corporate presentation december 2012.ppt€¦ · *per rps energy, ltd. reserve evaluation as of...
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© Coastal Energy Company 2012 | All Rights Reserved
Corporate PresentationDecember 2012
2Corporate Presentation December 2012
This presentation contains ‘forward-looking statements’ as defined by the applicable securities legislation.Statements relating to current and future drilling results, existence and recoverability of potential hydrocarbonreserves, production amounts or revenues, forward capital expenditures, operation costs, oil and gas priceforecasts and similar matters are based on current data and information and should be viewed as forward-lookingstatements. Such statements are NOT guarantees of future results and are subject to risks and uncertaintiesbeyond Coastal Energy’s control. Actual results may differ substantially from the forward-looking statements. Thispresentation does not contain all of the information contained in the preliminary prospectus of Coastal EnergyCompany, which should reviewed for complete information.
Forward Looking Statements
3Corporate Presentation December 2012
Company Overview
Operational Overview Asset Overview
Financial Overview($US in millions, except shares / share price)
Share Price (at 12/3/2012) C$19.16
Shares Outstanding 113.0
Shares Outstanding, Fully Diluted 117.7
Equity Value / Market Cap. $2,266.6
Debt (at 9/30/2012) $100.0
Cash (at 9/30/2012) $35.7
Enterprise Value $2,330.9
Production
Current Production (boepd) 24,500
Offshore Production (oil) 22,500
3/31/2012 RPS Reserves1
2P (Mmboe) 149.1
% Oil 86%
Increase vs. YE 2011 2P 45%
After‐Tax 2P PV‐10 ($MM) $2,497.7
Prospective Resources (Recoverable ‐ Mmboe)2 453.2
(1) Per RPS Energy, Ltd. Reserve evaluation as of 3/31/2012 (2) Internal estimate ‐ offshore only
4Corporate Presentation December 2012
Note: 2012 reserve figures per RPS Energy Ltd. report as of March 31, 2012; prospective resource volumes are undiscovered and represent internal estimates
Investment Highlights
Highly Prospective Inventory / Significant Asset Base
Opportunity to de-risk 660 Mmbbls unrisked oil-in-place by year-end 2013
>30 identified prospects comprising 450 Mmbbls offshore prospective resources
1.4 million acres in Gulf of Thailand; Malaysian RSC covering 3 fields
Opportunity to de-risk 660 Mmbbls unrisked oil-in-place by year-end 2013
>30 identified prospects comprising 450 Mmbbls offshore prospective resources
1.4 million acres in Gulf of Thailand; Malaysian RSC covering 3 fields
2011 Material Exploration Success Highly successful drilling program targeting shallow Miocene at Bua Ban North
Added 56 Mmbbls 1P, 68 Mmbbls 2P in 2011 at Bua Ban North; +102% total 2P y/y
Highly successful drilling program targeting shallow Miocene at Bua Ban North
Added 56 Mmbbls 1P, 68 Mmbbls 2P in 2011 at Bua Ban North; +102% total 2P y/y
2012 Exploration Success to Date Added 40 Mmbbls 2P Bua Ban North & 20 Mmbbls 3P Bua Ban South at 3/31/2012 Added 40 Mmbbls 2P Bua Ban North & 20 Mmbbls 3P Bua Ban South at 3/31/2012
Industry Leading F&D Costs 5-year F&D cost of $3.27/boe ($4.35/boe including facilities CapEx) 5-year F&D cost of $3.27/boe ($4.35/boe including facilities CapEx)
Growing Oil Production Profile Current production ~24,500 boepd, >90% offshore oil (+104% vs. 3Q11)
33,000 boepd 2013 guidance (+50% y/y)
Current production ~24,500 boepd, >90% offshore oil (+104% vs. 3Q11)
33,000 boepd 2013 guidance (+50% y/y)
Strong Management and Shareholder Support
Highly incentivized management team and employees
70% of outstanding shares owned by management and top 4 shareholders
Highly incentivized management team and employees
70% of outstanding shares owned by management and top 4 shareholders
5Corporate Presentation December 2012
Field Overview
Offshore Thailand
Bua Ban North
Current production ~18,000 bopd
Booked 68 Mmbbl 2P in 2011; added 40 Mmbbl 2P at 3/31/2012
Appraisal & exploration of 70 Mmbbl of prospective resources
Early 2013 development and appraisal drilling planned
Songkhla
Current production ~3,500 bopd
Appraisal & exploration of 89 Mmbbls of prospective resources
Development / appraisal and water injection activities currently underway
Bua Ban South
March 2012 discovery; completion, fracking and appraisal activities currently underway
Onshore
Sinphuhorm gas field current production ~2,000 boepd
15-year Gas Sales Agreement with Nam Phong power plant
Dong Mun discovery being evaluated for development
10 Mmboe contingent resources
6Corporate Presentation December 2012
51.0
102.8 40.4 5.3 0.5 149.1
37.4 8.5
484.8
0
100
200
300
400
500
600
700
800
2P YE 2010 2P YE 2011 2P Bua BanNorth Addition
2P Bua BanSouth Addition
Other 2P3/2012
3P3/2012
Contingent Prospective
(Mmbo
e)
Substantial Organic Reserve Growth
149 Mmboe 2P reserves at 3/31/2012 (86% oil/offshore, 59% 1P)*
45% increase over YE11
Near-term drilling program could result in significant additional uplift
Opportunity to de-risk ~660 Mmbbls of unrisked oil-in-place through year-end 2013
*Per RPS Energy, Ltd. Reserve evaluation as of March 31, 2012Note: Offshore prospective resources reflect internal estimatesOffshore/Onshore (Mmboe): 3/31/12 2P – 127.7 / 21.4; 3P – 34.2 / 3.2; Contingent – 8.5 / 12.8; Prospective – 453 / 31.6
7Corporate Presentation December 2012
Track Record of Consistent Growth
Production Growth EBITDA Growth
2013 production expected to average 33,000 27,000 boepd offshore Thailand, 2,300 onshore Thailand, 3,700 boepd Malaysia (3Q commencement)
Note: See EBITDA sensitivity slide for 2013 potential outcomes
$80/bbl
$120/bbl
8Corporate Presentation December 2012
2013 EBITDAX Sensitivity
Note: Assumes 2013 guidance of 33,000 boepd, $19/boe OpEx and $315 MM capital program
9Corporate Presentation December 2012
Robust 2013 Drilling Program
2013 FCF of $200 MM post CapEx and taxes at $100 realized oil price
2013 CapEx budget of $315 MM ~13% below 2012 due to substantially lower facilities expenditures while including a 2 rig program
Two rig program will permit mix of production enhancing development drilling and high-impact exploration activities offshore Thailand
Expect first oil in Malaysia in July
Onshore CapEx focused on development activities at Dong Mun field
($US MM) 2012 2013 %
Drilling & Completions
Offshore Thailand 130 153 18%
Onshore Thailand 5 21 nm
Malaysia1 5 42 nm
Facilities 162 81 (50%)
Seismic 42 7 (82%)
Other2 19 10 (46%)
Total 362 315 (13%)
(1) Reflects capi ta l i zed s tartup costs
(2) Reflects acquis i tion of addi tiona l interest in APICO and ARO
10Corporate Presentation December 2012
Rig Nov‐12 Dec‐12 Jan‐13 Feb‐13 Mar‐13 Apr‐13 May‐13 Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13
Vicksburg
Manta
HWU
Coastal Drilling Sequence
Songkhla A14
Songkhla A15
Songkhla A17
Bua Ban North
Development & Appraisal
8 Wells
Malaysia Appraisal Drilling
Bua Ban
South
Appraisal
Wells (4)
Bua Ban
South
Completion
/ Fracking
Bua Ban North
Development 8 Wells
Bua Ban South
Appraisal 3
Wells
G5/50 EXPL W
ell
Bua Ban Main
Workover ST 3
Wells
G5/43 EXPL
Songkhla M
G5/43 EXPL B
ua B
an North Terrace
G5/43 EXPL B
ua B
an Terrace
G5/43 EXPL
Benjarong F
G5/43 EXPL
Benjarong N
Songkhla H
Development 4
Wells
Exploration AppraisalDevelopment Water Disposal/InjectionWorkover / Completion
Note: HWU = hydraulic workover unit
MOPU required
MOPU required
11Corporate Presentation December 2012
Industry Leading F&D Costs
F&D Cost ($/boe) (Including Facilities CapEx) F&D Cost ($/boe) (Excluding Facilities CapEx)
<$400 MM total CapEx (excluding facilities) between Jan’08 - Mar’12
~122 Mmboe added between Jan’08 - Mar’12, net of production
Note: F&D cost calculated as cumulative period CapEx divided by period ending 2P reserves less period beginning 2P reserves plus cumulative period productionEnding period for all calculations reflects 3/31/2012
Thailand Exploration & Appraisal
13Corporate Presentation December 2012
Prospects
Lower Miocene/Up Oligocene
Eocene
Pre‐Tertiary Buried Hill
Lower Oligocene
Highly Prospective Songkhla Basin
Bua Ban North
Songkhla A Extensions
Bua Ban South
Bua Ban Terrace
Songkhla H
Benjarong South (Songkhla N)
Songkhla J (Buried Hill II)
Eocene
Lower Oligocene
Lower Miocene
Fields
Note: Prospective resource volumes are undiscovered resources and represent internal estimates
Songkhla L
Songkhla M
14Corporate Presentation December 2012
2012 Drilling Campaign
SA-10
Encountered 550’ Lower Oligocene sand oil column
212’ net pay
A record for the Songkhla Basin
SA-13
67 feet of Lower Oligocene net pay with 18% porosity
Evaluating updip location for confirmation well
Water injection wells required for eastern fault blocks due to lack of aquifer support
89 Mmbbls prospective resources (recoverable)
A-19 water injector found 100 feet Miocene M100 with 20-35% oil saturation, providing evidence of oil migration throughout Miocene in Songkhla area; evaluation of new 3-D to detect structural closures
Songkhla Field
Planned Development Well
2012 Drilling Campaign
SA10 550’ Oil Column 212’ Net Pay
Planned Water Injection Well
15Corporate Presentation December 2012
Songkhla Basin Miocene Trend
A A’
16Corporate Presentation December 2012
Miocene Oil-in-place estimates in millions of barrels- Blue discovered (393mmbbls)- Black prospective (666mmbbls)
Areas without estimates require detailed mapping
Songkhla Basin Miocene Trend
2012 Development & Appraisal
Continue delineation of Bua Ban North A & B Reserve additions Production
Additional drilling in Songkhla area Reserve additions Production & pressure maintenance
G5/43 Miocene Trend is very prolific
Only two Miocene grabens drilled Bua Ban North and Bua Ban South Both discovered oil
17Corporate Presentation July 2012
Highly Successful Exploration in 2011
Discovered successful Miocene trend in Songkhla basin
299 Mbbls STOIIP
3/31/2012 increases based on additional drilling and core analysis performed subsequent to year-end 2011
Producing approximately 18,000 bopd
Two recent successful horizontal development wells
Further drilling required to determine extent of field
Bua Ban North Field
(Mmbbls) YE 2010 YE 2011 3/31/2012 Change %2P 0.0 67.9 108.3 40.4 60%
Prospective1 0.0 64.0 70.1 6.1 10%(1) Reflects internal estimates
18Corporate Presentation December 2012
Stratigraphic limit of M100 net sand
Stratigraphic limit of M100 net sand
Stratigraphic limit of M100 net sand
Bua Ban South Field
A-04 and A-05 wells encountered Miocene pay in same reservoir as Bua Ban Main A-11
No Miocene oil water contact encountered yet
Could be materially lower than current depths
A-06 well will test eastern boundary
47 Mmbbls prospective resources (recoverable)
21 Mmbbls associated with potential fracking success
Fracking of BBS 1 & 3 underway
Booked 5.3 Mmbbls 2P, 20.0 Mmbbls 3P reserves at 3/31/2012
All associated with Miocene
Successful flow tests could result in significant reserve additions / reclassifications
Potential to reclassify incremental 14.7 Mmbbls 3P Miocene reserves to 2P
19Corporate Presentation December 2012
Likely Commercial Development Potential CNG for Natural Gas Vehicles 53 km pipeline to Nam Phong 24 Mmscfd gross from 4 wells (20 yrs)
60 Bcf contingent (recoverable) net to Coastal’s 40% interest
107.4 Bcf net incremental prospective resources (recoverable)
Dong Mun-3st (1Q12)
Confirmed G/W contact Improved reservoir
Milestones Commerciality approval (DMF) by 1Q13 Gas Sales Agreement by 2Q13 EIA/ONEP Approval by 3Q13 First Gas 4Q14
Dong Mun Field – Onshore Gas
Malaysian Risk Service Contract
21Corporate Presentation December 2012
Background
Coastal entered into a Risk Service Contract with PETRONAS for the development of the Kapal, Banang and Meranti fields (KBM) offshore Peninsular Malaysia
Coastal will be a 70% partner and a local Malaysian contractor (to be named later) will be a 30% partner
The contract requires the drilling of 17 wells: 10 wells at Kapal, 4 wells at Banang and 3 wells at Meranti
Once the wells are drilled, Coastal will operate the production facilities and coordinate oil liftings, operating cost disbursements, etc.
There are existing discoveries at each field. Coastal estimates recoverable oil could be anywhere from 15 to 35 Mmbbl
Additional upside from exploration prospects
22Corporate Presentation December 2012
Overview of Terms
The contract duration is 8 years ; the KBM SFRSC model strikes a balance in sharing of risks with fair returns for development and production of already discovered fields
PETRONAS remains the project owner while Contractors (Coastal and partners) are the service provider
Contractor will incur upfront costs for Petroleum Development and Operations and will be reimbursed upon first commercial production; the contractor will also be entitled to a Remuneration Fee per barrel from a pre-determined percentage of the field revenue
The reimbursement and remuneration are tied to cost and production performances; priority of payment shall be cost reimbursement of CAPEC and OPEX, followed by Remuneration Fee
Contractors are subjected to the Corporate Income Tax Act (CITA) and not the Petroleum Income Tax Act (PITA). Corporate tax payable by the Contractor Group under CITA is at the prevailing rate of 25%
23Corporate Presentation December 2012
Comparison Between PSC and SFRSC
***
* Petroleum Income Tax Act**Corporate Income Tax Act
24Corporate Presentation December 2012
Anticipated Costs / Timeline
First oil from Kapal field is expected beginning of 3Q13
The Capital Expenditure (CAPEX) of KBM Cluster is estimated to be USD320 million over 3 years
Coastal expects to fast track development of the fields using MOPUs and FSOs similar to how it has fast tracked development of its Gulf of Thailand assets
25Corporate Presentation December 2012
Conclusions
Songkhla Basin has significant upside Established Plays
Miocene Grabens Lower Oligocene Eocene Pre-Tertiary
New Play Development
Onshore Exploration Huge undrilled structures Lack of 3D Seismic Lack of Completion Technology
Horizontal Wells Fracture Technology
Business Development Significant Discoveries Undeveloped throughout Asia
Appendix
27Corporate Presentation December 2012
Further Exploration Potential
Richest source facies in the Songkhla basin are found within the lower Oligocene balanced-fill lake phase, an extensive carbonate‐rich interval with analogies to the Qingshankou and Nenjiang source strata in the Songliao Basin of China
Reservoirs associated with this lake type include lake marginal carbonate strata, lake marginal beach deposits, and deltaic facies that would tend to be restricted to the lake margin
Source rock is currently sitting in oil window; start of oil window is estimated to be between 6,250 - 10,000 feet
Thickness of source rock ranges from 77 feet to 300 feet in the center of the basin
Total Petroleum System Evaluation
Contour (ft) Acres Barrels of Oil (possible) Barrels Recoverable (assuming 10% recovery factor)
10,000.00 17,078.73 19,877,199,359.56 1,987,719,935.96
8,000.00 96,577.08 14,499,833,844.09 1,449,983,384.41
6,250.00 88,006.43 13,213,058,545.69 1,321,305,854.57
10,000 & 8,000 Total 3,437,703,320.37
Total 4,759,009,174.94
28Corporate Presentation December 2012
3-D seismic shoot covering entire Songkhla basin and G5/50 is complete
Processing and interpretation in 1Q13
Songkhla Basin 3-D Seismic
29Corporate Presentation December 2012
Lower Oligocene Sand depth closure from 8270 TVDSS LKO in C03
Top Lower Lacustrine Shale Depth Structure Map
Contour Interval: 100 feet TVDSS
DNP
DNP
DNP
DNP
Additional Miocene targets similar to Bua Ban Main A-11
Plan on testing horizontal wells in Lower Oligocene to
increase productivity and recovery
Plan to test concept of horizontal wells and multi-stage
fracturing in the Eocene
Drill additional water injectors to enhance recovery
Bua Ban Main Field
30Corporate Presentation December 2012
Assumes production, expenses and capital program outlined in 2013 guidance
Tax calculation includes Petroleum Income Tax and Special Remuneratory Benefit
Note: Tax rate expressed as a percentage of EBITDAXCash tax rate reflects actual amounts due in 2013 and is inversely related to commodity prices given large proportion of fixed amounts related to 2012 taxesEffective tax rate reflects taxes incurred in 2013 and includes amounts payable in 2014
2013 Projected Tax
Realized Crude Price
Offshore EBITDAX ($MM)
Cash Tax Rate (Due in 2013)
Effective Tax Rate
$85.00 543.5 26.7% 45.5%$90.00 587.1 25.5% 48.1%$95.00 630.6 24.2% 50.6%$100.00 675.8 23.0% 53.0%$105.00 723.7 22.0% 54.6%$110.00 771.7 20.9% 56.5%$115.00 819.7 20.2% 57.6%$120.00 867.7 19.6% 58.6%
31Corporate Presentation December 2012
Share Price Performance / Coastal Milestones
Share repurchase announced
Bua Ban South adds 23.5 Mmbbls 2P reserves with additional 31.0 Mmbbls of
prospective resources for total of 54.5 Mmbbls recoverable (81% of pre-drill estimate)
Announced commencement of Bua Ban South exploration. Pre-drill estimate was
67 Mmbbls of prospective resources
Announced YE11 2P reserves of 103.0 Mmbbls
A-10 Results
Announced
Overview of Thailand Fiscal Terms
33Corporate Presentation December 2012
12.5% royalty rate
Petroleum Income Tax (PIT) assessed at 50% of taxable income (revenues – allowabledeductions)
Allowable deductions for PIT are as follows:
Operating Expenditures
Hedging Losses
G&A expenses related to the petroleum operations
Capital expenditures under the following depreciation rules
o Pre-production intangibles are depreciated straight line over 10 years
o Post-production intangibles are fully expensed in the year incurred
o Tangibles are depreciated straight line over 5 years
Royalties are not deductible; however, the operator receives a PIT credit for royalties paid,lowering the effective tax rate
“Thai I” Regime (Onshore)
34Corporate Presentation December 2012
Royalty payable on a sliding scale determined by monthly production volume (5 – 15%)
Daily production of 25,000 bopd results in an approximate 11% royalty rate
Petroleum Income Tax (PIT) assessed at 50% of taxable income (revenues – allowabledeductions)
Allowable deductions for PIT are as follows:
Royalties
Operating Expenditures
Hedging Losses
G&A expenses related to the petroleum operations
Special Remuneratory Benefit (“SRB”) payments
Capital expenditures under the following depreciation rules
o Pre-production intangibles are depreciated straight line over 10 years
o Post-production intangibles are fully expensed in the year incurred
o Tangibles are depreciated straight line over 5 years
“Thai III” Regime (Offshore)
35Corporate Presentation December 2012
Designed as a “Windfall Profits Tax” for high oil price environments
Assessed on a sliding scale basis determined by “Revenue per Meter Drilled”
Petroleum Revenue is adjusted for inflation and exchange rate fluctuations sinceinception of the concession and then divided by total meters drilled on the concession
Coastal’s offshore concessions provide a 600,000 meter “allowance” to be added toactual drilling footage
Resulting metric determines the SRB rate (0 – 75%)
Tax assessed on “Petroleum Profit”
Allowable deductions are: Royalty, Hedging Losses, Capital Expenditures, OperatingExpenses, G&A
All Capex is expensed as incurred, with a special 35% “uplift” on facilities capex
Allows for full capital recovery plus uplift
Coastal had an approximate $165MM loss carryforward for SRB purposes at year end 2011
SRB is deductible for PIT purposes
Special Remuneratory Benefit (“SRB”)
36Corporate Presentation December 2012
The information contained in this presentation (“Presentation”) has been prepared by Coastal Energy Company (“Company”) and is being delivered for informational purposes only to a limitednumber of persons to assist them in deciding whether or not they have an interest in investing in the Company. The Presentation has not been independently verified and the information contained init is subject to updating, completion, revision, verification and further amendment. The Presentation does not purport to contain all information that a prospective investor may require. While theinformation contained in it has been prepared in good faith, neither the Company nor its shareholders, directors, officers, agents, employees, or advisors give, has given or has authority to give, anyrepresentations or warranties (express or implied) as to, or in relation to, the accuracy, reliability or completeness of the information in this Presentation, or any revision thereof, or of any other writtenor oral information made or to be made available to any interested party or its advisers (all such information being referred to as “information”) and liability therefore is expressly disclaimed.Accordingly, neither the Company nor any of its shareholders, directors, officers, agents, employees or advisers take any responsibility for, or will accept any liability whether direct, express or implied,contractual, torturous, statutory or otherwise, in respect of the accuracy or completeness of the information or for any of the opinions contained in, or for any errors, omissions or misstatements or forany loss, howsoever arising from the use of this Presentation. In furnishing this Presentation, the Company does not undertake or agree to any obligation to provide the recipient with access to anyadditional information or to update this Presentation or to correct any inaccuracies in, or omissions from, this Presentation which may become apparent.Information contained in this Presentation is confidential information and the property of the Company. It is made available strictly for the purposes referred to above.The Presentation and any further confidential information made available to any recipient must be held in complete confidence and documents containing such information may not be reproduced,used or disclosed without the prior written consent of the Company. This Presentation must not be copied, published, reproduced or distributed in whole or in part at any time without the prior writtenconsent of the Company and by accepting the delivery or making to it of this Presentation, the recipient agrees not to do so and to return any written copy of this Presentation to the Company at therequest of the Company.This Presentation should not be considered as the giving of investment advice by the Company or any of its shareholders, directors, officers, agents, employees or advisors. Each party to whom thisPresentation is delivered or made must make its own independent assessment of the Company after making such investigations and taking such advice as may be deemed necessary. In particular,any estimates or projections or opinions contained in this Presentation necessarily involve significant elements of subjective judgement, analysis and assumption and each recipient should satisfyitself in relation to such matters. Neither the delivery or making of this Presentation nor any part of its contents is to be taken as any form of commitment on the part of the Company to proceed withany transaction and the right is reserved to terminate any discussions or negotiations with any prospective investors. In no circumstances will the Company be responsible for any costs, losses orexpenses incurred in connection with any appraisal or investigation of the Company.This Presentation does not constitute, or form part of, any offer or invitation to sell or issue, or any solicitation of any offer to subscribe for or purchase any securities in the Company, nor shall it, orthe fact of its delivery, making or distribution, form the basis of, or be relied upon in connection with, or act as any inducement to enter into, an contract or commitment whatsoever with respect tosuch securities. Any such solicitation or offer will be made by means of a prospectus to be issued by the Company in due course and any decision to subscribe for securities in the Company shouldbe made solely on the basis of the information contained in such prospectus.
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