Corporate Presentation February PDF Free Download

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

Offshore Thailand Onshore Thailand Total Company 32.9 mmbl of 2P Reserves 10,500 bopd avg. production $5.23 per share post-tax 2P NAV 22.1 mmboe of 2P Reserves 2,000 boe/d avg. production $1.84 per share post-tax 2P NAV 55.0 mmboe of 2P Reserves 12,500 boe/d avg. production $7.07 per share post-tax 2P NAV Offshore Thailand Two fields currently producing Songkhla Field: Successful appraisal and exploration has added over 80 mmbbl of oil in place in the Oligocene and Eocene Currently producing approximately 7,500 bopd Bua Ban Field: First phase of development drilling is complete Currently producing approximately 3,000 bopd Exploration program targeting over 150 mmbbl of prospective resources in 1H2011 Onshore Thailand EU1 / E5N contains the Sinphuhorm gas field Currently producing 2,000 boepd Gas sold to Nam Phong power plant under a 15-year Gas Sales Agreement A 3D seismic program is underway over the Sinphuhorm field Note: Reserve numbers from Competent Person s Report dated 12/31/2009 prepared by Huddleston & Co. 3

Investment Highlights Key Highlights Growing Oil Focused Production Profile Established production base of 12,500 boepd which is 85% offshore oil and 15% onshore natural gas (natural gas pricing is based on oil products) Significant Acreage and Drilling Inventory with substantial upside potential High impact exploration drilling in 2011 testing over 150 mmbbl of prospective resources 1.4 million acres in the Gulf of Thailand and over 30 identified prospects (1 million acres is contiguous in the southern area of the block and the remaining 400,000 is contiguous in the northern area) Cost-effective Shallow Water Development Use of mobile platforms and FSOs lowers operating costs and F&D costs Strong Management and Shareholder Support 70% of outstanding shares owned by management and top 4 shareholders 4

Growing Production Profile 2010 Highlights Drilling Program Average Daily Production First phase of Bua Ban field development is complete Successful exploration and appraisal drilling of the Lower Oligocene Wedge and Eocene reservoirs at Songkhla 2011 Highlights Exploration drilling targeting over 150 mmbbl of prospective resources in the first half of the year Planned fracture stimulation at Benjarong and Bua Ban underway Exploration at Bua Ban North beginning in early February 2011 capex program of $150MM: 50% development drilling and 50% exploration drilling 5

2011 EBITDAX Sensitivity 6

Company Snapshot Financial Information Cash (as at 9/30/10) $27MM Total Debt (as at 9/30/10) $58MM Share Price (as at 2/7/11) C$7.86 After-tax 2P NAV per share (fully diluted) C$7.07 Current Market Cap $890MM Shares Outstanding 111,563,430 Shares Outstanding, fully diluted 113,235,224 Proven Reserves (After-tax PV10) Offshore Onshore Total Proven + Probable Proven + Probable + Possible 15.2 mmbbl ($345 MM) 32.9 mmbbl ($577 MM) 48.4 mmbbl ($737 MM) 8.0 mmboe ($108 MM) 22.1 mmboe ($204 MM) 22.1 mmboe ($204 MM) 23.2 mmboe ($453 MM) 55.0 mmboe ($781 MM) 70.5 mmboe ($941 MM) Production 10,500 bopd 2,000 boepd 12,500 boepd *Average of analyst estimates at Stifel Nicolas Weisel, Paradigm Captal, Canaccord Genuity and Macquarie Capital 7

Summary of Exploration Plan Between now and June 2011 we will test prospects with unrisked prospective recoverable resources of 150 mmbbl: Bua Ban Eocene (50 mmbbl); fracture testing to begin February 2011 Bua Ban North (Lower Oligocene 15 mmbbl, Miocene 15 mmbbl, Eocene 45 mmbbl); drilling of multiple exploration prospects scheduled to begin in February 2011 Bua Ban South Miocene (35 mmbbl); scheduled to begin exploration/appraisal drilling in late Q1 2011; to the south of the two Bua Ban wells which have already encountered productive Miocene sands 9

Offshore Exploration Plan 150 mmbbl of Prospective Resources 2 0 1 1 Feb Mar Apr May Jun Jul Aug B L O C K G 5 / 4 3 Bua Ban Benjarong Drill Bua Ban North A, B and C Oligocene, Eocene and Miocene Exploration prospects (up to 75 mmbbl potential recoverable) Fracture test of A-04 & A-07 Eocene (50 mmbbl potential for entire play) Acid stimulation and frac of A-02 well (10 20 mmbbl potential) Drill up 2 Miocene exploration and 6 Lower Oligocene development wells at Bua Ban South (up to 35 mmbbl potential) Fracture test of A-01 well (50 mmbbl potential) Test of Lacustrine shale at Bua Ban Main (50 100 mmbbl potential) By June 2011 we will have tested over 150 mmbbl of prospective resources Songkhla A Complete drilling of exploration wells Legend In Progress Planned 10

Songkhla Bua Ban Producing approximately 7,500 bopd Reserve and production upside has been confirmed with the successful exploration of Songkhla East Oligocene and Eocene Field 2P reserves of 11.1 mmbbl Producing approximately 3,000 bopd A-03 and A-11 Micoene wells under evaluation along with A- 04 and A-07 Eocene wells Field 2P reserves of 21.8 mmbbl Exploration Upside Acid and fracture stimulations planned at Bua Ban and Benjarong to begin in late January Bua Ban Eocene (50 mmbbl potential) Bua Ban South Miocene (35 mmbbl potential) Bua Ban North Eocene, Miocene & Lower Oligocene (75 mmbbl aggregate potential) Unconventional Lacustrine Shale (50 100 mmbbl potential) 11

Songkhla A: Oligocene SA-07ST Songkhla Exploration Results Well Interval Net Pay Porosity A-09 Oligocene 140 feet 15% Eocene 75 feet 16.5% A-11 Oligocene 44 feet 18% Eocene 69 feet 21% A-12 Oligocene 105 feet 20% Eocene 43 feet 19% Producer Injector SA 12ST Songkhla East drilling results confirm migration east of the Songkhla Wedge Further appraisal and exploration drilling will be required to determine areal extent SA-07 sidetrack is currently being drilled An additional 5 development wells are currently planned 80 mmbbl of oil in place discovered in Oligocene and Eocene by recent drilling 12

Songkhla A: Eocene 80 Net Pay (TVDFT) in Eocene Oil in Eocene Eocene Development Proposed Location 69 52 136 47 Well Interval Net Pay Porosity A-07 Eocene 140 feet 17% A-09 Eocene 52 feet 21% A-11 Eocene 69 feet 21% A-12 Eocene 0 feet N/A A-12ST Eocene 47 feet 19% Songkhla Eocene mapping is still in progress The Eocene appears to be highly faulted 1000 m Top Corporate Eocene Presentation depth February structure 2011 13

Bua Ban Terrace C 01 Bua Ban North B 01 Bua Ban North Basin Exploration Prospects 1H 2011 Bua Ban Miocene I 01 Bua Ban North A 01 Prospect Interval Prospect Depth (Feet) Unrisked STOOIP (MMBO) P50 Unrisked Recoverable (MMBO) P50 Bua Ban North A Oligocene/Eocene 8000 42 8 Bua Ban North B Oligocene/Eocene 7800 72 14 Bua Ban Terrace C Oligocene/Eocene 5800 139 28 Bua Ban Field Bua Ban Miocene I Miocene/ Eocene 3500 20 8 Total 266 53 Bua Ban South 14

Significant Exploration Upside Potential in the Eocene Reservoir Porosity vs. Depth in Eocene Reservoir Drilled to date To be drilled in 1H11 Higher quality Eocene sands are expected on the northern exploration prospects planned for 1H11 drilling 15

Prospective Bua Ban Resources P50 ( Base ) Case Prospect Depth Unrisked (P50) Unrisked (P50) Prospect Well Interval (TVD Seismic ft) STOOIP (MMBO) Recoverable (MMBO) Bua Ban Northeast Bua Ban North B 01 Oligocene 6200 17.026 3.405 Eocene 7800 39.854 3.985 Bua Ban G Miocene Miocene 3370 6.015 1.944 Bua Ban North D Oligocene Oligocene 6470 4.700 0.940 Total 67.595 10.274 Bua Ban Northwest Bua Ban Terrace C Oligocene Oligocene 5100 36.119 7.224 Eocene 5800 114.940 22.988 Bua Ban Terrace E Eocene Eocene 5550 38.999 7.800 Bua Ban H Miocene Miocene 3370 4.136 0.620 Bua Ban I Miocene Miocene 3340 13.069 1.960 Bua Ban M Miocene Miocene 2640 4.905 0.736 Total 212.168 41.328 Bua Ban North Central Bua Ban North A 01 Oligocene 7080 15.065 3.013 Eocene 7950 40.941 4.094 Bua Ban North E Oligocene Oligocene 5500 7.519 1.504 Bua Ban Terrace F Eocene Eocene 5700 57.051 11.410 Bua Ban D Miocene Miocene 3175 6.015 3.357 Bua Ban E Miocene Miocene 3370 5.478 1.987 Bua Ban F Miocene Miocene 3280 4.082 1.171 Total 136.151 26.536 Bua Ban South Bua Ban Terrace G Eocene Eocene 5775 32.905 6.581 Bua Ban Terrace H Eocene Eocene 7775 37.264 3.726 Bua Ban B Miocene Miocene 2630 2.126 13.406 Bua Ban C Miocene Miocene 2400 19.514 4.839 Bua Ban J Miocene Miocene 2660 4.368 1.848 Bua Ban K Miocene Miocene 2775 7.412 1.112 Bua Ban L Miocene Miocene 2640 3.473 0.521 Total 107.062 32.033 Total All Prospects 522.976 110.171 16

Improving Offshore Operating Netbacks $80.00 Offshore Netbacks ($ / bbl) $70.00 $60.00 $50.00 $40.00 $30.00 $20.00 $1.50 $11.16 $2.38 $14.63 $3.85 $3.35 $16.96 $29.41 $4.64 $22.19 $39.42 $5.12 $14.21 $50.08 $5.45 $14.67 $52.68 $6.68 $15.99 $44.58 $10.00 $15.98 $19.12 $29.55 $23.77 $0.00 Q4 08 Q1 09 Q2 09 Q3 09 Q4 09 Q1 10 Q2 10 Q3 10 Cash Taxes Royalties Production expense Cash Operating Netback 18

Increasing EBITDAX (1) Note (1): EBITDAX in Q2 10 is lower than in Q1 10 due to the timing of liftings. The Company had approximately 222,000 bbls of crude oil inventory at the end of Q2 10. 19

G5/43 South Exploration: Bua Ban North A & B W Songkhla D Prospect E Time (sec) Top Lower Oligocene Lst Top Eocene Base Lower Oligocene Reservoir Bua Ban North B Reprocessed PrSDM Time Domain 1000 meters W Bua Ban North C Prospect Songkhla E Prospect E Bua Ban North A Time (sec) Top Lower Oligocene Lst Reprocessed PrSDM Time Domain Top Eocene Base Lower Oligocene Reservoir 1000 meters 1000 meters Base Lower Oligocene Sand Time Structure 20 ms contour interval 21

Songkhla Stratigraphy Benjarong 1 Songkhla 1 Reservoir Seal Reservoir Source Eocene Reservoir 22

Eocene Lower Oligocene 23

Upper Oligocene Miocene 24

Songkhla Basin Regional Cross Section SW Bua Ban Field Songkhla Field NE 25

Thailand Fiscal Terms G5/43 Thai III regime Royalty payable on a sliding scale determined by monthly production volume (5 15%) Current monthly production volume results in 7% effective royalty rate; monthly production of 20,000 bopd results in 10% effective royalty rate Petroleum Income Tax ( PIT ) payable on net income after deductions Allowable deductions: Royalty, Operating Expenses, Depreciation Allowance, Special Remuneratory Benefit, Loss Carryforward Tangibles depreciated straight-line over 5 years Pre-production intangibles depreciated straight-line over 10 years Post-production intangibles expensed as incurred Resulting net income taxed at 50% rate Coastal expects its overall effective tax rate to be approximately 5-10% in 2010* Coastal does not expect to incur any SRB liability in 2010 *Assumes $115MM capex for development of Bua Ban and Benjarong; $70/bbl realized; Average daily offshore production of 10K bopd in 2010 26

Special Remuneratory Benefit 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 applied to sliding scale is adjusted for inflation and exchange rate fluctuations (0 75%) Coastal s offshore concessions provide a 600,000 meter allowance to be added to actual drilling footage Tax assessed on Petroleum Profit Allowable deductions: Royalty, Capital Expenditures, Operating Expenses, Loss Carryforward All Capex is expensed as incurred, with a special 35% uplift on facilities capex Allows for full capital recovery plus uplift SRB is deductible for PIT purposes 27

Special Remuneratory Benefit Example Revenue: $250MM Adjusted Revenue: $200MM Deductible Expenses - $345MM Royalty (10%): $25MM Operating Expenses: $50MM Capital Expenditures: $120MM ($80MM intangible, $30MM facilities +35% facilities uplift) Loss Carryforward: $150MM Petroleum Profit: -$95MM ($250MM - $345MM), $95MM loss carried to next year Adjusted Revenue per Meter Drilled $200MM / (600,000 + 15 wells X 3,000 meters) = $310 per meter Resulting SRB rate is approximately 25% per sliding scale (USD/THB rate of 35 was used); applied to negative Petroleum Profit results in no SRB payable Adj. Revenue per Meter SRB Rate <137 0 137 411 1% for each $7 411 960 1% for each $27 >960 1% for each $110 28

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. 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Corporate Presentation February 2011