Corporate Presentation December Coastal Energy Company 2012 All Rights Reserved

Transcription

1 Corporate Presentation December 2012 Coastal Energy Company 2012 All Rights Reserved

2 Forward Looking Statements 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 hydrocarbon reserves, production amounts or revenues, forward capital expenditures, operation costs, oil and gas price forecasts and similar matters are based on current data and information and should be viewed as forward-looking statements. Such statements are NOT guarantees of future results and are subject to risks and uncertainties beyond Coastal Energy s control. Actual results may differ substantially from the forward-looking statements. This presentation does not contain all of the information contained in the preliminary prospectus of Coastal Energy Company, which should reviewed for complete information. 2

3 Company Overview Operational Overview Asset Overview Production Current Production (boepd) 24,500 Offshore Production (oil) 22,500 3/31/2012 RPS Reserves 1 2P (Mmboe) % Oil 86% Increase vs. YE P 45% After Tax 2P PV 10 ($MM) $2,497.7 Prospective Resources (Recoverable Mmboe) (1) Per RPS Energy, Ltd. Reserve evaluation as of 3/31/2012 (2) Internal estimate offshore only Financial Overview ($US in millions, except shares / share price) Share Price (at 12/3/2012) C$19.16 Shares Outstanding Shares Outstanding, Fully Diluted Equity Value / Market Cap. $2,266.6 Debt (at 9/30/2012) $100.0 Cash (at 9/30/2012) $35.7 Enterprise Value $2,

4 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 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 2012 Exploration Success to Date 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) Growing Oil Production Profile 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 Note: 2012 reserve figures per RPS Energy Ltd. report as of March 31, 2012; prospective resource volumes are undiscovered and represent internal estimates 4

5 Field Overview Offshore Thailand Bua Ban North Songkhla 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 Current production ~3,500 bopd Appraisal & exploration of 89 Mmbbls of prospective resources Development / appraisal and water injection activities currently underway Bua Ban South Onshore March 2012 discovery; completion, fracking and appraisal activities currently underway 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 5

6 Substantial Organic Reserve Growth Mmboe 2P reserves at 3/31/2012 (86% oil/offshore, 59% 1P)* % increase over YE Near-term drilling program could result in significant additional uplift (Mmboe) 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, 2012 Note: Offshore prospective resources reflect internal estimates Offshore/Onshore (Mmboe): 3/31/12 2P / 21.4; 3P 34.2 / 3.2; Contingent 8.5 / 12.8; Prospective 453 / P YE P YE P Bua Ban North Addition 2P Bua Ban South Addition Other 2P 3/2012 3P 3/2012 Contingent Prospective 6

7 Track Record of Consistent Growth Production Growth EBITDA Growth $120/bbl $80/bbl Note: See EBITDA sensitivity slide for 2013 potential outcomes 2013 production expected to average 33,000 27,000 boepd offshore Thailand, 2,300 onshore Thailand, 3,700 boepd Malaysia (3Q commencement) 7

8 2013 EBITDAX Sensitivity Note: Assumes 2013 guidance of 33,000 boepd, $19/boe OpEx and $315 MM capital program 8

9 Robust 2013 Drilling Program ($US MM) % Drilling & Completions Offshore Thailand % Onshore Thailand 5 21 nm Malaysia nm Facilities (50%) Seismic 42 7 (82%) Other (46%) Total (13%) (1) Reflects capitalized startup costs (2) Reflects acquisition of additional interest in APICO and ARO 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 highimpact exploration activities offshore Thailand Expect first oil in Malaysia in July Onshore CapEx focused on development activities at Dong Mun field 9

10 Coastal Drilling Sequence 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 MOPU required Vicksburg Songkhla A17 Songkhla A14 Songkhla A15 Bua Ban South Appraisal Wells (4) G5/50 EXPL Well Bua Ban Main Workover ST 3 Wells G5/43 EXPL Songkhla M Songkhla H Development 4 Wells G5/43 EXPL Bua Ban North Terrace G5/43 EXPL Bua Ban Terrace G5/43 EXPL Benjarong F G5/43 EXPL Benjarong N MOPU required Manta Bua Ban North Development & Appraisal 8 Wells Malaysia Appraisal Drilling Bua Ban South Appraisal 3 Wells Bua Ban North Development 8 Wells HWU Bua Ban South Completion / Fracking Exploration Development Workover / Completion Appraisal Water Disposal/Injection Note: HWU = hydraulic workover unit 10

11 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 production Ending period for all calculations reflects 3/31/

12 Thailand Exploration & Appraisal

13 Highly Prospective Songkhla Basin Bua Ban Terrace Bua Ban North Songkhla J (Buried Hill II) Songkhla H Songkhla L Songkhla A Extensions Prospects Eocene Lower Oligocene Lower Miocene/ Up Oligocene Pre Tertiary Buried Hill Fields Eocene Lower Oligocene Lower Miocene Bua Ban South Songkhla M Benjarong South (Songkhla N) Note: Prospective resource volumes are undiscovered resources and represent internal estimates 13

14 Songkhla Field 2012 Drilling Campaign SA-10 SA-13 Encountered 550 Lower Oligocene sand oil column 212 net pay A record for the Songkhla Basin 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 SA Oil Column 212 Net Pay 2012 Drilling Campaign Planned Development Well Planned Water Injection Well 14

15 Songkhla Basin Miocene Trend A A 15

16 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 Miocene Oil-in-place estimates in millions of barrels - Blue discovered (393mmbbls) - Black prospective (666mmbbls) Areas without estimates require detailed mapping 16

17 Bua Ban North Field Highly Successful Exploration in 2011 Discovered successful Miocene trend in Songkhla basin 299 Mbbls STOIIP (Mmbbls) YE 2010 YE /31/2012 Change % 2P % Prospective % (1) Reflects internal estimates 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 Corporate Presentation July

18 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 Stratigraphic limit of M100 net sand Successful flow tests could result in significant reserve additions / reclassifications Potential to reclassify incremental 14.7 Mmbbls 3P Miocene reserves to 2P 18

19 Dong Mun Field Onshore Gas 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 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 19

20 Malaysian Risk Service Contract

21 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 21

22 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% 22

23 Comparison Between PSC and SFRSC * ** * Petroleum Income Tax Act **Corporate Income Tax Act 23

24 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 24

25 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 25

26 Appendix

27 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, , ,877,199, ,987,719, , , ,499,833, ,449,983, , , ,213,058, ,321,305, ,000 & 8,000 Total 3,437,703, Total 4,759,009,

28 Songkhla Basin 3-D Seismic 3-D seismic shoot covering entire Songkhla basin and G5/50 is complete Processing and interpretation in 1Q13 28

29 Bua Ban Main Field Lower Oligocene Sand depth closure from 8270 TVDSS LKO in C03 Additional Miocene targets similar to Bua Ban Main A-11 Plan on testing horizontal wells in Lower Oligocene to DNP increase productivity and recovery Plan to test concept of horizontal wells and multi-stage DNP fracturing in the Eocene DNP DNP Drill additional water injectors to enhance recovery Top Lower Lacustrine Shale Depth Structure Map Contour Interval: 100 feet TVDSS 29

30 2013 Projected Tax Assumes production, expenses and capital program outlined in 2013 guidance Tax calculation includes Petroleum Income Tax and Special Remuneratory Benefit Realized Crude Price Offshore EBITDAX ($MM) Cash Tax Rate (Due in 2013) Effective Tax Rate $ % 45.5% $ % 48.1% $ % 50.6% $ % 53.0% $ % 54.6% $ % 56.5% $ % 57.6% $ % 58.6% Note: Tax rate expressed as a percentage of EBITDAX Cash tax rate reflects actual amounts due in 2013 and is inversely related to commodity prices given large proportion of fixed amounts related to 2012 taxes Effective tax rate reflects taxes incurred in 2013 and includes amounts payable in

31 Share Price Performance / Coastal Milestones 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 Mmbbls Share repurchase announced A-10 Results Announced 31

32 Overview of Thailand Fiscal Terms

33 Thai I Regime (Onshore) 12.5% royalty rate Petroleum Income Tax (PIT) assessed at 50% of taxable income (revenues allowable deductions) 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 o o Pre-production intangibles are depreciated straight line over 10 years Post-production intangibles are fully expensed in the year incurred 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 33

34 Thai III Regime (Offshore) 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 allowable deductions) 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 o o Pre-production intangibles are depreciated straight line over 10 years Post-production intangibles are fully expensed in the year incurred Tangibles are depreciated straight line over 5 years 34

35 Special Remuneratory Benefit ( SRB ) 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 since inception 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 to actual drilling footage Resulting metric determines the SRB rate (0 75%) Tax assessed on Petroleum Profit Allowable deductions are: Royalty, Hedging Losses, Capital Expenditures, Operating Expenses, 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 35

36 Legal Disclaimer 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 limited number 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 in it 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 the information 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, any representations 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 written or 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 for any 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 any additional 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 written consent 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 the request 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 this Presentation 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 satisfy itself 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 with any 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 or expenses 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, or the 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 to such 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 should be made solely on the basis of the information contained in such prospectus. The delivery, making or distribution of this Presentation in or to persons in certain jurisdictions may be restricted by law and persons who receive this Presentation should inform themselves about, and observe, any such restrictions. Any failure to comply with these restrictions may constitute a violation of the laws of the relevant jurisdiction. In particular, this Presentation has not been approved by an authorised person pursuant to Section 21 of the Financial Services and Markets Act 2000 ( FSMA ) and accordingly, it is being communicated in the United Kingdom only to persons to whom this Presentation may be communicated without contravening the financial promotion prohibition in Section 21 of the FSMA. Those persons are described in the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 ( Order ) and include persons who fall within the category of person set out in Articles 19 and 49 of the Order. Any investment activity to which this Presentation relates in the United Kingdom is available to, and will only be engaged with such persons and this Presentation should not be acted or relied upon in the United Kingdom by persons of any other description. This Presentation has not been approved as a prospectus by the UK Financial Services Authority ( FSA ) under Section 87A of the FSMA and has not been filed with the FSA pursuant to the United Kingdom Prospectus Rules. No offer of securities in the Company is being or will be made in the United Kingdom in circumstances which would require such a prospectus to be prepared. The securities proposed to be issued by the Company (the "Common Shares") have not and will not be registered under the U.S. Securities Act of 1933, as amended (the "Securities Act") and may not be offered or sold in the United States except pursuant to an exemption from, or transactions not subject to, the registration requirements of the Securities Act. In addition, other than to a limited number of persons reasonably believed to be qualified institutional buyers (as defined in Rule 144A under the Securities Act), neither this Presentation nor any copy of it may be taken or transmitted into the United States or America or distributed directly or indirectly, in the United States of America or to any resident thereof except in compliance with the applicable U.S. securities laws. Any failure to comply with these restrictions may constitute a violation of applicable U.S. securities laws. By accepting this Presentation, the recipient represents and warrants that it is a person to whom this Presentation may be delivered or distributed without a violation of the laws of any relevant jurisdiction. This Presentation is not to be disclosed to any other person or used for any other purpose and any other person who receives this Presentation should not rely or act upon it. 36