KrisEnergy Ltd - Appendices a to C

7/28/2019 KrisEnergy Ltd - Appendices a to C

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APPENDIX A

INDUSTRY OVERVIEW

All the information and data presented in this section, including the analysis of the global oil and gas

market has been provided by our energy industry consultant, Wood Mackenzie. Wood Mackenzie has

advised that the statistical and graphical information contained herein is drawn from its database and

other publicly available sources. In connection therewith, Wood Mackenzie has advised that:

(i) certain information in Wood Mackenzies database is derived from estimates or subjectivejudgments;

(ii) the information in the databases of other data collection agencies may differ from the

information in Wood Mackenzies database; and

(iii) while Wood Mackenzie has taken reasonable care in the compilation of the statistical and

graphical information and believes it to be accurate and correct, data compilation is subject to

limited audit and validation procedures.

Wood Mackenzies methodologies for collection of information and data are proprietary, and therefore

the information discussed in this section, may differ from that of other sources. The information and

data presented in this section has not been independently verified and neither we not the Joint Issue

Managers, Global Coordinators, Bookrunners and Underwriters make any representation as to the

accuracy or completeness of such data or any assumptions relied upon thereon. See Forward-

Looking Statements and Experts which are included elsewhere in this offering document.

I. Global Oil and Gas Market Overview

Global and regional reserves1

Global reserves by region

Wood Mackenzie estimates total global commercial oil and gas reserves at approximately 1,422 billionboe2 (as of Q4 2012A), with the Middle East region accounting for 40% of the total, followed by theRussia and Caspian region (20%), North America (14%), and Asia Pacific (8%).

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North America Asia Pacific Africa Latin America Europe

)eobmm(sevreseRgniniameR

Commercial Oil and Gas Reserves by Region

Gas Liquids % of Global Reserves

Source: Wood Mackenzie

1 Using Wood Mackenzies methodology, commercial reserves are broadly equivalent to proven and probable reserves.

In particular, Wood Mackenzie considers commercial reserves to be fields which are currently in production, under

development or regarded as probable developments. Fields under development are fields where the development plan

has been approved by the government authorities and the field participants have made the final investment decision for

the project to proceed. Probable developments are discoveries where reserve estimates have been sufficiently proved-

up and any development plan would be economically viable. Wood Mackenzie would expect probable developments to

be either on-stream or under development within a five-year timescale.

2 This includes both conventional and unconventional commercial reserves such as shale gas, tight oil, and oil sands.

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Global oil and gas demand

Crude oil demand by region

Global oil demand has risen since 2009A, with Wood Mackenzie projecting oil demand to continueincreasing from 27,726 mmboe in 2013F to 29,789 mmboe in 2018F, equating to a 1.4% averageannual growth rate. Despite demand cooling in Europe and North America, development in the rest ofthe world looks set to drive this overall growth in global oil demand. In particular, Wood Mackenzie

expects that the volumetric demand for oil in Asia Pacific will surpass the total increase in demand fromthe rest of the regions, with 1,226 mmboe of additional demand expected from 2013F to 2018F, or anaverage annual growth rate of 2.5%. China and Japan are currently the largest oil demand centers inAsia, but this is set to change as India is projected to overtake Japan as second largest oil market inAsia by 2015F. Demand in China and India is driven by the transport sector; and these two countriesprovide the majority of the growth through 2018F.

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Oildemand

(mmboe)

Crude Oil Demand by Region, 2005A-2018F

South America Russia and Caspian North America Middle East

Europe Asia Pacific Africa Yr-on-Yr Growth


Gas demand by region

In Wood Mackenzies view, gas looks set to take on a greater role globally, with gas demand expected tosteadily increase into the future, from 19,625 mmboe (111 tcf) in 2013F to 23,105 mmboe (131 tcf) in2018F, equating to an average annual growth rate of 3.3%. The main regions that contribute to this rise(volumetrically) are Asia Pacific, Middle East, and North America, with gas demand in Asia Pacificgrowing at an average of 6.9% per year between 2013F and 2018F.

China is the largest gas market in Asia and the fastest growth center in the region through the 2013F to2018F period. India, although slightly behind Japan in terms of current demand, is estimated to grow atan average 3.2% per year through the end of the decade.

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Gasconsumption(mmboe)

Gas Consumption by Region, 2005A-2018F




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Global oil and gas production

Crude oil production by region

Based on Wood Mackenzie estimates, global oil production is set to rise from 31,105 mmboe in 2013F to33,341 mmboe in 2018F, at an average annual growth rate of 1.4%. This is led by the projected growth inproduction in the Middle East and North America. In the Asia Pacific region, oil production between 2013Fand 2018F is set to remain steady. The impact of unconventional oil production will be felt acutely in NorthAmerica. Tight oil production in the United States is expected to increase from 1.5 million b/d in 2012A to4.1 million b/d in 2020F. Tight oil production is also expected to increase in Canada from around 230,000 b/d in 2012A to 450,000 b/d in 2020Fbut Wood Mackenzie expects a level of tight oil production of only260,000 b/d by 2020F outside of North America.

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2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Oilproduc

tion(mmboe)

Oil Production by Region, 2005A-2018F




Gas production by region

Wood Mackenzie expects a 3.5% average annual increase in global gas production, from 19,527 mmboe(111 tcf) in 2013F to 23,195 mmboe (132 bcf) in 2018F. While the regions of North America and Russia &Caspian are expected to continue maintaining their positions as the leading producers of gas globally,Asia Pacific is expected to grow its gas production at an annual average rate of 8.1% between 2013Fand 2018F, outperforming other regions.

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While the combination of hydraulic fracturing and horizontal drilling enabling commercial hydrocarbonflows from tight reservoirs has revolutionized North American energy, particularly shale gas to date, itwill take time for other regions to enjoy similar success. Wood Mackenzie acknowledges the shale gaspotential in Europe, Latin America, China, the Middle East, and elsewhere. However, issues such asthe absence of a supportive regulatory regime, early geological understanding, low local pricing, lack ofinfrastructure access and low service sector capability are throttling the pace of growth. ConsequentlyWood Mackenzie does not anticipate that shale gas growth in other regions will make a material impacton either supply or pricing, until after at least 2018F.

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2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Gasproduction(mmboe)

Gas Production by Region, 2005A-2018F




II. Crude Oil and Natural Gas Pricing

Crude oil pricing

Key global benchmarks: Oil Outlook

From 2013F to 2018F, the growth in non-Organization of Petroleum Exporting Countries (OPEC)production is projected to be keeping OPEC spare crude oil productive capacity between five andseven million barrels/day. Prices are lower in 2018F on a real basis than projected for 2012F. WideningOPEC spare capacity through much of the decade will cause oil prices to decline on an annualaverage basis with Brent falling to a low for 2016 of US$90.00 per barrel real, or US$99.82 per barrelon a nominal basis.

From the low in 2016F, Brent is expected to rise to an annual average of US$93 per barrel in realterms in 2018F. The late decade upward turn is based on the strength in oil demand growth and theneed to provide incentives for producers to invest, due to the increasing marginal breakeven price ofprobable developments.

In the period to 2018F, Wood Mackenzie estimates oil will have a protected market share because ofthe reliance on oil in the transport and the petrochemical sectors. Policies and technologies underdevelopment at present to reduce oil use are projected to have an impact and are reflected in thedemand forecast. But Wood Mackenzie expects a lag before widespread adoption. It is not until after2020 that more dramatic impact from alternative technologies and fuel efficiency gains is expected.

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Historical and forecast crude oil pricing

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US$/bbl

Brent

Real (2012$/bbl) Nominal ($/bbl)

Source: 2005A-2012A historical data--Thomson Datastream; 2013F-2018F forecast--Wood Mackenzie

Thomson Datastream has not provided its consent, for the purposes of Section 249 of the Securities and Futures Act, to the inclusion of the

information cited and attributed to it, in this offering document and is thereby not liable for such information under Sections 253 and 254 of the

Securities and Futures Act. While we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators, Bookrunners and

Underwriters have taken reasonable actions to ensure that the relevant information from the relevant source has been reproduced in its proper

form and context, neither we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators, Bookrunners and

Underwriters nor any other party has conducted an independent review or verified the accuracy or completeness of the relevant information.

Brent-West Texas Intermediate (WTI) Differential

From late 2010A, the historical differential between Brent and WTI has undergone a major shift, withWTI pricing at a steep discount to Brent a remarkable shift, given that Brent traditionally traded at aslight discount (approximately US$1.50 per barrel) to WTI, based on Brent being of slightly inferiorquality to WTI.

The shift in the relationship between these two marker crude oils is structural, with landlocked US domesticlight sweet crude growing in volume and experiencing challenges placing itself in a demand constraineddomestic refining system, while waterborne light sweet Brent-linked grades are able to trade more freely ininternational markets.

Wood Mackenzie sees the evolution of the Brent-WTI differential as largely driven by three criticalfactors:

Refinery demand for light crude oil

Logistics

Competition between growing volumes of domestic light crude and waterborne crude imports.

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Wood Mackenzie expects the differential will start to narrow only after 2020, driven by a flattening ofthe domestic crude oil production profile, and through growing volumes of domestic light sweetproduction entering markets on the east and west coasts, as mentioned above, Wood Mackenzie doesnot foresee the differential returning to its historical relationship.

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US$/bbl

WTI

Real (2012$/bbl) Nominal ($/bbl)Source: 2005A-2012A historical data--Thomson Datastream; 2013F-2018F forecast--Wood Mackenzie

Thomson Datastream has not provided its consent, for the purposes of Section 249 of the Securities and Futures Act, to the inclusion of theinformation cited and attributed to it, in this offering document and is thereby not liable for such information under Sections 253 and 254 of theSecurities and Futures Act. While we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators, Bookrunners andUnderwriters have taken reasonable actions to ensure that the relevant information from the relevant source has been reproduced in its properform and context, neither we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators, Bookrunners andUnderwriters nor any other party has conducted an independent review or verified the accuracy or completeness of the relevant information.

Brent-Dubai differential

The availability of light sweet crude has increased during 2012A. Growing domestic supply in the UShas reduced demand for US crude imports from West Africa. The resumption of crude exports from

Libya has also resulted in increased supply of light sweet crude. This has contributed to narrower pricepremiums for light sweet crudes versus heavier, more sour, crudes. This has been reflected in thediscount for Dubai crude versus Brent which narrowed significantly in 2012A after having been verywide in 2011A. The value of heavier more sour crudes has been supported by sanctions against Iranand Syria which have forced many refiners to look for alternative sources for replacement grades ofsimilar quality.

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Wood Mackenzie forecasts that the global crude slate will get lighter through 2017. As a result WoodMackenzie expects the price premium for light sweet crudes such as Brent to narrow. Over the sameperiod, investments are being made to increase coking capacity at refineries. This will increasedemand for heavier crudes similar to Dubai and their value is expected to increase relative to lightersweet crudes. Wood Mackenzie estimates that the Brent-Dubai differential will narrow through 2017A.After this time, the proportion of heavy crude in the global crude slate starts to grow and, together withincreasing outright prices, this leads Wood Mackenzie to forecast that the Brent-Dubai differential willwiden again.

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2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

US$/bbl

Dubai

Real (2012$/bbl) Nominal ($/bbl)

Source: 2005A-2012A historical data--Thomson Datastream; 2013F-2018F forecast--Wood Mackenzie

Thomson Datastream has not provided its consent, for the purposes of Section 249 of the Securities and Futures Act, to the inclusion of the

information cited and attributed to it, in this offering document and is thereby not liable for such information under Sections 253 and 254 of the

Securities and Futures Act. While we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators, Bookrunners and

Underwriters have taken reasonable actions to ensure that the relevant information from the relevant source has been reproduced in its proper

form and context, neither we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators, Bookrunners and

Underwriters nor any other party has conducted an independent review or verified the accuracy or completeness of the relevant information.

The key light sweet benchmark crudes in the Asia-Pacific region are Minas and Tapis. Both of thesecrudes traded at 4% to 5% premium to Brent in 2012A.

Natural gas pricing

Overview of regional pricing dynamics

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US$/mmBtu,Real(2012A)

Global Gas Spot Prices (real 2012A terms)

HH NBP Japan Asia Oil Indexed Contract

Source: 2005A-2012A Oil Indices--Thomson Datastream, 2005A-2012A NBP--Argus, Others and all forecast 2013F-2018F--Wood Mackenzie

None of Thomson Datastream and Argus has provided its consent, for the purposes of Section 249 of the Securities and Futures Act, to theinclusion of the information cited and attributed to it, in this offering document and is thereby not liable for such information under Sections 253 and

254 of the Securities and Futures Act. While we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators,

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Bookrunners and Underwriters have taken reasonable actions to ensure that the relevant information from the relevant source has been

reproduced in its proper form and context, neither we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators,

Bookrunners and Underwriters nor any other party has conducted an independent review or verified the accuracy or completeness of the relevant

information.

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2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

US$/mmBtu,Nominal

Global Gas Spot Prices (nominal)

HH NBP Japan Asia Oil Indexed Contract

Source: 2005A-2012A Oil Indices--Thomson Datastream, 2005A-2012A NBP--Argus, Others and all forecast 2013F-2018F--Wood Mackenzie

None of Thomson Datastream and Argus has provided its consent, for the purposes of Section 249 of the Securities and Futures Act, to the

inclusion of the information cited and attributed to it, in this offering document and is thereby not liable for such information under Sections 253 and

254 of the Securities and Futures Act. While we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators,

Bookrunners and Underwriters have taken reasonable actions to ensure that the relevant information from the relevant source has been

reproduced in its proper form and context, neither we, the Over-allotment Option Grantor and the Joint Issue Managers, Global Coordinators,

Bookrunners and Underwriters nor any other party has conducted an independent review or verified the accuracy or completeness of the relevant

information.

The prevailing premium that LNG suppliers enjoy in Asian markets is a consequence of the lack ofproximate supply to meet demand, requiring distant LNG from suppliers in Norway and Trinidad &Tobago to meet demand. Wood Mackenzies view is that this tightness will persist until at least 2017Fand, subject to the pace of growth of new LNG presently under construction in Australia, possibly

longer. Most LNG delivered into Asia is supplied under long term contracts is indexed to oil rather thanpriced at spot. And while some term LNG supply has been agreed on a Henry Hub (HH) basis, oilindexation is likely to remain key to price formation of LNG in Asia for some time, and certainly through2018F. The floor price to incentivise new LNG supply into the market is estimated in the US$11-12/mmbtu range. In many Asian markets the price of indigenous gas is subject to local considerations;see individual country overviews for Indonesia, Thailand, Vietnam, Cambodia, and Bangladesh. Inrecent years there has been an increasing convergence of local gas prices and regional LNG priceswith imported LNG increasingly setting the price ceiling for contract negotiations.

While HH prices in the US have averaged around US$3.75/mmbtu for the last three years WoodMackenzie expects prices to rise through the medium term to encourage new supply into the marketfor growing demand to be met. Growing demand will come from the industrial renaissance in the US,

from fuel displacement in power, residential and transport and from LNG exports. Wood Mackenzieestimates LNG export from the US will start in 2016, from the Sabine Pass liquefaction facility on theUS Gulf Coast.

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III. South East Asia Regional Oil and Gas Market Overview

Reserves and resources by country3

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RemaningReserves

(mmboe) Commercial and Technical Oil and Gas Reserves by Country, 2012A

Commercial Liquids Technical Liquids Commercial Gas Technical Gas

Source: Wood MackenzieSource: Wood Mackenzie

As of Wood Mackenzies latest estimates from Q4 2012A, the South East Asian region holds about60,922 mmboe of commercial and technical oil and gas reserves3. The bulk of the reserves are locatedin Indonesia and Malaysia, which contribute 29,547 mmboe (48%) and 15,414 mmboe (25%) to theregional total, respectively. In South East Asia, 80% of commercial and technical reserves are gas,demonstrating the strong regional bias toward gas.

Demand and production (historical and forecast)

Crude oil demand

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Oildemand(mmboe)

South East Asia Oil Demand, 2005A-2018F

Vietnam Cambodia Myanmar Indonesia

Brunei Darussalam Thailand Philippines Malaysia

Singapore Yr-on-yr change%


3 Technical reserves are defined as reserves that have been discovered but are currently not considered commercial.

This may be due for example to low levels of recoverable reserves, perceived technical difficulties with a

development, low product quality or the lack of available markets (e.g. stranded gas deposits).

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In Wood Mackenzies view, oil demand in South East Asia is on an overall upward trend, with demandexpected to reach 1,837 mmboe in 2018F, a 2.8% average annual increase from 2013F. Indonesia isthe largest market for oil in South East Asia, driven by transport requirements, although Vietnam will bethe fastest growing oil consumer through 2018F, with an average annual 8.8% growth rate, followed byCambodia and Myanmar at 5.2% and 3.4%, respectively.

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Vietnam Cambodia Myanmar Indonesia BruneiDarussalam

Thailand Philippines Malaysia Singapore

Average Annual Increase in Oil Demand by Country, 2013F-2018F


Gas demand

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Gasdemand(mmboe)

South East Asia Gas Demand, 2005A-2018F

Vietnam Myanmar Indonesia Malaysia

Singapore Thailand Philippines Brunei Darussalam

Cambodia Yr-on-yr change%


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Gas looks set to take on greater importance for South East Asia in the coming years, as WoodMackenzie expects the region to see an average 4.1% annual increase in regional gas demand from884 mmboe (5,021 bcf) in 2013F to 1,081 mmboe (6,140 bcf) in 2018F. Indonesia, Malaysia andThailand are the top three drivers of this gas demand volumetrically; Vietnam is the fastest growing gasdemand center through 2018F with a 5.5% average annual growth rate.

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Vietnam Myanmar Indonesia Malaysia Singapore Thailand Phil ippines Brunei

Darussalam

Cambodia

Average Annual Increase in Gas Demand by Country, 2013F-2018F


Crude oil production

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Oilproduction

(mmboe)

South East Asia Oil Production, 2005A-2018F

Brunei Darussalam Cambodia Indonesia

Malaysia Myanmar Philippines

Thailand Vietnam Yr-on-yr change%


Wood Mackenzie projects oil production in South East Asia to decline slightly between 2013F and2018F, from 879 mmboe to 838 mmboe. The largest decrease in production comes from Vietnam,while Malaysia is expected to replace Indonesia as South East Asias largest oil producer in 2018F.Other countries in the region are also expected to see a drop in oil production, including Indonesia,Thailand and Vietnam.

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Gas production

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Gasproduction(mmboe)

South East Asia Gas Production, 2005A-2018F

Brunei Darussalam Cambodia Indonesia

Malaysia Myanmar Philippines

Thailand Vietnam Yr-on-yr change%


Gas production in South East Asia is on the rise. Myanmar and Vietnam are both projected tosignificantly increase their gas production rates from 2013F to 2018F, with average annual growthrates of 9.7% and 5.5%, respectively. Regionally, gas production will increase at an average annualrate of 2.5% through 2018F, with the largest producer, Indonesia, growing at an average annual rate of1.3%.

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Oil(mmboe)

South East Asia Oil Supply-Demand, 2005A-2018F

Oil Production (mmboe) Oil Demand (mmboe)


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Gas(mmboe)

South East Asia Gas Supply-Demand, 2005A-2018F

Gas Production (mmboe) Gas Demand (mmboe)


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Oil and gas prospectivity of region

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Brunei Indonesia Malaysia Myanmar Thailand Vietnam

TotalYet-to-Find

(mmboe)

Yet-to-Find Commercial and Technical Reserve Volumes

Liquids Gas


Based on Wood Mackenzies projections, the total yet-to-find (YTF) volume in South East Asia is14,614 mmboe, of which 5,512 mmboe is liquids and 9,102 mmboe (52 tcf) is gas.4 Indonesia,Malaysia and Myanmar are highly prospective for gas reserves, while Vietnams YTF liquids volume isthe highest in the region at 1,868 mmboe.

4 Wood Mackenzie bases its YTF resource on the potential from the discovery of conventional oil and gas new fields.

Unconventional resource potential is excluded from the scope of reporting, as is the potential from upgrades and

extensions on existing discoveries. Wood Mackenzie uses a projected creaming curve to derive the assumption of YTF

potential in a basin. The curve is generated using best fit of a hyperbolic trend to historic data on cumulative reserves by

cumulative exploration wells. The curves trajectory is also an assumption of reserves that will be discovered per

exploration well. The overall basin YTF assumption is constrained by Wood Mackenzies forecast of exploration well

numbers to 2030F. This YTF assumption is intended to be a broadly realistic input to Wood Mackenzies future

economics evaluation, and is not a substitute for a geologically-constrained resource assessment. Basin coverage

excludes Cambodia.

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Exploration successes and discoveries by country

In recent years, the region has seen a mixed trend in discovered volumes, with an average 1,417mmboe discovered per year since 2005A.

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Discoveredvolume(mmbo

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Discovered Volume by Country, 2005A-2012A(Commercial & Technical Resources)

Brunei Cambodia Indonesia Malaysia Malaysia-Thai JDA Myanmar Philippines Thailand Vietnam


On a country-by-country perspective, Malaysia has had the largest volumes discovered since 2005A,with 4,808 mmboe of conventional resource. In Indonesia, 2,187 mmboe of conventional resource hasbeen discovered since 2005A, with Vietnam following at 1,981 mmboe in the same period. TheMalaysia-Thailand JDA, however, has enjoyed the greatest exploration success rate of 61% during thisperiod, followed by Malaysia at 54% and Thailand at 51%.

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Discovered Volume by Country and Exploration Success Rates

2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A Success rate


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Major players active in the region

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Petronas

Shell

Chevron

PERTAMINA

INPEXCorporation

PTTEP

BP

PetroVietnam

JOGMEC

ExxonMobil

ConocoPhillips

Total

MurphyOil

BruneiGovernment

HessCorporation

Talisman

CNOOC

Ltd

EnergiMegaPersada

Eni

JXNipponOil&Energy

Corp

Remainingreserves(mmboe)

Oil and Gas Reserves in SE Asia by Company, 2012A(Commercial and Technical Reserves)


Based on total remaining reserves as estimated by Wood Mackenzie at Q4 2012, the top three playersin South East Asia are Petronas, Shell and Chevron. Petronas has double the remaining reserves ofShell.

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PETRONAS

Chevron

Shell

Total

ExxonMobil

INPEX

Corporation

PERTAMINA

PTTEP

Brunei

Government

PetroVietnam

ConocoPhillips

Talisman

HessCorporation

BP

CNOOC

Ltd

JXNipponOil&

EnergyCorp

MurphyOil

Zarubezhneft

MOGE

Mitsui&CoA

verageWIP

roduction2007A-2012A

('000boe/d)

Average WI Production in South East Asia 2007A-2012A


By production, Petronas, Chevron and Shell are the largest in the region, based on the average totalworking interest production from 2007A-2012A. Petronas averaged approximately 910,000 boe/d, as

compared to Chevrons 774,000 boe/d and Shells 560,000 boe/d over the period.

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E&P expenditure

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20,000

25,000

30,000

35,000

2003A 2004A 2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A

E&PSpend(US$

M)

E&P Spend by Country, 2003A-2012A (nominal)

Brunei Cambodia Indonesia Malaysia Malay/Thai JDA Myanmar Philippines Thailand Vietnam


According to Wood Mackenzie estimates, E&P expenditure has more than doubled in the past 10years (on a nominal basis) from US$15,418 million in 2003A to US$32,301 million in 2012A. The toptwo countries by E&P spend in 2012A are Indonesia (US$10,705 million) and Malaysia (US$10,184million).

In estimating the overall E&P expenditure, Wood Mackenzie includes the exploration spend, capitalexpenditure and operating expenditure associated with each country. Please note that the E&P spendestimate for Cambodia does not include capital expenditure and operating expenditure, and that theE&P spend for the Malaysia/Thailand JDA does not include exploration spend.

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IV. Overview of Key Countries Oil and Gas Industry

Indonesia

Overview

MALAYSIA

INDONESIA

KAKAP

TEMBANG

28" gas pipelineto Singapore

Belitung

Bangka

Sumatra

SINGAPORE

INDONESIA

Indian Ocean

Natuna Sea

Siberut

Sipura

Pagai Utara

Pagai Selatan

Java Sea

NSO

ARUN

MALAYSIA

THAILAND

Arun LNG Plant

Medan

DURISteamfloodCENTRALSUMATRA

FIELDSRiau

Andalan

IndahKiat

SOUTH

SUMATRAFIELDS

Palembang

Prabumulih

MUSI

PUSRI

Grissik GPP

28"Duri

steamflo

od

28"

Batam

Sakernan GPP

32"gasto

TegalGede

Tanahbala

Nias

Simeulu

Enganno

Java

32"gasto

Cilegon

PAGARDEWA

Labuhan Maringgai

Plaju

Pekanbaru

SouthSum

atra-W

estJava

RANTAU KAMBUNA

GEBANG JOA

MALACCA

STRAIT PSC

Lampung Regas (u/c)

NusantaraRegas Satu

108E

108E

105E

105E

102E

102E

99E

99E

96E

96E

6N

6N

3N

3N

0

0

3S

3S

6S

6S

0200400 100km


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Indonesias recent hydrocarbon industry has highlighted two dominant trendsdeclining oil production,and rising gas output. Since 2005A the Indonesian government has increased the number of newexploration blocks on offer across the country in a bid to spur a wave of new discoveries. So far, nomajor success stories have emerged, as the average size of hydrocarbon discoveries in Indonesia hasremained low since early 2000A. However, with an increasing number of frontier exploration wells inthe West Papua area set to be drilled in the period 2013F-2014F, major discoveries could still be onthe agenda.

Bali

Grati

KangeanTuban

Mojokerto

Jogjakarta

Surakarta

Semarang

TambakLorok Gresik

Kepodang(Muriah PSC)

BAWEAN PSC Fields

WEST MADURA/POLENG PAGERUNGAN(Kangean PSC)

Sirasun,Batur

Madura

East Java

Indian Ocean

Java Sea

Bawean Island

OYONGSurabaya

UJUNG PANGKAH14

"

28" East Java gasPagerungan-Gresik

CEPU AREA

East JavaDistribution System

KETAPANG PSC Fields

BD

18"

MALEO

Leles Pulp Mill

toCirebon

BRANTAS PSC Fields

planned 28" gas

planned

Porong TERANGCepu

RembangPlanned West Java LNG

116E

116E

114E

114E

112E

112E

110E

110E

6S

6S

8S

8S

10S

10S

0100200 50km


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Most liquids and gas production is sourced from the well-explored basins of Sumatra, Java and EastKalimantan. Given the maturity of the core producing areas within these regions, it is inevitableoperators will have to develop new reserves in more challenging and remote locations throughoutIndonesia. Moreover, many within the industry and the Indonesian government also believe that it ismore likely future hydrocarbon discoveries in frontier regions will be predominantly gas-based.

10"

BUNYUBunyu Methanol Plant

TARAKAN

TUNU

Kaltim: Fertiliser PlantKPA Ammonia PlantKPI Ammonia Plant

SEMBERAH

PECIKO

HANDIL

BADAK

SANGA SANGAGula

Gandang

Gendalo

Gada

Bangka/Aton

WEST SENOBontang LNG Plant

NUBI/SISI

SEPPINGAN

INDONESIAKalimantan

MALAYSIA

Sarawak

Mak

assa

rStrait

Tanjung Batu,Samarinda

Balikpapan Refinery

Lawe-Lawe

Equator

Senipah Oil Terminal

Santan Oil Terminal

119E

119E

118E

118E

117E

117E

116E

116E

115E

115E

3N

3N

2N

2N

1N

1N

0

0

1S

1S

0 50 10025km


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Oil and gas reserves/resources

Indonesia has 29,547 mmboe of remaining commercial and technical oil and gas reserves. Gasaccounts for a significant portion of Indonesias petroleum reserves (contributing 85% on a commercialand technical basis, and 76% on a commercial basis only), and continues to be a primary energysource for Indonesia. The largest remaining gas reserves in Indonesia are in Sumatra, West Papua,Natuna Sea and East Kalimantan.

2,531

1,988

7,83917,189

Indonesia Commercial and Technical Oil and Gas Reserves (mmboe), 2012A



Prospectivity and recent discoveries

0

500

1000

1500

2000

2500

3000

Liquids Gas

TotalYet-to-Find(mmbo

e)

Indonesia Yet-to-Find Commercial and Technical Reserve Volumes


Indonesia is viewed by many as having considerable remaining oil and gas potential, with WoodMackenzie estimating about 3,665 mmboe of total YTF reserves. This is anticipated to be in theeastern basins, where large areas, both onshore and offshore, remain relatively unexplored. The majorproblem faced by potential explorers in these basins is the sheer size and remoteness of the areas tobe explored. This, in combination with the lack of infrastructure and the harshness of the terrain (manyof the prospective onshore areas are in remote jungle regions), makes the logistics of petroleumexploration very difficult.

In the last 10 years, the country has seen between 14 to 22 fields discovered per year. The volumesdiscovered each year has varied considerably, with 2011A seeing a high of 646 mmboe added (mainly

from the Asap field in the Bintuni basin and Jangkrik North East field in the Kutei basin). Overall, therehas been 3,160 mmboe of discovered volumes from 2003A-2012A.

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Indonesias coal bas methane (CBM) resource potential is estimated in the range of 36 tcf, located inthe Barito (9.7 tcf), Kutei (11.1 tcf), and South Sumatra (15.2 tcf) basins. However, there are nocommercial CBM operations to date in Indonesia, and these estimates remain highly uncertain untilpilot drilling is completed.

0

5

10

15

20

25

30

0

100

200

300

400

500

600

700

2003A 2004A 2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A

Numberofdiscoveries

Totaldiscoveredvolume(mmboe)

Indonesia Recent Discoveries, 2003A-2012A


Historical and forecast oil and gas demand and production

Indonesian oil production has been in decline since the turn of the decade, as smaller new oildevelopments have struggled to replace output from the mature, legacy fields such as the giant Minasand Duri fields in central Sumatra that lie at the heart of the nations liquids output. This decline trend isset to continue, partially offset from 2014F by the ramp-up of production from the 160,000 b/d BanyuUrip field. However, there are few other new oil developments of scale currently planned in the country.

Indonesia has been a net importer of oil since 2004A.

0

100

200

300

400

500

600

700

0

100

200

300

400

500

600

700

2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Oil(mmboe)

Indonesia Oil Supply-Demand, 2005A-2018F



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This follows from the increase in gas prices for the fertiliser sector as well. With a number of fertilisergas contracts due to expire in 2012, Wood Mackenzie has seen the range of agreed prices betweenUS$5.0-7.0/mmbtu with an annual escalation clause.

This new price benchmark appears to be the standard across Indonesia in all sectors. This is a distinctimprovement compared to agreements in the past. It signals a shift in the governments position toallow price increases to reflect the scarcity of the resource and the higher priced alternative of importedLNG. This is expected to encourage more upstream exploration and production, which will lead todevelopment of marginal onshore fields and unconventional gas resources.

The 2001 Oil & Gas Law requires upstream operators to provide at least 25% of gas production to fulfilldomestic needs, with some recent projects required to allocate up to 40% of output to the domesticmarket. As DMO is implemented on a case-by-case basis, this creates uncertainties for developers, asthey are uncertain what proportion will be allocated domestically and some projects may have tosupply up to 100% sales to the local market. In terms of oil production, contracts stipulate that thecontractor should supply a DMO quantity based on 25% of the total quantity of crude oil produced,multiplied by its pre-tax profit oil entitlement percentage.

Major players active in country

0

500

1000

1500

2000

2500

3000

PERTAMINA

INPEX

Corporation

Chevron

BP

JOGMEC

Shell

CNOOC

Ltd

ConocoPhillips

EnergiM

egaPersada

Eni

Talisman

Total

M

edcoEnergi

Mitsubish

iCorporation

ExxonMobil

PetronasCarigali

JXNippon

Oil&Energy

C

orp

Premier

GentingOil&Gas

GDFSuez

Remainingreserves(mmboe) Oil and Gas Reserves in Indonesia by Company, 2012A

(Commercial and Technical Reserves)

Gas OilSource: Wood Mackenzie

Indonesia has one of the most diverse upstream industries of any country in the world, with over 200active PSC participants of varying ability and size. In terms of remaining reserves and production, thetop 20 companies include US and European majors (Chevron, BP, ConocoPhillips, ExxonMobil, Total,Shell), Indonesian independents (Medco Energi and Energi Mega Persada), international independents(Talisman) and oil companies from Japan (INPEX), China (CNOOC), and Indonesias own state player(PERTAMINA). KrisEnergy has an operated position in 6 blocks in Indonesia, and one non-operatedinterest in Salamander Energys Glagah-Kambuna Technical Assistance Contract (TAC), a smallproducing interest that is likely to cease production and/or be relinquished in 2013.

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Chevron is the leading producer in Indonesia with 457,000 boe/d of average working interestproduction from 2007-2012. This is driven by its operatorship of the CPI Area, which includes the largeMinas and Duri oil developments. Other major players include INPEX and Total, which have significantproduction through the Offshore Mahakam PSC that supplies the majority of the gas feedstock into theBontang LNG facility.

-

50

100

150

200

250

300

350

400450

500

Chevron

PER

TAMINA

INPEX

Co

rporation

Total

Conoc

oPhillips

CN

OOC

Ltd

BP

Talisman

ExxonMobil

Medc

oEnergi

Eni

PETRONAS

HessCo

rporation

Pe

troChina

Ene

rgiMega

Persada

Santos

CPC

KuwaitP

etroleum

Corpo

ration

CNPC

KodecoEnergy

AverageWIProduction2007A-201

2A

('000boe/d)

Indonesia Average WI Production 2007A-2012A


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Thailand

Overview

THAILAND

MALAYSIA-THAILAND JDA

CAMBODIA

VIETNAM

MYANMAR

CAM-THAI OCA

LAOS

Gulf of

Thailand

BONGKOT

ERAWAN

YETAGUNEsso

BANGKOK

Ho Chi Minh

PHNOM PENH

YADANA

SIRIKIT

Mekong

Fang

BUNG YA

BENCHAMAS

NORTH JARMJUREETANTAWAN

MALIWAN

SUPHAN

BURIFIELDS

MILITARY

OPERATEDAREA

Bangchak

Thai Oil

RayongStar

RRC Shell TPI

BangkokSriracha

Samut Prakan

Lumlukka

Area to beDelimited

B8/32

B5/27

ARTHIT

106E

106E

104E

104E

102E

102E

100E

100E

98E

98E

96E

96E

20N

20N

18N

18N

16N

16N

14N

14N

12N

12N

1

0N

1

0N

8N

8N

0 100 20050km


Thailands upstream oil and gas production is predominately sourced from two offshore areas in theGulf of Thailand: the Pattani basin and the Malay basin. The complex structural nature of the offshoregeology means no one field or area dominates reserves or outputinstead the majority of productionis provided by thousands of separate (but relatively heterogeneous) reservoirs spread across the twobasins. Remaining hydrocarbon reserves are dominated by gas, which constitutes three-quarters ofremaining reserves.

Thailands indigenous gas production is dominated by a number of key offshore projects includingArthit, Bongkot and the 3rd Gas Contract area. Together these fields accounted for more than half ofThailands domestic gas production in 2012A. Other large gas-producing developments include B12/27and the 1st and 2nd Gas Contract Areas, all operated by Chevron. The largest producing onshore gasfield is the Hess-operated Sinphuhorm, which in 2013F is expected to have a sales output of 95mmcfd.

To meet growing demand, Thailands domestic gas supply has been augmented by imported gas from

Myanmar and the Malaysia-Thailand JDA. In addition, the first LNG imports were received in 2011A. TheLNG regasification terminal has an initial capacity of five million tonnes per annum, and is located at Map TaPhut, south of Bangkok.

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The largest liquid producing areas are the Chevron-operated B8/32 and Contract 3 areas. Elsewhereliquid production is supplemented by the onshore Sirikit Area (S1), and Coastal Energys Songkhladevelopment in G5/43. Mubadalas G1/48 (Manora) project will add further production from 2014F.

Longer-term, liquid production is forecast to decline in line with falling output from the main gasproducing fields in the Pattani and Malay basins.

Despite a small number of wildcats being drilled, Thailands recent exploration activities have beenmainly focused on delineation and step-out exploration and appraisal drilling. A number of smalldiscoveries have been made both onshore and in the Gulf of Thailand in recent years.

Following the popularity of the 20th licensing round launched in 2007 (30 blocks were awarded), theThailand Energy Ministry has announced that it will launch a 21st Licensing Round in 2013, with a totalof 22 blocks on offer.


712

161

2,040

458

Thailand Commercial and Technical Oil and Gas Reserves (mmboe), 2012A



Thailand has a total of 3,371 mmboe of remaining oil and gas reserves, taking into consideration bothcommercial and technical reserves. Gas makes up about 74% of the total reserves, on both acommercial, and a commercial and technical basis, underlying its importance to Thailands energyportfolio. To date, the bulk of Thailands petroleum reserves have been discovered offshore in the Gulfof Thailand although the Gulf is now a relatively mature area, it still contains the vast majority of thecountrys remaining reserves.

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Liquids Gas0

50

100

150

200

250

300

350

400

450

TotalYet-to-Find(m

mboe)

Thailand Yet-to-Find Commercial and Technical Reserve Volumes


Wood Mackenzie estimates that Thailand has 540 mmboe of YTF potential, the large majority of itbeing gas (77%). In the last 10 years, Thailand has seen discovered volumes of 493 mmboe. The peakof this was in 2009A, with 118 mmboe discovered.

0

5

10

15

20

25

0

20

40

60

80

100

120

140

2003A 2004A 2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A

Numbero

fdiscoveries


Thailand Recent Discoveries, 2003A-2012A



The Defense Energy Department began oil production in Thailand in the late-1950s. However,production remained at relatively low levels until Shell brought the Sirikit field onstream in 1983A.Thailands other main source of indigenous liquid production has been condensate from Chevrons gasfields in the Gulf of Thailand, the first being produced from Erawan in 1981. Liquids productionincreased steadily during the 2000s, as a result of the Big Oil project, which produces from fieldsincluding Benchamas, Plamuk and Yala in the Chevron-operated areas. Higher production from theBongkot area has also added to Thailands liquid output. In the near to medium-term, the largest liquidsproducer in Thailand will continue to be Chevron, from the Contract areas and the B8/32 concession(KrisEnergy holds a 4.63% non-operated interest in the B8/32 concession).

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Thailands largest onshore oil producing field has been the Sirikit Area, operated by PTTEP. Currentdevelopment work is expected to maintain oil production from the Sirikit Area above 25,000 b/d until2016F.

0

50

100

150

200

250

300

350

400

450

0

50

100

150

200

250

300

350

400

450

2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Oil(mmboe)

Thailand Oil Supply-Demand, 2005A-2018F



To date, the vast majority of Thailands gas output has come from the Gulf of Thailand, whereproduction started in 1981A from Unocals Erawan field. Chevron acquired Unocal in August 2005A,and became Thailands premier gas producer.

As a result of the Asian economic crisis, growth in gas demand was stifled in the late-1990s andThailand was confronted by an oversupply of contracted gas. An increase in contracted supply fromMyanmar in the early-2000s meant limited opportunities for increased domestic supply.

However, in the last decade Thailands domestic gas demand has grown strongly. In 2003A, a numberof sales agreements for the supply of domestic gas were signed. Incremental supply was secured from

existing suppliers such as Unocals B12/27 concession, and in January 2004A, a Gas SalesAgreement (GSA) was signed for the supply of gas from PTTEPs Arthit fields. This was the first newsource of gas to be contracted to the Thai market since early-2000. In addition, Unocal secured aHeads of Agreement (HOA) for the supply of additional gas from Contract Areas 1, 2 and 3, in 2006A.The HOA was converted into a full GSA in 2007A and a 10-year extension to the concessionagreements was secured. Supply from Arthit started in April 2008A, via the third Gulf of Thailand gastrunk line.

Thailand also receives gas from the Malaysia-Thailand JDA, from both the Carigali-PTTEP OperatingCompany-operated B-17 block and the Carigali-Triton Operating Company -operated A-18 block. A-18and B-17 are expected to supply 400 mmcfd and 270 mmcfd, respectively, at peak. The salesagreements for A-18 and B-17 have an option to increase supply if demand and reserves allow. First

production from the Malaysia-Thailand JDA was achieved in 2008A.

In recent years, two major projects have been brought onstream to increase the supply of gas toThailands domestic market. Chevrons Platong II project began commercial production in October2011A, whilst PTTEPs Bongkot South development began production in April 2012A. These projectswill increase supply capacity by 420 mmcfd and 320 mmcfd, respectively.

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In addition to new domestic developments, or exploration success, piped imports are available fromMyanmar and the MTJDA. Since the inception of the LNG regas terminal in 2011A, LNG importsaugment the domestic and piped gas supply.

0

50

100

150

200

250

300

0

50

100

150

200

250

300

2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Gas(mmbo

e)

Thailand Gas Supply-Demand, 2005A-2018F



Indicative crude oil and natural gas pricing

Liquids Pricing

Oil is sold at a price referenced to local crudes (e.g. Tapis) or baskets of crude (e.g. Oman blend,Ardjuna and Minas). B8/32 crude is sold at a benchmark to Dubai.

Condensate pricing is based on an average of a basket of five crudes and condensates (Berri, Murbau,Seria Light, North West Shelf, Tapis) posted in Singapore, usually at a discount of between 5% and9%.

Gas Pricing

Gas sold in Thailand is generally sold at a price dictated by a formula contained within the gas salesagreement. Details of these formulae remain confidential and vary between individual GSAs andsuppliers. The formulae reference a variety of indices, the most common of which are as follows:

A basket of Medium Sulphur Fuel Oils from Singapore

The Wholesale Price Index in Thailand

The US Index of Export Prices

The Producer Price of Oil Field Machinery and Tools Index

The Baht/US$ Exchange Rate

The Inflation Rate

Fluctuations in Foreign Currency Exchange Rates

Individual formula may reference only one or a number of these indices. To account for variance of theindices referenced, gas prices are generally adjusted every six months or every year, depending on theterms of the contract. In some cases, the GSA allows for more frequent adjustment in the event thatcertain indices and factors on which the price is based fluctuate outside a given range.

Domestic demand, pricing tension and domestic market obligation

Until the end of 2020F, domestic gas supplies will still form a large proportion of the total gas suppliedinto Thailand. Beyond 2020F, the average price of gas rises rapidly in parallel with the projected LNGimports to meet demand.

The cap on gas prices is likely to be set by the price of purchasing LNG in the international marketwhile the theoretical floor would be set by imported coal. However the restriction on building new coal-fired power plants limits the effectiveness of the floor as the pricing boundary.

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While the Thai contracts do not require a DMO supply, under the terms of the Petroleum Act, shouldthe government determine that Thailand requires additional oil supply, concessionaires may berequired to supply petroleum of suitable quality for the purpose of having an adequate supply ofpetroleum for the demand in Thailand ... each concessionaire shall be required to supply suchpetroleum in the ratio that his petroleum production bears to total petroleum production in Thailand asshown in the last six months. Where it is deemed a matter of national security, the government cantemporarily prohibit the export of all or part of petroleum produced.


0

200

400

600

800

1000

1200

1400

Chevron

PTTE

P

Mitsui&C

o

Total

CoastalEnergy

MubadalaDevelopme

nt

Co

B

G

HessCorporation

METI(Japa

n)

SalamanderEnergy

PrivateInvesto

rs

KrisEnergy

TatexThailand

HongKong&ChinaGas

ExxonMo

bil

CarnarvonPetroleu

m

TapOil

GovernmentofThailand

Sophonpanich

JXNipponOil&Energy

Corp

R

emainingreserves(mmboe) Oil and Gas Reserves in Thailand by Company, 2012A



Thailands upstream industry is dominated by two operatorsChevron and state company PTTEP.They manage the largest gas, oil and condensate projects in the country, and are the leading playersin terms of both reserves and production. Chevron holds total remaining reserves of 1,156 mmboe, andregistered an average WI production from 2007A-2012A of 248,000 boe/d, while PTTEP has remaining

reserves of 1,047 mmboe, and produced 202,000 boe/d on an average WI basis between 2007A-2012A. Other notable players include MOECO, Total and BG, who predominately participate in non-operating roles. Hess Corporation operates the Sinphuhorm onshore gas project, while Mubadala,Salamander Energy and Coastal Energy all have small producing oil fields in the Gulf of Thailand.KrisEnergy has a non-operated position in Thailand, partnered with Chevron (operator) and PTTEP inthe producing B8/32 fields in the Pattani Basin, as well as a 25% non-operated position in MubadalaDevelopment Co.s G11/48 and G10/48 blocks. G11/48 is approaching Final Investment Decision(FID) and work towards development is ongoing at G10/48.

-

50

100

150

200

250

300

Chevron

PTTEP

Mitsui&Co

Total

BG

HessCorporation

METI(Japan)

Mubadala

DevelopmentCo

CoastalEnergy

PrivateInvestors

Sa

lamanderEnergy

ExxonMobil

Sophonpanich

P

anOrientEnergy

Carnarvon

Petroleum

ChoicePlus

Holdings

TatexThailand

KrisEnergy

DefenceEnergy

Dept

KunLunEnergy

CompanyA

verageWIProduction2007

A-2012A

('000boe/d)

Thailand Average WI Production 2007A-2012A


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Cambodia

Overview

The Cambodian upstream industry is still in its infancy compared to the majority of its South East Asianneighbours. The greatest potential is thought to exist in the disputed Overlapping Claims Area (OCA)

between Thailand and Cambodia, which could hold up to 11 tcf of gas and over a billion barrels ofliquids. However, exploration is on-hold pending resolution of the OCA issue.

Interest in Cambodias undisputed offshore waters slowly gained momentum following a series of oildiscoveries made by Chevron in Block A in 2004A and 2005A. Exploration acreage was acquired bycompanies such as PTTEP, Medco Energi, Lundin Petroleum and CNOOC. However, the wells drilledso far have mostly not been successful, and some of these PSCs have since been relinquished.

The countrys onshore acreage remains largely unexplored, due to a lack of available data andlogistical issues, such as poor infrastructure, access and unexploded war-time ordinance and land-mines.

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27

35

Cambodia Commercial and Technical Oil and Gas Reserves (mmboe), 2012A

Technical Liquids Technical Gas


Cambodia holds 62 mmboe of technical reserves. No commercial oil or gas reserves have beenproven in Cambodia to-date. The results of Chevrons recent appraisal drilling have not been releasedand Wood Mackenzie continues to categorize reserves in the Pimean Akas, Sirey Sambat, Pisnuka,Sovann Phum and Mealdey discoveries as non-commercial at the current time. Original oil in placereserves on the block were independently certified at 672 million boe in 2011A.

CNPA estimates, based on basin level analysis, suggest that Blocks A-F could cumulatively contain upto 3 tcf of gas and 400 million barrels of crude. These figures remain speculative and appraisal resultswill provide a more substantiated view of the potential in the offshore areas.


0

1

1

2

2

3

3

4

0

5

10

15

20

25

30

35

40

45

50

2003A 2004A 2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A

Numberofdiscoveries

T

otaldiscoveredvolume(mmboe)

Cambodia Recent Discoveries, 2003A-2012A


No discoveries have been made in Cambodia since 2004 and 2005, when Chevron made successfuloffshore finds in the Khmer basin totaling 62 mmboe (Wood Mackenzie technical reserves estimates).In the near-term, exploration activity is likely to remain predominantly in the offshore area. In recentyears, there has been little onshore activity due to the presence of concealed land mines, security risksand environmental concerns. This may change with a renewed interest in exploring Cambodiasonshore areas, particularly the Tonle Sap Basin. In addition, PetroVietnam planned to acquire 600 kmof 2D seismic over its onshore Block XV during late 2012A/early-2013F.

Cambodias offshore sector is likely to see the bulk of near-term exploration, with all the undisputedoffshore acreage now fully licensed. Drilling on the Mirach Energy-operated Block D is expected inmid-2013F.

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0

2

4

6

810

12

14

16

18

0

2

4

6

810

12

14

16

18

2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Oil(m

mboe)

Cambodia Oil Supply-Demand, 2005A-2018F



Oil/Liquids

There is currently no oil production in Cambodia. Chevrons Block A discoveries offer the best potentialfor near-to-medium term oil production (shown in the chart above, although this production iscontingent on the resolution of fiscal terms).

Gas

There is currently no gas production in Cambodia. Chevrons Mealdey discovery offers the bestpotential for near to medium-term gas production. Cambodia does not have a gas market yet, with noinfrastructure built to date.


The government of Cambodia with one calendar quarters notice has the right to require the contractorto sell its proportion of net petroleum output to the Ministry in order to meet internal demand in thecountry.


0

4

8

12

16

20

24

Chevron

MOECO

KrisEnergy

LG-CaltexOil

CNPA

Remainingreserves(mmboe) Oil and Gas Reserves in Cambodia by Company, 2012A



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There are currently 16 companies active in Cambodias non-disputed acreage. Wood Mackenziesestimates of technical reserves for Cambodia consist of the Block A discoveries; Chevron (operator)and MOECO share the highest portion of the technical reserves, at 17.7 mmboe each.

Vietnam

Overview

Vietnam has two core producing basins, the Cuu Long and Nam Con Son basins, both located off thecountrys south coast. The Cuu Long Basin, located nearer to the shore, contains the giant Bach Hooilfield, which is now in terminal decline, plus a number of other oilfields. Gas from nearbydevelopments is routed through the Bach Ho gas facilities and piped onshore to market. The Nam ConSon Basin is mostly gas prone, and is home to the Lan Tay/Lan Do project, which supplies around halfof Vietnams gas.

A number of new oil fields have been developed in recent years predominantly by smaller players.There are also two large gas developments expected onstream in the next five years: the Chevron-operated Block B project in the Malay Basin, and the PetroVietnam-operated Hai Thach/Moc Tinh in

the Nam Con Son Basin.

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As part of plans to develop the center of the country, the Dung Quat refinery was commissioned inearly-2010A. To secure long-term gas supplies, Vietnam is currently considering building a LNGregasification terminal in the south of the country.

In August 2011A, it was announced the country would hold its first licensing round since 2007A. Nineblocks were offered in the Nam Con Son, Cuu Long and Malay basins, with bids to be submitted byJanuary 2012A. Interest in the gazetted blocks was disappointing, with only a handful of blocksawarded. However, there has been a healthy number of adhoc awards in the past few years.


1,055

764

1,320

1,633

Vietnam Commercial and Technical Oil and Gas Reserves (mmboe), 2012A

Commercial Liquids Technical Liquids Commercial Gas Technical GasSource: Wood MackenzieSource: Wood Mackenzie

Vietnam holds about 4,772 mmboe of total remaining reserves, with 62% of this being gas reserves, or,if taken on a commercial basis, 56%. Due to low gas prices and a lack of infrastructure, a large portionof Vietnams gas reserves has remained undeveloped.

The majority of oil reserves have been discovered in the Cuu Long Basin. The basin is generally oil-prone, with some associated gas. Bach Ho, the first and largest oil and gas producing field in the basin,has been in production since 1986A. The Rang Dong, Su Tu Den and Ruby fields, with total 2Preserves of over 500 million barrels of oil, are some of the key fields that have come onstream in thelast 10 years. Recent discoveries such as the Te Giac Trang in Block 16-1, and Su Tu Trang in Block15-1, are expected to offset the production decline from Bach Ho.

The majority of Vietnams non-associated gas reserves can be found in the Nam Con Son Basin.Arguably the countrys most significant offshore gas finds to date are the TNK-BP-operated Lan Tay/Lan Do fields in Block 06-1. Recoverable gas reserves from the block are estimated to be in the regionof 2.15 tcf (plus additional technical reserves). Significant gas discoveries have also been made in theKNOC-operated Block 11-2 and Blocks 5-2 and 5-3, which were relinquished by BP in early-2009. Witha growing gas market in south Vietnam, Wood Mackenzie expects other gas reserves in the basin tobe developed in the near to medium term. The Nam Con Son Basin also has oil potential, as proved byPremier Oils Chim Sao, Dua and Ca Rong Do discoveries. Chim Sao was brought onstream inOctober 2011A, and Dua is expected to start production in 2014F.

The Malay Basin can broadly be divided into the southern oil and associated gas fields and thenorthern fields which are generally gas prone. Chevron has made several large discoveries in thebasin including the Kim Long, Ca Voi and Ac Quy fields. The reserve potential of these fields isestimated at around 4 tcf, and first commercial gas sales are expected in 2017F at the earliest.Talismans Cai Nuoc field in Block 46, and its Song Doc oil field in Block 46/02 are the only twoproducing fields in the basin.

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0

200

400

600

800

1000

1200

1400

1600

1800

2000

Liquids Gas

TotalYet-to-Find(m

mboe)

Vietnam Yet-to-Find Commercial and Technical Reserve Volumes


In terms of prospectivity, Wood Mackenzie estimates total YTF potential in Vietnam to be 2,425mmboe of liquids and gas. The Nam Con Son Basin is thought to have some oil upside, whiledeepwater exploration in the Song Hong and Phu Khanh Basin may prove up new plays. Taking a lookback in the last 10 years, Vietnam has had 49 field discoveries, with 2,696 mmboe discovered in total,or an average 55 mmboe of reserves per discovery since 2003A.

Not included in the above chart is the CBM potential in the Red River Delta basin, which has a highdegree of uncertainty around its estimates. A number of studies on the basin estimate the GIIP torange between 6 to 14 tcf. Wood Mackenzie estimates Red River resource potential at 6.6 tcf.

0

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4

6

8

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12

0

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2003A 2004A 2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A

Numberofdiscoveries


Vietnam Recent Discoveries, 2003A-2012A


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Production started from the Su Tu Den field in 2003A, and peak daily production of around 79,000 b/dwas achieved in 2004A. However, field output declined fairly rapidly soon after. New oil productionbegan from the Song Doc, Phuong Dong, Ca Ngu Vang and Su Tu Vang fields during the latter half of2008A, leading to an increase in liquids production in 2009A. Nonetheless the impact of these newfields has been muted by the accelerated decline of the mature Rang Dong field and poorer thanexpected performance from Su Tu Vang.

0

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100

150

200

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0

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250

2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Oil(mmboe)

Vietnam Oil Supply-Demand, 2005A-2018F



Vietnams gas production has risen since 1995A, when the Bach Ho field began supply to the Ba Riapower plant. Rates increased further in 2002 following the construction of the 399 kilometre Nam ConSon pipeline from the Lan Tay field to Dinh Co. The spare capacity of this line has allowed for nearbygas fields to be developed and tied-in. A second Nam Con Son pipeline has been approved, and isscheduled to be completed around mid-2015F. Wood Mackenzie expects that the Hai Thach/Moc Tinh

project will utilize the pipeline after an initial period of around 18 months and anticipates the project willsupply into the existing Nam Con Son Pipeline.

0

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40

50

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80

2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Gas(mmboe)

Vietnam Gas Supply-Demand, 2005A-2018F




Liquids Pricing

Liquids price is generally at a premium to that of Brent on the world market. All crude sold to thirdparties is valued at the net realised price, at the point of delivery received by contractor.

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Natural Gas Pricing

The gas price used for fiscal purposes is the realised sales price. Gas from the Block 46 (Cai Nuoc)PSC and the PM3 CAA area, a portion of which is currently supplied to Vietnam, is sold at a pricewhich is linked to the price of Medium Sulphur Fuel Oil in Singapore. Other gas currently sold todomestic users in Vietnam is not linked to any index.


Gas prices in Vietnam have historically been very low, which has hampered development of gas fields.However, there are signs prices are rising, and this has prompted Chevrons much-delayed gas project(Kim Long, Ac Quy, and Ca Voi fields, together estimated at 3.8 tcf of gas) in the Malay Basin toprogress, although Chevron and PetroVietnam are yet to agree a final, enhanced gas price for theproject.

Recently, however, PV Gas has been increasing the price of gas sold to industries and fertiliser plants. Gasis sold to their subsidiary, PetroVietnam Low Pressure Gas Distribution company (PGD) which thendistributes gas to industries via its onshore pipeline network. Gas sold to PGD has risen fromUS$8.35/mmbtu to US$10.55/mmbtu.

Similarly, gas prices to fertiliser plants in Phu My and Ca Mau has increased by 40% from US$4.59/mmbtu to US$6.43/mmbtu. However, gas sold to the power sector has not seen the same levelsof increase. As the power sector still consists of 80% of the total market, pricing reform in this sectorwill be needed to attract upstream investments.

Moves to increase gas prices for the industry and fertiliser sector may filter upwards, allowing PV Gasto contract gas supplies at higher prices that will allow operators to pursue higher cost developments.

While there is no domestic market obligation for oil, an oil export duty was introduced in the post-September 1993 PSC terms on any of the contractors profit oil and cost recovery oil exported. This iscurrently 4%. For PSCs signed after 2009, Wood Mackenzie understands an export duty of 10%applies.


0

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PetroVietnam

Chevro

n

PetronasCariga

li

Gazprom

ExxonMob

il

Zarubezhne

ft

PTTEP

Perenc

o

KNOC

SOCOInternational

Mitsui&C

o

ONGC

JXNipponOil&Energ

y

Corp S

KEnerg

y

Idemits

u

Premie

r

Talisma

n

INPEXCorporatio

n

AAR

BP

Remainingreserves(mmboe) Oil and Gas Reserves in Vietnam by Company, 2012A



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State oil company PetroVietnam is the dominant player in the country, having stakes in all projects.Chevron is the leading International Oil Company in terms of reserves volume through its gas project inthe Malay Basin. Petronas Carigali has a sizeable technical reserves portfolio across the country, whilePerenco has a large volume of technical reserves in the Cuu Long Basin. Production-wise,PetroVietnam has the highest average working interest production from 2007A-2012 of 162,000 boe/d.

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180

PetroVietnam

Zarubezhneft

ONGC

ConocoPhillips

BP

KNOC

PETRONAS

JXNipponOil&

Ene

rgyCorp

SKEnergy

SOCOIn

ternational

PTTEP

AAR

LG

Perenco

Premier

Talisman

Geopetrol

Daesung

Santos

Hyundai

AverageWIProduction2007A-201

2A

('000boe/d)

Vietnam Average WI Production 2007A-2012A


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Bangladesh

Overview

BANGLADESH

INDIA

MYANMAR

Tripur

a

Ganges

Bha

girathi

Kolkata

DHAKA

Jamuna

Padma

Bay of Bengal

INDIA

Active PSC - Onshore

16Santos

Shahbazpur

Block 9Tullow/Niko

Block 11

Bapex

Active PSC - Offshore

Block 5

Open

Block 12

Moulavi BazarChevron

ChattakNiko

Petrobangla

Petrobangla

Semutang

Petrobangla

Open

SS-02

On OfferSS-03

On Offer SS-09On Offer

SS-06

On Offer

SS-07

On Offer

SS-08

On Offer

Begumganj

SS-04

Titas

Petrobangla

SS-10

DS-08-10 DS-08-11

On Offer

FeniPetrobangla

Petrobangla

Niko

Khulna

KailastilaChevron

Kutubdia

ConocoPhillips Conoco-Phillips

Shwe Phyu

SHWE

Dhirubhai 20

Dhirubhai 11

Dhirubhai40 India

Claim

BangladeshClaim

On Offer

SS-11On Offer

Block 7

Open

Block 6BOpen

Block 6AOpen

Block 4B

Open

Block 4A

Open

Block 3AOpen

Block 2A

OpenBlock 2B

Open

Block 8

Netrakona Block 13

Open

Block 14

Open

Patharia

Bapex

Block 10Open

Block 1Open

Blocks on offerDS-12

On Offer

Block 3B

Open

Block 22A

Open

Block 22BOpen

Sitap

ah

ar

Patiya

Jaldi

Sita

kun

d

BibiyanaChevron

Kasalong

Bapex

SS-01Open

DS-16

On Offer

MYANMAR

Bapex

Bapex

SundalpurPetrobangla

92E

92E

90E

90E

88E

88E

25N

25N

23N

23N

21N

21N

0 80 16040km


Bangladeshs hydrocarbon industry is dominated by natural gas, which provides its main source ofenergy. However, in recent years, demand for gas has grown faster than supply, leaving the countryfacing gas shortages. The state oil and gas company, Petrobangla, is the dominant producer in thecountry, but funding issues have constrained its ability to develop further reserves in the near term.

Chevron is the main international player in Bangladesh, operating the Bibiyana, Jalalabad and MoulaviBazar fields, which provide almost 50% of the countrys gas production. The Bibiyana field is expectedto produce over 1 bcfd of gas, once constraints have been removed from the national transmissionsystem. To alleviate this problem, the first of three planned compressor stations was commissioned atMuchai in May 2012.

In mid-2011, Petrobangla signed a contract with ConocoPhillips to explore two deepwater blocks awardedto the company during the 2008 licensing round. Bangladeshs offshore areas are largely untested and ifsuccessful, this would present another avenue to meet the supply shortages. The resolution of the maritimeboundary dispute with Myanmar in March 2012 now allows ConocoPhillips to carry out exploration activity

on the entire area of block DS-08-11.

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30

1,643

754

Bangladesh Commercial and Technical Oil and Gas Reserves (mmboe), 2012A



Wood Mackenzie estimates 2,426 mmboe of remaining commercial and technical oil and gas reservesin Bangladesh. Reserves are dominated by gas, with commercial and technical gas reservesamounting to almost 99% of Bangladeshs total reserves. The majority of the technical gas reservesare likely to be made commercial at some stage in the future but their development remains hamperedeither by lack of Petrobangla funding or development approval. Bangladeshs liquids reserves wereboosted by the discovery of the Bibiyana gas/condensate field in 1998A, where it is estimated that totalremaining commercial liquid reserves are around 16 million barrels.


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TotalYet-to-Find(mmboe)

Bangladesh Yet-to-Find Commercial and Technical Reserve Volumes


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Total YTF in Bangladesh is estimated at 635 mmboe, of which 100% is gas. In the last 10 years, 7fields have been discovered, with combined volumes of 152 mmboe. The fields are all in the Tripura-Cachar-Bengal basin, with the biggest two, Bangora and Lalmai, both discovered by Tullow in 2004A.

0

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2

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2003A 2004A 2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A

Numberofdiscoveries

Totaldiscoveredvolume(mmb

oe)

Bangladesh Recent Discoveries, 2003A-2012A



Oil

Oil production in Bangladesh occurred between 1987A and 1994A, when the Sylhet (Haripur) fieldproduced an average of 200 b/d of waxy, low sulphur, 28API oil from the Sylhet-7 well. The pipelinefrom Sylhet-7 waxed up and production ceased in July 1994, with the field having produced 550,000barrels of oil. It is understood that there are no plans to bring Sylhet-7 back onstream.

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2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Oil(mmboe)

Bangladesh Oil Supply-Demand, 2005F-2018F



Gas

Gas production in Bangladesh started in 1960A when the Chattak field was brought onstream and hasbeen steadily rising. Until 1998, Petrobangla had retained exclusive responsibility for all hydrocarbonproduction in Bangladesh, operating 15 gas fields via its two subsidiaries, Sylhet Gas Fields Limited(SGFL) and Bangladesh Gas Fields Company Limited (BGFCL). Petrobanglas monopoly ended whenCairn brought the Sangu field onstream in June 1998A.

Feni and Fenchuganj began production in 2004A. Feni previously produced gas under Petrobangla

operatorship but was shut-in during 1998A. Niko took over in 2003A and began production from thefield in November 2004A, at a rate of 20 mmcfd. BAPEX brought the Fenchuganj field onstream in May2004A, at a rate of just under 25 mmcfd.

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In April 2005A, Chevron brought the Moulavi Bazar field onstream at a rate of around 70 mmcfd.Production was ramped up to 110 mmcfd in July 2005A. Following the commissioning of the Bibiyanafield in March 2007A, production from Moulavi Bazar was reduced on account of compressionconstraints. In 2012A, production from the Bibiyana field averaged 800 mmcfd, and output is expectedto peak in 2015F.

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2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013F 2014F 2015F 2016F 2017F 2018F

Gas

(mmboe)

Bangladesh Gas Supply-Demand, 2005F-2018F




Liquids Pricing

The value of oil/condensate from each production area is determined on the basis of market valuecomparable to APPI. The price of locally produced LPG is linked to the international price of keroseneon a BTU basis.

Natural Gas Pricing

For the upstream companies, there is no fixed gas purchase price. In the 1990s, Cairn and Occidentalwere involved in protracted negotiations over the price that Petrobangla would pay. Under the 1993Petroleum Policy, the pricing for associated gas is on a cost plus basis. For non-associated onshoregas, the price is indexed to 75% of the price of HSFO 180 CST freeonboard (f.o.b.) Singapore, lessnegotiated discounts. Offshore gas pricing is 25% higher than for onshore, equivalent to 93.75%HSFO, again less negotiated discounts.

Floor and ceiling prices for HSFO, negotiable by PSC, are applied to ensure price competitiveness ofdomestic gas. Under the 1997 Model PSC, the floor and ceiling prices for HSFO were set atUS$70/tonne and US$120/tonne respectively (equivalent to around US$1.31/mcf and US$2.25/mcfonshore and around US$1.73/mcf and US$2.97/mcf offshore, with the above linkage indexconsidered).

Under the 2008 Model PSC, offshore gas pricing for Type-A blocks was unchanged from the 1997Model PSC. However, the price for Type-B blocks was indexed to 100% of HSFO.

In 2009, Cairn announced that it has been given the rights to freely market gas from its Block 16 (non-Sangu areas) with the buyers.

The price for each calendar quarter is calculated based on the arithmetic average of the daily APPIprice quotations, for the six months ending on the last day of the s

KrisEnergy Ltd - Appendices a to C

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