1st June 2009
IF Oil Discovery Update Presentation
1st June 2009
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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
1st June 2009
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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
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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Kevin Hart
1st June 2009
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Ed Willett
1st June 2009
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1st June 2009
5 j p y late 2011 assuming FPSO concept.
International Consultancy Ltd.
1C 2C 3C
Total STOIIP mmbbl
101.2 194.5 274.1
1st June 2009
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.
STOIIP mmbbl P90 P50 P10 Mean Total 131 206 335 225 Contingent Resource P90 P50 P10 Mean Total 44 76 130 82
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FPSO resulting in significant CAPEX savings.
block field integration (IE, IM, etc.).
IF-1r well DST Flare
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8
Bomono Permit 100%
commitment
IF Oil Discovery
1st June 2009
commitment Etinde Permit 100%
2008
three years from date of signing
commitment
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Competent Persons Report:
by Bowleven Plc to conduct an independent third party review and audit of the IF Oil Discovery.
1st June 2009
10
Trident IV Jack-up on IF-1r location Summer 2008.
POS 65%
Competent Persons Report:
area (IF-1r locale) is insufficient for commercial development and an
1st June 2009
POS 65%
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p appraisal program is required.
is evaluated as 65%.
POS 65%
1st June 2009
POS 65%
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assessment 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
Bowleven Structure (Mar ‘09)
(based on Green pick) 1st June 2009
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independent 4-way dip closure updip to the SE of the IF-1r discovery well.
compartmentalisation and more pessimistic time-depth conversion than encountered in IF-1r.
High case
IF-1R
Poor Data Zone ?Gas Chimney
Bowleven Structure (Mar ‘09)
(based on Green pick)
TRACS Structure Map (May ‘09)
(based on Yellow pick) 1st June 2009
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independent 4-way dip closure updip to the SE of the IF-1r discovery well.
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)
Shale Thin Beds TRACS CPI log with Reservoir Zonation
GR Res Rhobz-TNph-DT Vclay Phie
OWC 6548ftMD
Core
ft) 98%recovery
DST 1
Peak 4184bopd ½” choke TRACS CPR Top Amalgamated Sands pick. 1st June 2009
Sand 1 Sand 2 Sand 3 Shale
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input into STOIIP calculations.
Core (455f
Shale Thin Beds TRACS CPI log with Reservoir Zonation
GR Res Rhobz-TNph-DT Vclay Phie
OWC 6548ftmd
Core
ft) 98%recovery
DST 1
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
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input into STOIIP calculations.
Core (455f
Shale Thin Beds TRACS CPI log with Reservoir Zonation
GR Res Rhobz-TNph-DT Vclay Phie
OWC 6548ftmd
Core
ft) 98%recovery
DST 1
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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input into STOIIP calculations.
Core (455f
Competent Persons Report:
parameters are constant (based on core, log, MDT and test data):
High Case 274.1mmbbl STOIIP
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
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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
higher than in IF-1r well.
as encountered in IF-1r well.
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
(Structure as Bowleven mapping) (N:G higher than in IF-1r well)
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(Structure as TRACS mapping) (N:G as in IF-1r well)
(structure low; low pick and different depth conversion over poor data area) (N:G lower than prognosed)
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Competent Persons Report:
individual reservoir zones and combined probabilistically to derive an overall recovery factor.
Range of Recovery Factors Average Recovery Factor
23.6% 27.3% 34.4%
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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
MLHP 7
IE ID IM IC Manyikebi
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
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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 IM IC Manyikebi
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
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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
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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
Competent Persons Report:
1st June 2009
flow restricted due to unrealistically high
volumes per annum). 23
for high, mid and low cases.
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%)
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24 appraisal well is required to identify the failure case and a 65% POS.
proposed development would be appropriately re-scaled.
$65/bbl real (flat)).
Bowleven NPV (10%) mmUS$ 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 $/bbl (associated gas is excluded from evaluation)
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High Case Areal Extent
Bowleven Structure (Mar ‘09)
(based on Green pick)
Bowleven In-house volumes
STOIIP P90 MMbbl P50 MMbbl P10 MMbbl Mean MMbbl Thin Bed zone 21 52 125 65 Massive Bed zone 79 142 244 153 TOTAL *Monte Carlo addition) 131 206 335 225 IF Contingent Resource P90 MMbbl P50 MMbbl P10 MMbbl Mean MMbbl
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Thin Bed zone 6 14 38 19 Massive Bed zone 30 57 105 63 TOTAL *Monte Carlo addition) 44 76 130 82
FPSO resulting in significant CAPEX savings.
field integration (IE, IM, etc.).
IF Oil Anticipated Ultimate Development Scenario
MLHP 7
ID IM IC Manyikebi
MLHP 7
IE ID
Phase 1 Oil Process: 30,000 bopd Gas Flared Water Overboard
Limbé
Phase 2 Liquids: 60,000 bpd Water Injection: 60,000bpd Gas Dehydration & Compression: 36 MMscfd
Phase 2: Fuel Gas Pipeline to Limbé.
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MLHP 7
IF
Phase Producers Injectors 1 2x Appraisal 2 2 2x Dry, 1x Subsea 3 (Contingent) 3 1 TOTAL 7 4
27 MLHP 5 MLHP 7 MLHP 5
Appraisal well 1 (~2km) Appraisal well 2 (~2km)
FPSO: Spread moored, dynamic flexible production and injection risers and umbilicals Phase 2: 9-Slot WHP 2 prod. 3 inj.
IF Oil Anticipated Ultimate Development Scenario
MLHP 7
ID IM IC Manyikebi
MLHP 7
IE ID
Phase 1 Oil Process: 30,000 bopd Gas Flared Water Overboard
Limbé
Phase 2 Liquids: 60,000 bpd Water Injection: 60,000bpd Gas Dehydration & Compression: 36 MMscfd
Phase 2: Fuel Gas Pipeline to Limbé.
Cost Item Phase 1 ($Millions) Phase 2 ($Millions) Topsides
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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
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Infield flowlines
26 31
FPSO installation
31 104
Subsea Flowlines
29 21 Total 106 209
Case Total Estimated Capex (USD millions) Total Estimated Annual Opex (USD millions, Cost estimates from Genesis:
Initial well count: 4 producers
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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.
1000 1200 1400 1600 1800
IF Stand Alone Oil Development: Bowleven NPV 225 mmbbls Mean STOIIP; CPR Costs; 30 mbpd
1st June 2009
30 200 400 600 800 50 60 70 80
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31 31 31
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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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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
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
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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
ID-IE 15-25 (NGL)
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
Sanaga-1X 1st June 2009
subsurface review of Block 5 & 6
Cretaceous lower slope turbidite deposits
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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
(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 .
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Sanaga-1X 1200ft Oil Shows
Epaemeno Permit 50%
(50% relinquishment)
conducting G&G work through to
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well locations under TSA
(net) development carry East Orovinyare Permit 100%
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Omko-1 (20MMbbl)
A A’
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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)
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A
A Azile Depth Map
1st June 2009
Cap Lopez turbidite sands of the Upper Cretaceous.
A’
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30km 10km A’
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