Corporate Presentation - Coastal Energy · 2012/11/19 · Corporate Presentation February 2013 19...

© Coastal Energy Company 2012 | All Rights Reserved

Corporate Presentation February 2013

2 Corporate Presentation February 2013

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.

Forward Looking Statements


Company Overview

Operational Overview Asset Overview

Financial Overview

($US in millions, except shares / share price)

Share Price (at 1/31/2013) C$21.96

Shares Outstanding 113.6

Shares Outstanding, Fully Diluted 116.2

Equity Value / Market Cap. $2,564.5

Debt (at 12/31/2012) $100.0

Cash (at 12/31/2012) $70.0

Enterprise Value $2,594.5

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


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

Material Exploration Success

During Past 2 Years

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

Added 40 Mmbbls 2P Bua Ban North & 20 Mmbbls 3P Bua Ban South in 2012

Substantial 2013 Drilling Program

Two rigs running for entire year; approximately 60% development/40%

exploration

First oil expected in Malaysia in 2H2013

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


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


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

(Mm

bo

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, 2012

Note: Offshore prospective resources reflect internal estimates

Offshore/Onshore (Mmboe): 3/31/12 2P – 127.7 / 21.4; 3P – 34.2 / 3.2; Contingent – 8.5 / 12.8; Prospective – 453 / 31.6


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


2013 EBITDAX Sensitivity

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


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 capita l i zed s tartup costs

(2) Reflects acquis i tion of additional interest in APICO and ARO


Rig 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

So

ng

kh

la

A12S

T

So

ng

kh

la

Eo

cen

e

So

ng

kh

la A

16

Bua Ban North

Development & Appraisal

8 Wells

Malaysia Appraisal Drilling

Bua Ban

South

Fracking

Bua Ban North

Development 8 Wells

Bua Ban South

Appraisal 5

Wells

G5/5

0 E

XP

L W

ell

Bua Ban Main

Workover ST 3

Wells

G5/4

3 E

XP

L

So

ng

kh

la M

G5/4

3 E

XP

L B

ua

Ban

No

rth T

erra

ce

G5/4

3 E

XP

L B

ua

Ban

Terra

ce

G5/4

3 E

XP

L

Ben

jaro

ng

So

uth

Songkhla H

Development 4

Wells

Exploration Appraisal Development Water Disposal

/Injection Workover

/

Completion

Note: HWU = hydraulic workover unit

MOPU required

MOPU required

So

ng

kh

la

Dev

elo

pm

en

t


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 3/31/2012

Thailand Exploration & Appraisal


Summary

Songkhla Basin has significant upside

Recent 3D seismic survey being processed

Survey covers entire Songkhla basin as well as the G5/50 exploration block

Initial data quality is excellent

Data have already produced new leads and structures and initial mapping is in progress

Established plays which offer further upside potential

Miocene Grabens

Lower Oligocene

Eocene

Onshore Exploration

Dong Mun gas discovery (10 mmboe net to Coastal)

Commerciality study has been approved

Expected to begin production in 2015


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


Songkhla Field

STOOIP 60.5 mmbbls

EUR 18.3 mmbbls

Remaining 11.7 mmbbls

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

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


Highly Successful Exploration in 2011

Confirmed successful Miocene trend in the

Songkhla basin

25 of 26 wells have been successful and

have added 67.0 mmbbl of certified 2P

reserves

Further drilling required to determine extent

of Bua Ban North field with exploration and

appraisal upside targeting an additional 63.0

mmbbl

Discovered Oil

Oil Well

Prospect or development location M100 penetration

point

Interval wet

Interval tight or absent

Bua Ban North


Bua Ban North Field

Undrilled Miocene

Prospects

27 Undrilled Closures

Potential Reserves (Unrisked) 58 MMBO


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


CC1H

GG1H

CC2

CC3

CC4

GG7

GG6

GG5

GG4

GG

2

GG3

Existing wells 3 (SC-11, SG-04, SG-05) New Wells:

Horizontal 2 (CC1H & GG1H) Deviated 9 (CC2 thru CC4, GG2

thru GG7) Wells CC2 & CC3 are appraisal wells to test

down-dip extent of reservoir i.e. OWC. If in oil column, will produce oil and later convert

to water injector when water breakthrough occurs.

If OWC identified, will use as water injector(s). OWC estimated at 3600 ft.TVDss (MDT).

CC wells drilled from C Platform GG wells drilled from G Platform

Bua Ban South

Development Plan


Lower Oligocene Sand depth closure from 8270 TVDSS LKO in C03

Bua Ban (Songkhla C & G)

Lower Oligocene Sand Reservoir

Top Lower Lacustrine Shale Depth Structure

Contour Interval: 100 feet TVDSS

7520 - Top Lower Oligocene Sand FT TVDSS DNP - Did Not Penetrate

Lower Oligocene Sand well penetration point – sand tight or absent

Well TD Location

Lower Oligocene Sand well penetration point - wet

Lower Oligocene Sand well penetration point – oil

DNP

DNP

DNP

DNP

Lower Oligocene Sand Closure Area 2166 Acres

STOOIP 74.6 MMBLS

3 Stage Frac job

in the Lower

Oligocene

Reservoir


Eocene Sand 8800 TVDSS depth structure closure

Top Eocene Sand Depth Structure

Contour Interval: 100 feet TVDSS

7520 - Top Eocene Sand FT TVDSS DNP - Did Not Penetrate

Eocene Sand well penetration point – sand tight or absent

Well TD Location

Eocene Sand well penetration point - wet

Eocene Sand well penetration point – oil DNP DNP

DNP

DNP

DNP

DNP

DNP DNP

DNP

DNP

DNP

DNP

Eocene Sand Closure Area 2870 Acres

STOOIP 157.4 MMBLS

6 Stage Frac job

in the Lower

Oligocene and

Eocene

Reservoir

Bua Ban (Songkhla C & G)

Eocene Sand Reservoir


Songkhla H Field

• Songkhla H Development

• 3 Oil Producers • 1 Water Injector • Exploration

• Well Downthrown Closure • Reserve Exposure 14mmbbls STOOIP

Main Field

Downthrown Closure


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


Songkhla Basin Miocene Trend

A A’


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


Songkhla N (Benjarong) Prospects

Lower Miocene M200 Time Structure

20 ms contour interval

Multiple stacked structural targets in:

Lower Miocene

Upper Oligocene

Lower Oligocene

Eocene

M200 A

M200 B

M200 C


Songkhla N (Benjarong) Prospects – Dip Line

M050

M075

M200

U Olig marker

M200 A

colored inversion

Tim

e (

sec)

1000 m

west east

Bua Ban North Field

Jerry’s Modifications

Songkhla M Lead

Time Structure : Upper Oligocene


Songkhla L Lead

Lower Miocene Closure

Lower Miocene Time Structure Contour Interval: 5 ms

oil prospect penetration interval wet Interval tight or absent

Lower Miocene A 615 acres

STOOIP = 28 MMBO

Drilling or proposed well

Lower Miocene B 130 acres

STOOIP = 6 MMBO

Lower Miocene C 40 acres

2 MMBO OOIP

A

Lower Miocene Closure May be near M500 Level Possibly Sand Prone Interval based on Progradational Foresets Just below Picked Horizon 15 to 20 msec (68 to 90 ft) of Column Height

B

C

M100

Reflectivity

L_Mio 1350 High

U Olig

L Olig LST

W E

Songkhla B02-ST1

L_Mio Upper Closure

Songkhla L Lead

E – W Line A


EAST TERRACE D PROSPECT

Miocene (600 acres)

and Eocene (2700 acres) Primary Objectives A

A’

B

B’ EAST TERRACE D A A’

EAST TERRACE D B’ B

Eocene

Eocene

M50

M50

Top Eocene Map

Terrace Prospects


SOUTH TERRACE C PROSPECT

Miocene M50, M100

U Oligocene L Oligocene

and Eocene Objectives

A

A

A’

A’

B

B

B’

B’ SOUTH TERRACE C

SOUTH TERRACE C

SOUTH TERRACE C

Top Eocene Map

Representing L Oligocene

And Eocene Objectives

Eocene

Eocene

L Olig

L Olig

M50

M100

U Olig

Terrace Prospects


SOUTH TERRACE C PROSPECT Miocene M50, M100, U Oligocene, L Oligocene and Eocene Objectives

M100 Map

Representing M050, M100,

U Oligocene Objectives

SOUTH TERRACE C

Bua Bahn North Field

SOUTH TERRACE C

SOUTH TERRACE C

A

A’

B

B’

A A’

B B’

Bua Bahn North Field

Eocene

L Olig

M100

M50

M50

M100

U Olig

U Olig

Eocene

L Olig

Bua Ban North Field

M100

M50

U Olig

Eocene

L Olig

Terrace Prospects


Songkhla Basin 3D – Old Versus New Coverage

Songkhla Pre - Existing 3d

Songkhla 2012 New 3d


Songkhla Pre - Existing 3D

Songkhla 2012 New 3D Arbitrary line A – A‘

Songkhla Basin 3D – Old Versus New Coverage

Additional Coverage Additional Coverage


Stratigraphic

Pinch-outs

Fractured

Basement

4-way Fault

Closures

Fractured Basement

Preliminary Results of New 3D Seismic


New Plays Along Basin Margins

Original 3D Limit

Songkhla A Bua Ban North

Miocene Ramp Play Terrace Play

Oligocene

Strat Play

Asri Sub-Basin, Indonesia

300 MMBO in basin

margin ramp/strat play

Malaysian Risk Service Contract


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


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%


Comparison Between PSC and SFRSC

** *

* Petroleum Income Tax Act

**Corporate Income Tax Act


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


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

Malaysia First Entry

Appendix


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


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 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 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%

Overview of Thailand Fiscal Terms


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 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)


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 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)


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

Special Remuneratory Benefit (“SRB”)


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