare

MLHP-7 Current Development PotentialIF Oil with IM-ID-IE Gas Condensate Development – Possible Synergies

MLHP 7

IE

ID

IM

IC

ManyikebiGas Injection

Pipeline

Potential tie-in of Isongo-Marine

gas-condensate

IE WHP PlatformLimbé

New oil processing & export facilities

Limbé Refinery and Power station

1st June 2009

MLHP 7

IF WHP Platform6-Slot Wellhead

IFIE WHP Platform9-Slot Wellhead

FieldOil/NGLsMbbl/d

Gas Export MMscf/d

Gas ProductionMMscf/d

Development Wells

Producers Injectors

IF 15-20 (oil) 16-22 - 3-4 0

ID-IE 15-25 (NGL) - 130-150 3-5 2-3

TOTAL 30-45 (liquids) 16-22 130-150 6-9 2-3

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Multiphase pipelines from fields to FPSO for fluid separation, gas compression and living quarters

MLHP 5

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

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Wet GIIP (bcf)* CIIP (mmbbl)† STOIIP (mmbbl)

Delta‡ 175 10Kappa 75Lambda 12 1Qof 595 33Phi-chi 451 25Psi 158 9Pi 44 2B t W

MLHP-5 & 6 Prospect and Lead Inventory(Unrisked Mean In Place volumes)

1st June 2009

Beta W 88Beta E 117Beta S 417e-Epsilon 17 1e-Alpha 30sub-Epsilon 1793 99supra Zeta 350 19Zayin 113 6Zeta 295 16Tau 296 16Sigma 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-1X1200ft Oil Shows

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

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

AA’

Rembo Kotto (60MMbbl)

Assewe (18MMbbl)

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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’

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30km10km

A’

1st June 2009

Documents

IF Oil Discovery Update Presentation - Bowleven PLC · IF Oil CPR Presentation 1st June 2009 8 8 Ed Willett, Exploration Director 8. Cameroon Acreage Position Bomono Permit 100% •